Continental Resources Inc (CLR) 10-K14 Feb 222021 FY Annual reportFinancial data

Company Profile

Document and Entity Information

Document and Entity Information Document - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2021	Jan. 31, 2022	Jun. 30, 2021
Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
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	2021
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
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 2.5
Entity Common Stock, Shares Outstanding		364,298,349
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

Audit Information

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2021
Auditor [Line Items]
Auditor Firm ID	248
Auditor Name	GRANT THORNTON LLP
Auditor Location	Oklahoma City, Oklahoma

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Current assets:
Cash and cash equivalents	$ 20,868	$ 47,470
Crude oil and natural gas sales	1,122,415	561,127
Joint interest and other	278,753	143,829
Allowance for credit losses	(2,814)	(2,462)
Receivables, net	1,398,354	702,494
Derivative assets	22,334	15,303
Inventories	105,568	72,157
Prepaid expenses and other	17,266	15,121
Total current assets	1,564,390	852,545
Net property and equipment, based on successful efforts method of accounting	16,975,465	13,737,292
Derivative assets, noncurrent	13,188	0
Operating lease right-of-use assets	16,370	8,557
Other noncurrent assets	21,698	34,704
Total assets	18,591,111	14,633,098
Current liabilities:
Accounts payable trade	582,317	361,704
Revenues and royalties payable	627,171	327,029
Accrued liabilities and other	285,740	167,013
Derivative liabilities	899	227
Current portion of operating lease liabilities	1,674	2,588
Current portion of long-term debt	2,326	2,245
Total current liabilities	1,500,127	860,806
Long-term debt, net of current portion	6,826,566	5,530,173
Other noncurrent liabilities:
Deferred income tax liabilities, net	2,139,884	1,620,154
Asset retirement obligations, net of current portion	215,701	177,194
Derivative liabilities, noncurrent	318	1,584
Operating lease liabilities, net of current portion	13,800	5,839
Other noncurrent liabilities	38,390	14,623
Total other noncurrent liabilities	2,408,093	1,819,394
Commitments and contingencies (Note 13)
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; 364,297,520 shares issued and outstanding at December 31, 2021; 365,220,435 shares issued and outstanding at December 31, 2020	3,643	3,652
Additional paid-in capital	1,131,602	1,205,148
Retained earnings	6,340,211	4,847,646
Total shareholders’ equity attributable to Continental Resources	7,475,456	6,056,446
Noncontrolling interests	380,869	366,279
Total equity	7,856,325	6,422,725
Total liabilities and equity	$ 18,591,111	$ 14,633,098

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2021	Dec. 31, 2020
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	364,297,520	365,220,435
Common stock, outstanding	364,297,520	365,220,435

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenues:
Crude oil and natural gas sales	$ 5,793,741	$ 2,555,434	$ 4,514,389
Gain (loss) on derivative instruments, net	(128,864)	(14,658)	49,083
Crude oil and natural gas service operations	54,441	45,694	68,475
Total revenues	5,719,318	2,586,470	4,631,947
Operating costs and expenses:
Production expenses	406,906	359,267	444,649
Production taxes	404,362	192,718	357,988
Transportation expenses	224,989	196,692	225,649
Exploration expenses	21,047	17,732	14,667
Crude oil and natural gas service operations	21,480	18,294	33,230
Depreciation, depletion, amortization and accretion	1,898,082	1,880,959	2,017,383
Property impairments	38,370	277,941	86,202
Acquisition costs	13,920	0	0
General and administrative expenses	233,628	196,572	195,302
Net (gain) loss on sale of assets and other	(5,146)	187	(535)
Total operating costs and expenses	3,257,638	3,140,362	3,374,535
Income (loss) from operations	2,461,680	(553,892)	1,257,412
Other income (expense):
Interest expense	(251,598)	(258,240)	(269,379)
Gain (loss) on extinguishment of debt	(290)	35,719	(4,584)
Other	(23,654)	1,662	3,713
Total other income (expense)	(275,542)	(220,859)	(270,250)
Income (loss) before income taxes	2,186,138	(774,751)	987,162
(Provision) benefit for income taxes	(519,730)	169,190	(212,689)
Net income (loss)	1,666,408	(605,561)	774,473
Net income (loss) attributable to noncontrolling interests	5,440	(8,692)	(1,168)
Net income (loss) attributable to Continental Resources	$ 1,660,968	$ (596,869)	$ 775,641
Basic net income (loss) per share (in dollars per share)	$ 4.61	$ (1.65)	$ 2.09
Diluted net income (loss) per share (in dollars per share)	$ 4.56	$ (1.65)	$ 2.08
Foreign currency translation adjustments	$ 0	$ 0	$ 140
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Reclassification Adjustment from AOCI, Realized upon Sale or Liquidation, Net of Tax	0	0	(555)
Other Comprehensive Income (Loss), Net of Tax	0	0	(415)
Comprehensive Income (Loss), Net of Tax, Consolidated	1,666,408	(605,561)	774,058
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	5,440	(8,692)	(1,168)
Comprehensive Income (Loss), Net of Tax, Attributable to Continental Resources	$ 1,660,968	$ (596,869)	$ 775,226

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							$ 276,728
Total equity	$ 6,421,861
Balance at Dec. 31, 2018		$ 3,760	$ 1,434,823	$ 415	$ 4,706,135	$ 6,145,133
Balance, shares at Dec. 31, 2018		376,021,575
Increase (Decrease) in Equity [Roll Forward]
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	(190,239)	$ (56)	(190,183)					(190,239)
Other Comprehensive Income (Loss), Net of Tax	(415)			(415)		(415)
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		$ 3,711	1,274,732	0	5,463,224	6,741,667
Balance, shares at Dec. 31, 2019		371,074,036
Balance at Dec. 31, 2018		$ 3,760	1,434,823	415	4,706,135	6,145,133
Balance, shares at Dec. 31, 2018		376,021,575
Increase (Decrease) in Equity [Roll Forward]
Treasury Stock, Retired, Cost Method, Amount	$ (441,069)
Restricted stock:
Repurchased and canceled, shares	(16,967,228)
Balance at Dec. 31, 2021	$ 7,475,456	$ 3,643	1,131,602	0	6,340,211	7,475,456
Balance, shares at Dec. 31, 2021	364,297,520	364,297,520
Increase (Decrease) in Equity [Roll Forward]
Noncontrolling interests							366,684
Total equity	$ 7,108,351
Balance at Dec. 31, 2019		$ 3,711	1,274,732	0	5,463,224	6,741,667
Balance, shares at Dec. 31, 2019		371,074,036
Increase (Decrease) in Equity [Roll Forward]
Net income (loss) attributable to Continental Resources	(596,869)				(596,869)	(596,869)
Net income (loss) attributable to noncontrolling interests	(8,692)						(8,692)
Net income (loss)	(605,561)
Dividends, Common Stock, Cash	(18,580)				(18,580)	(18,580)
Change in dividends payable	8				8	8
Adoption of ASU 2016-13	(137)				(137)	(137)
Treasury Stock, Value, Acquired, Cost Method	(126,906)					(126,906)		(126,906)
Treasury Stock, Shares, Retired		(8,122,104)
Treasury Stock, Retired, Cost Method, Amount	(126,906)	$ (81)	(126,825)					(126,906)
Other Comprehensive Income (Loss), Net of Tax	0
Stock-based compensation	64,585		64,585			64,585
Contributions from noncontrolling interests	21,557						21,557
Distributions to noncontrolling interests	(13,270)						(13,270)
Restricted stock:
Issued	27	$ 27	0			27
Issued, shares		2,738,625
Repurchased and canceled	$ (7,347)	$ (3)	(7,344)			(7,347)
Repurchased and canceled, shares	(8,122,104)	(306,845)
Forfeited	$ (2)	$ (2)				(2)
Forfeited, shares		(163,277)
Balance at Dec. 31, 2020	$ 6,056,446	$ 3,652	1,205,148	0	4,847,646	6,056,446
Balance, shares at Dec. 31, 2020	365,220,435	365,220,435
Increase (Decrease) in Equity [Roll Forward]
Noncontrolling interests	$ 366,279						366,279
Total equity	6,422,725
Net income (loss) attributable to Continental Resources	1,660,968				1,660,968	1,660,968
Net income (loss) attributable to noncontrolling interests	5,440						5,440
Net income (loss)	1,666,408
Dividends, Common Stock, Cash	(168,536)				(168,536)	(168,536)
Change in dividends payable	133				133	133
Treasury Stock, Value, Acquired, Cost Method	(123,924)					(123,924)		(123,924)
Treasury Stock, Shares, Retired		(3,198,571)
Treasury Stock, Retired, Cost Method, Amount	(123,924)	$ (32)	(123,892)					$ (123,924)
Other Comprehensive Income (Loss), Net of Tax	0
Stock-based compensation	63,145		63,145			63,145
Contributions from noncontrolling interests	33,086						33,086
Distributions to noncontrolling interests	(23,936)						(23,936)
Restricted stock:
Issued	31	$ 31	0			31
Issued, shares		3,050,491
Repurchased and canceled	$ (12,804)	$ (5)	(12,799)			(12,804)
Repurchased and canceled, shares	(3,198,571)	(478,697)
Forfeited	$ (3)	$ (3)				(3)
Forfeited, shares		(296,138)
Balance at Dec. 31, 2021	$ 7,475,456	$ 3,643	$ 1,131,602	$ 0	$ 6,340,211	$ 7,475,456
Balance, shares at Dec. 31, 2021	364,297,520	364,297,520
Increase (Decrease) in Equity [Roll Forward]
Noncontrolling interests	$ 380,869						$ 380,869
Total equity	$ 7,856,325

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Net income (loss)	$ 1,666,408	$ (605,561)	$ 774,473
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion, amortization and accretion	1,893,106	1,882,458	2,019,704
Property impairments	38,370	277,941	86,202
Non-cash (gain) loss on derivatives, net	(20,814)	(13,492)	15,612
Stock-based compensation	63,173	64,613	52,044
Provision (benefit) for deferred income taxes	519,730	(166,971)	212,689
Net (gain) loss on sale of assets and other	(5,146)	187	(535)
(Gain) loss on extinguishment of debt	290	(35,719)	4,584
Other, net	35,614	16,970	10,408
Changes in assets and liabilities:
Accounts receivable	(694,981)	332,128	(33,619)
Inventories	(33,411)	12,859	(21,204)
Other current assets	(2,144)	1,471	(4,459)
Accounts payable trade	106,367	(133,977)	(36,359)
Revenues and royalties payable	298,552	(143,260)	69,195
Accrued liabilities and other	109,540	(66,071)	(36,467)
Other noncurrent assets and liabilities	(803)	(1,272)	3,420
Net cash provided by operating activities	3,973,851	1,422,304	3,115,688
Cash flows from investing activities:
Exploration and development	(2,382,413)	(1,408,149)	(2,783,149)
Purchase of producing crude oil and natural gas properties	(2,548,575)	(81,994)	(51,558)
Purchase of other property and equipment	(66,598)	(23,994)	(25,983)
Proceeds from sale of assets	8,041	2,779	88,734
Net cash used in investing activities	(4,989,545)	(1,511,358)	(2,771,956)
Cash flows from financing activities:
Credit facility borrowings	1,663,000	2,052,000	1,216,000
Repayment of credit facility	(1,323,000)	(1,947,000)	(1,161,000)
Proceeds from issuance of Senior Notes	1,587,776	1,485,000	0
Redemption and repurchase of Senior Notes	(630,782)	(1,343,250)	(500,000)
Premium and costs on redemption of Senior Notes	0	(25,173)	(4,167)
Proceeds from other debt	0	26,000	0
Repayment of other debt	(2,243)	(6,679)	(2,352)
Debt issuance costs	(12,082)	(4,368)	0
Contributions from noncontrolling interests	31,493	27,116	109,137
Distributions to noncontrolling interests	(22,447)	(13,809)	(14,164)
Repurchase of common stock	(123,924)	(126,906)	(190,239)
Repurchase of restricted stock for tax withholdings	(12,804)	(7,347)	(21,943)
Dividends paid on common stock	(165,895)	(18,460)	(18,380)
Net cash provided by (used in) financing activities	989,092	97,124	(587,108)
Effect of exchange rate on cash and cash equivalents	0	0	27
Net change in cash and cash equivalents	(26,602)	8,070	(243,349)
Cash and cash equivalents at beginning of period	47,470	39,400	282,749
Cash and cash equivalents at end of period	$ 20,868	$ 47,470	$ 39,400

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
Supplemental Cash Flow Information	Dec. 31, 2021
Supplemental Cash Flow Elements [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 2021 2020 2019 Supplemental cash flow information: Cash paid for interest $ 214,727 $ 256,633 $ 267,421 Cash paid for income taxes 3 4 229 Cash received for income tax refunds (1) 58 9,600 107 Non-cash investing activities: Asset retirement obligation additions and revisions, net 31,060 17,791 6,630 (1) Amount received in 2020 primarily represents alternative minimum tax refunds. As of December 31, 2021 and 2020, the Company had $242.9 million and $128.8 million, respectively, of accrued capital expenditures included in “Net property and equipment” with an offsetting amount in “Accounts payable trade” in the consolidated balance sheets. As of December 31, 2021 and 2020, the Company had $1.7 million and $0.1 million, respectively, of accrued contributions from noncontrolling interests included in "Receivables – Joint interest and other" with an offsetting amount in "Equity – Noncontrolling interests" in the condensed consolidated balance sheets. As of December 31, 2021 and 2020, the Company had $2.5 million and $1.0 million, respectively, of accrued distributions to noncontrolling interests included in "Revenues and royalties payable" with an offsetting amount in "Equity – Noncontrolling interests" in the condensed consolidated balance sheets. As of December 31, 2021, the Company recognized approximately $21.4 million of asset retirement obligations and $10.0 million of right-of-use assets and corresponding lease liabilities associated with the 2021 property acquisitions discussed in Note 2. Property Acquisitions and Dispositions .

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information	12 Months Ended
Supplemental Cash Flow Information	Dec. 31, 2021
Supplemental Cash Flow Elements [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 2021 2020 2019 Supplemental cash flow information: Cash paid for interest $ 214,727 $ 256,633 $ 267,421 Cash paid for income taxes 3 4 229 Cash received for income tax refunds (1) 58 9,600 107 Non-cash investing activities: Asset retirement obligation additions and revisions, net 31,060 17,791 6,630

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information - Summary - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Supplemental Cash Flow Elements [Abstract]
Cash paid for interest	$ 214,727	$ 256,633	$ 267,421
Cash paid for income taxes	3	4	229
Cash received for income tax refunds (1)	58	9,600	107
Noncash Investing and Financing Items [Abstract]
Asset retirement obligation additions and revisions, net	31,060	17,791	$ 6,630
Accrued capital expenditures	242,900	128,800
Accrued contributions from noncontrolling interests	1,700	100
Accrued distributions to noncontrolling interests	2,500	$ 1,000
Asset retirement obligation recognized in conjunction with property acquisitions	21,400
Right-of-use assets and corresponding lease liabilities recognized in conjunction with property acquisitions	$ 10,000

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
Organization and Summary of Significant Accounting Policies	Dec. 31, 2021
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, management, 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. In 2021 the Company executed strategic acquisitions to expand its operations into the Permian Basin of Texas and the Powder River Basin of Wyoming. See Note 2. Property Acquisitions and Dispositions for additional information on the acquisitions. The Company's North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, Powder River Basin, and the Red River units. The South region includes all properties south of Nebraska and west of the Mississippi River and includes the SCOOP and STACK areas of Oklahoma and the Permian Basin of Texas. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations. For financial reporting purposes, the Company has one reportable segment due to the similar nature of its business, which is the exploration, development, and production of crude oil and natural gas in the United States. 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 (loss) 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, 2021, the Company had cash deposits in excess of federally insured amounts of approximately $19.4 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 writes off specific receivables when they become noncollectable and any payments subsequently received on those receivables are credited to the allowance for credit losses. Write-offs of noncollectable receivables have historically not been material. The Company’s allowance for credit losses totaled $2.8 million and $2.5 million as of December 31, 2021 and 2020, respectively. See Note 10. Allowance for Credit Losses for additional information. 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, 2021, sales to the Company’s largest purchaser accounted for approximately 10% 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 2021. 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, 2021 and 2020 consisted of the following: December 31, In thousands 2021 2020 Tubular goods and equipment $ 12,506 $ 13,671 Crude oil 93,062 58,486 Total $ 105,568 $ 72,157 In the first quarter of 2020 the Company recognized a $24.5 million impairment to reduce its crude oil inventory to estimated net realizable value at the time of impairment. The impairment is included in the caption “Property impairments” in the consolidated statements of comprehensive income (loss) for the year ended December 31, 2020. 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 and repairs 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 Automobiles and aircraft 5-10 Machinery and equipment 6-20 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, 2019 through December 31, 2021: In thousands 2021 2020 2019 Asset retirement obligations at January 1 $ 179,676 $ 153,673 $ 141,360 Accretion expense 11,125 9,393 8,443 Revisions (1) (1,291) 10,743 (1,762) Plus: Additions for new assets (2) 32,351 7,048 8,392 Less: Plugging costs and sold assets (2,037) (1,181) (2,760) Total asset retirement obligations at December 31 $ 219,824 $ 179,676 $ 153,673 Less: Current portion of asset retirement obligations at December 31 (3) 4,123 2,482 1,899 Non-current portion of asset retirement obligations at December 31 $ 215,701 $ 177,194 $ 151,774 (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 for 2021 includes $21.4 million of asset retirement obligations recognized in conjunction with the 2021 property acquisitions discussed in Note 2. Property Acquisitions and Dispositions . (3) Balance is included in the caption “Accrued liabilities and other” in the consolidated balance sheets. As of December 31, 2021 and 2020, net property and equipment on the consolidated balance sheets included $72.8 million and $56.1 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 notes 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 $60.6 million and $45.8 million (net of accumulated amortization of $36.9 million and $30.5 million) relating to its long-term debt at December 31, 2021 and 2020, respectively. The increase in 2021 resulted from the capitalization of costs incurred in connection with the amendment of the Company’s credit facility and the issuance of new senior notes as discussed in Note 8. Long-Term Debt . Unamortized capitalized costs associated with the Company’s Notes and note payable totaled $50.9 million and $42.5 million at December 31, 2021 and 2020, 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 $9.7 million and $3.3 million at December 31, 2021 and 2020, respectively, and are reflected in “Other noncurrent assets” on the consolidated balance sheets. For the years ended December 31, 2021, 2020 and 2019, the Company recognized amortization expense associated with capitalized debt issuance costs of $7.2 million, $7.8 million and $8.3 million, respectively, which are reflected in “Interest expense” on the consolidated statements of comprehensive income (loss). Derivative instruments The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value with such amounts classified as current or long-term based on contractual settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income (loss) under the caption “Gain (loss) on derivative instruments, net.” See Note 6. Derivative Instruments for additional information. 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 7. 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, 2021 and 2020. Income taxes Income taxes are accounted for using the asset and 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. The Company establishes a valuation allowance if it believes it is more likely than not that some or all of its deferred tax assets will not be realized. Significant judgment is applied in evaluating the need for and the magnitude of appropriate valuation allowances against deferred tax assets. See Note 11. Income Taxes for additional information. Earnings per share attributable to Continental Resources Basic net income (loss) per share is computed by dividing net income (loss) attributable to the Company by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share attributable to the Company for the years ended December 31, 2021, 2020 and 2019. Year ended December 31, In thousands, except per share data 2021 2020 2019 Net income (loss) attributable to Continental Resources (numerator) $ 1,660,968 $ (596,869) $ 775,641 Weighted average shares (denominator): Weighted average shares - basic 360,434 361,538 370,699 Non-vested restricted stock (1) 4,019 — 1,839 Weighted average shares - diluted 364,453 361,538 372,538 Net income (loss) per share attributable to Continental Resources: Basic $ 4.61 $ (1.65) $ 2.09 Diluted $ 4.56 $ (1.65) $ 2.08 (1) For the year ended December 31, 2020, the Company had a net loss and therefore the potential dilutive effect of approximately 934,000 weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computation. Foreign currency translation In 2014, the Company initiated operations in Canada through a wholly-owned Canadian subsidiary. The Company’s operations in Canada were immaterial and were sold in the fourth quarter of 2019. See Note 11. Income Taxes and Note 2. Property Acquisitions and 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 (loss), net of tax” in the consolidated statements of comprehensive income (loss). Adoption of new accounting pronouncement On January 1, 2021 the Company adopted ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. This standard eliminated 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 clarified certain aspects of the existing guidance, among other things. The Company adopted the standard on a prospective basis, which did not have a material impact on its financial position, results of operations, or cash flows.

Property Acquisitions and Dispo

Property Acquisitions and Dispositions	12 Months Ended
Property Acquisitions and Dispositions	Dec. 31, 2021
Business Combination and Asset Acquisition [Abstract]
Property Acquisitions and Dispositions	Property Acquisitions and Dispositions 2021 Permian Basin Acquisition On December 21, 2021, the Company acquired oil and gas assets and properties from certain subsidiaries of Pioneer Natural Resources Company pursuant to a purchase and sale agreement in which the Company purchased: (a) 100% of the issued and outstanding limited liability company interests of Jagged Peak Energy LLC, which in turn owns 100% of the issued and outstanding limited liability company interests of Parsley SoDe Water LLC; and (b) certain oil and gas assets and properties in the Permian Basin of Texas (collectively, the “Pioneer Acquisition”). The properties included approximately 92,000 net leasehold acres, approximately 50,000 net royalty acres in the same area normalized to a 1/8th royalty, production totaling approximately 42,000 net barrels of oil equivalent per day (78% oil) based on two-stream reporting at the time of closing, and extensive water infrastructure. The purchase price paid to the sellers was approximately $3.06 billion in cash, representing a $3.25 billion purchase price less customary closing adjustments made pursuant to the agreement. The Company funded the purchase price through a combination of cash on hand, utilization of credit facility borrowing capacity, and the issuance of senior notes as further discussed in Note 8. Long-Term Debt . The Pioneer Acquisition was accounted for using the acquisition method under ASC Topic 805, Business Combinations, which requires all assets acquired and liabilities assumed to be recorded at fair value at the acquisition date. Provisional fair value measurements have been made by the Company for acquired assets and liabilities, and adjustments to those measurements may be made in subsequent periods (up to one year from the acquisition date) as additional information necessary to complete the fair value analysis is obtained. The following table summarizes the provisional fair values assigned to assets acquired and liabilities assumed as of the acquisition date (presented in millions). Certain studies necessary to complete the purchase price allocation are still under evaluation, including, but not limited to, the valuation of service properties and equipment, inventory, and lease liabilities. The Company will finalize the purchase price allocation during the twelve-month period following the acquisition date, during which time the value of the assets and liabilities presented below may be revised if necessary. In millions As of December 21, 2021 Receivables $ 3 Proved crude oil and natural gas properties 2,396 Unproved crude oil and natural gas properties 693 Service properties, equipment and other 6 Operating lease right-of-use assets 2 Total assets acquired $ 3,100 Revenues and royalties payable $ 14 Accrued liabilities and other 8 Operating lease liabilities 2 Asset retirement obligations 16 Total liabilities assumed $ 40 Net assets acquired $ 3,060 The fair values of proved and unproved properties acquired were measured using discounted cash flow valuation techniques based on inputs that are not observable in the market and, as such, are considered Level 3 fair value measurements. Significant unobservable inputs included future commodity prices adjusted for differentials, projections of estimated quantities of recoverable reserves, forecasted production based on decline curve analysis, estimated timing and amount of future operating and development costs, and a weighted average cost of capital. For income tax purposes, the Pioneer Acquisition will be treated as an asset purchase such that the tax basis in the assets and liabilities will generally reflect the allocated fair value at closing. Therefore, the Company does not anticipate a material tax consequence for deferred income taxes related to the Pioneer Acquisition. The Pioneer Acquisition contributed $29.4 million of revenues and $14.1 million ($0.04 per basic and diluted share) of net income to the Company's consolidated results during the period of ownership from December 21, 2021 to December 31, 2021, excluding transaction expenses. The Company incurred $13.9 million of expenses in connection with the transaction which are reflected in the caption “Acquisition costs” in the consolidated statements of comprehensive income (loss) for the year ended December 31, 2021. The table below summarizes the Company's pro forma results as if the Pioneer Acquisition and associated increase in debt described in Note 8. Long-Term Debt had been completed on January 1, 2020 and were combined with the Company's historical results. The following pro forma information is unaudited, is provided for informational purposes only, and does not represent actual results that would have occurred if the Pioneer Acquisition was completed on January 1, 2020, nor are they indicative of future results. Year Ended December 31, In millions 2021 2020 Pro forma combined total revenues $ 6,657 $ 3,174 Pro forma combined net income (loss) attributable to Continental $ 2,097 $ (481) Powder River Basin Acquisitions In March 2021, the Company acquired undeveloped leasehold and producing properties in the Powder River Basin of Wyoming for $206.6 million, consisting of a $21.5 million escrow deposit paid in December 2020 upon execution of a definitive purchase agreement and a $185.1 million payment made at closing in March 2021. The acquisition was accounted for as an asset acquisition under ASC Topic 805 and included approximately 130,000 net acres and producing properties with production totaling approximately 7,200 net barrels of oil equivalent per day at the time of closing. Of the purchase price, $183 million was allocated to proved properties and $24 million was allocated to unproved properties. The $21.5 million escrow deposit paid in December 2020 is included in the caption "Other noncurrent assets" on the Company's balance sheet at December 31, 2020, which was subsequently reclassified to "Net property and equipment" on the closing date. The Company recognized approximately $4.9 million of asset retirement obligations and $8.2 million of right-of-use assets and corresponding lease liabilities associated with the acquired properties. In November 2021, the Company acquired undeveloped leasehold and producing properties in the Powder River Basin for $246.8 million. The acquisition was accounted for as an asset acquisition under ASC Topic 805 and included approximately 72,000 net acres and immaterial amounts of production. Of the purchase price, $27 million was allocated to proved properties and $220 million was allocated to unproved properties. The Company recognized approximately $0.5 million of asset retirement obligations and an immaterial amount of right-of-use assets and corresponding lease liabilities associated with the acquired properties. 2020 In October 2020, the Company acquired undeveloped leasehold and producing properties in the SCOOP play for $162.8 million. The acquisition included approximately 19,500 net acres and immaterial amounts of production. 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.

Net Property and Equipment

Net Property and Equipment	12 Months Ended
Net Property and Equipment	Dec. 31, 2021
Property, Plant and Equipment, Net [Abstract]
Net Property and Equipment	Net Property and Equipment Net property and equipment includes the following at December 31, 2021 and 2020. See Note 2. Property Acquisitions and Dispositions for discussion of certain acquisitions executed in 2021 that contributed to the increase in net property and equipment in 2021. December 31, In thousands 2021 2020 Proved crude oil and natural gas properties $ 31,613,656 $ 27,726,954 Unproved crude oil and natural gas properties 1,358,673 368,256 Service properties, equipment and other 484,989 414,066 Total property and equipment 33,457,318 28,509,276 Accumulated depreciation, depletion and amortization (16,481,853) (14,771,984) Net property and equipment $ 16,975,465 $ 13,737,292

Accrued Liabilities and Other

Accrued Liabilities and Other	12 Months Ended
Accrued Liabilities and Other	Dec. 31, 2021
Accrued Liabilities and Other Liabilities [Abstract]
Accrued Liabilities and Other	Accrued Liabilities and Other Accrued liabilities and other includes the following at December 31, 2021 and 2020: December 31, In thousands 2021 2020 Prepaid advances from joint interest owners $ 18,964 $ 25,209 Accrued compensation 82,844 47,985 Accrued production taxes, ad valorem taxes and other non-income taxes 90,597 40,818 Accrued interest 75,983 50,009 Current portion of asset retirement obligations 4,123 2,482 Other 13,229 510 Accrued liabilities and other $ 285,740 $ 167,013

Derivative Instruments

Derivative Instruments	12 Months Ended
Derivative Instruments	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments From time to time the Company enters into derivative contracts to economically hedge against the variability in cash flows associated with future sales of production. The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The estimated fair value 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 7. Fair Value Measurements . At December 31, 2021 the Company had outstanding derivative contracts as set forth in the tables below. Natural gas derivatives Weighted Average Hedge Price ($/MMBtu) Period and Type of Contract Average Volumes Hedged Basis Swaps Swaps Sold Put Floor Ceiling January 2022 - December 2023 Basis Swaps - NGPL TXOK 75,000 MMBtus/day $ (0.17) January 2022 - March 2022 Collars - Henry Hub 90,000 MMBtus/day $ 3.00 $ 6.33 Three-way collars - Henry Hub 280,000 MMBtus/day $ 2.33 $ 3.02 $ 4.46 Swaps - Henry Hub 45,000 MMBtus/day $ 3.86 April 2022 - September 2022 Swaps - Henry Hub 190,000 MMBtus/day $ 4.02 October 2022 - December 2022 Collars - Henry Hub 150,000 MMBtus/day $ 3.54 $ 5.34 Three-way collars - Henry Hub 50,000 MMBtus/day $ 3.00 $ 4.07 $ 5.00 Swaps - Henry Hub 50,000 MMBtus/day $ 4.20 January 2023 - December 2023 Collars - Henry Hub 62,500 MMBtus/day $ 3.41 $ 4.87 Three-way collars - Henry Hub 12,500 MMBtus/day $ 3.00 $ 4.32 $ 5.00 Swaps - Henry Hub 175,000 MMBtus/day $ 3.38 January 2024 - December 2024 Swaps - Henry Hub 125,000 MMBtus/day $ 3.12 Collars - Henry Hub 25,000 MMBtus/day $ 3.10 $ 4.18 January 2025 - December 2025 Swaps - Henry Hub 10,000 MMBtus/day $ 3.08 Crude oil derivatives Period and Type of Contract Average Volumes Hedged Weighted Average Hedge Price ($/Bbl) January 2022 - March 2022 NYMEX Roll Swaps 32,500 Bbls/day $ 0.71 April 2022 - June 2022 NYMEX Roll Swaps 15,000 Bbls/day $ 0.85 July 2022 - December 2022 NYMEX Roll Swaps 7,500 Bbls/day $ 0.90 Derivative gains and losses Cash receipts and payments in the following table reflect the gains or losses on derivative contracts which matured during the applicable period, calculated as the difference between the contract price and the market settlement price of matured contracts. The Company's derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate ("WTI") pricing and natural gas derivative settlements based primarily on NYMEX Henry Hub pricing. Non-cash gains and losses below represent the change in fair value of derivative instruments which continued to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period. Year ended December 31, In thousands 2021 2020 2019 Cash received (paid) on derivatives: Crude oil fixed price swaps $ (44,463) $ (31,179) $ — Crude oil collars (9,365) — — Crude oil NYMEX roll swaps (163) — — Natural gas fixed price swaps (84,141) 1,071 58,836 Natural gas collars (11,546) 1,958 5,859 Cash received (paid) on derivatives, net (149,678) (28,150) 64,695 Non-cash gain (loss) on derivatives: Crude oil collars 227 (227) — Crude oil NYMEX roll swaps 957 — — Natural gas fixed price swaps 25,565 2,043 (10,130) Natural gas basis swaps (177) — — Natural gas collars (7,690) 11,676 (5,482) Natural gas three-way collars 1,932 — — Non-cash gain (loss) on derivatives, net 20,814 13,492 (15,612) Gain (loss) on derivative instruments, net $ (128,864) $ (14,658) $ 49,083 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,” “Derivative assets, noncurrent,” “Derivative liabilities,” and “Derivative liabilities, noncurrent,” 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 derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets at December 31, 2021, all at fair value. December 31, In thousands 2021 2020 Commodity derivative assets: Gross amounts of recognized assets $ 42,903 $ 15,900 Gross amounts offset on balance sheet (7,381) (597) Net amounts of assets on balance sheet 35,522 15,303 Commodity derivative liabilities: Gross amounts of recognized liabilities (8,598) (2,408) Gross amounts offset on balance sheet 7,381 597 Net amounts of liabilities on balance sheet $ (1,217) $ (1,811) 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 2021 2020 Derivative assets $ 22,334 $ 15,303 Derivative assets, noncurrent 13,188 — Net amounts of assets on balance sheet 35,522 15,303 Derivative liabilities (899) (227) Derivative liabilities, noncurrent (318) (1,584) Net amounts of liabilities on balance sheet (1,217) (1,811) Total derivative assets, net $ 34,305 $ 13,492

Fair Value Measurements

Fair Value Measurements	12 Months Ended
Fair Value Measurements	Dec. 31, 2021
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. Assets and Liabilities Measured at Fair Value on a Recurring Basis The Company’s derivative instruments are reported at fair value on a recurring basis. In determining the fair values of swap contracts, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of swap contracts are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness. The following tables summarize the valuation of derivative instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31, 2021 and 2020. Fair value measurements at December 31, 2021 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Fixed price swaps $ — $ 27,608 $ — $ 27,608 Basis swaps — (177) — (177) Collars — 3,986 — 3,986 Three-way collars — 1,931 — 1,931 NYMEX roll swaps — 957 — 957 Total $ — $ 34,305 $ — $ 34,305 Fair value measurements at December 31, 2020 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Swaps — $ 2,043 — 2,043 Collars — 11,449 — 11,449 Total $ — $ 13,492 $ — $ 13,492 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. Significant unobservable inputs (Level 3) utilized in the determination of discounted future net cash flows include future commodity prices adjusted for differentials, forecasted production based on decline curve analysis, estimated future operating and development costs, property ownership interests, and a 10% discount rate. At December 31, 2021, the Company's commodity price assumptions were based on forward NYMEX strip prices through year-end 2026 and were then escalated at 3% per year thereafter. Operating cost assumptions were based on current costs escalated at 3% per year beginning in 2023. Unobservable inputs to the Company's fair value assessments are reviewed and 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 year ended December 31, 2021, estimated future net cash flows were determined to be in excess of cost basis, and therefore no impairment was recorded for the Company's proved crude oil and natural gas properties in 2021. For the years ended December 31, 2020 and 2019, the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows, and therefore, were impaired. Such impairments totaled $207.1 million and $3.7 million for 2020 and 2019, respectively, which for 2020 reflected fair value adjustments on legacy properties in the Red River Units totaling $168.1 million and various non-core properties in the North and South regions totaling $14.5 million. The impaired properties were written down to their estimated fair value at the time of impairment of $145.7 million. Impairments for 2020 also include a $24.5 million impairment recognized in the first quarter of 2020 to reduce the Company's crude oil inventory to estimated net realizable value at the time of impairment. Proved property impairments recognized in 2019 reflected write-offs of various non-core properties in the North and South regions. Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2021, 2020, and 2019, reflecting recurring amortization of undeveloped leasehold costs on properties the Company expects will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the consolidated statements of comprehensive income (loss). Year ended December 31, In thousands 2021 2020 2019 Proved property and inventory impairments $ — $ 207,119 $ 3,745 Unproved property impairments 38,370 70,822 82,457 Total $ 38,370 $ 277,941 $ 86,202 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. See Note 8. Long-Term Debt for discussion of the changes in the Company's outstanding debt during the year ended December 31, 2021. December 31, 2021 December 31, 2020 In thousands Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Debt: Credit facility $ 500,000 $ 500,000 $ 160,000 $ 160,000 Notes payable 22,356 22,000 24,590 24,700 5% Senior Notes due 2022 — — 630,470 632,900 4.5% Senior Notes due 2023 648,078 670,200 646,943 669,900 3.8% Senior Notes due 2024 908,061 950,000 906,922 939,500 2.268% Senior Notes due 2026 792,621 795,200 — — 4.375% Senior Notes due 2028 991,880 1,082,100 990,746 1,024,400 5.75% Senior Notes due 2031 1,482,319 1,769,600 1,480,879 1,651,900 2.875% Senior Notes due 2032 791,521 780,500 — — 4.9% Senior Notes due 2044 692,056 781,500 691,868 689,600 Total debt $ 6,828,892 $ 7,351,100 $ 5,532,418 $ 5,792,900 The fair value of 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 notes payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the notes payable and an assumed discount rate. The fair value of notes payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of notes payable is classified as Level 3 in the fair value hierarchy. The fair values of the Company's senior 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
Long-Term Debt	Dec. 31, 2021
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $54.2 million and $43.7 million at December 31, 2021 and 2020, respectively, consists of the following. December 31, In thousands 2021 2020 Credit facility $ 500,000 $ 160,000 Notes payable 22,356 24,590 5% Senior Notes due 2022 — 630,470 4.5% Senior Notes due 2023 648,078 646,943 3.8% Senior Notes due 2024 908,061 906,922 2.268% Senior Notes due 2026 792,621 — 4.375% Senior Notes due 2028 991,880 990,746 5.75% Senior Notes due 2031 1,482,319 1,480,879 2.875% Senior Notes due 2032 791,521 — 4.9% Senior Notes due 2044 692,056 691,868 Total debt 6,828,892 5,532,418 Less: Current portion of long-term debt 2,326 2,245 Long-term debt, net of current portion $ 6,826,566 $ 5,530,173 Credit Facility On October 29, 2021, the Company replaced its credit facility which resulted in an increase in aggregate commitments from $1.5 billion to $1.7 billion and an extension of the maturity date from April 2023 to October 2026. On November 22, 2021, the Company incrementally increased the amount of aggregate credit facility commitments from $1.7 billion to $2.0 billion. The new credit facility provides for benchmark replacement mechanics to address the transition from LIBOR, while all other terms, conditions, and covenants remain substantially unchanged from the prior credit facility. The Company's credit facility is unsecured and has no borrowing base requirement subject to redetermination. The Company had $500 million of outstanding borrowings on its credit facility at December 31, 2021, which were incurred to fund a portion of the Company's December 2021 acquisition of properties in the Permian Basin of Texas as discussed in Note 2. Property Acquisitions and Dispositions. 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, 2021 was 1.6%. The Company had approximately $1.50 billion of borrowing availability on its credit facility at December 31, 2021 after considering outstanding borrowings and letters of credit. The Company incurs commitment fees based on currently assigned credit ratings of 0.20% per annum on the daily average amount of unused borrowing availability. 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, 2021. Senior Notes In November 2021 the Company issued $800 million of 2.268% Senior Notes due 2026 ("2026 Notes") and $800 million of 2.875% Senior Notes due 2032 ("2032 Notes") and received combined total net proceeds from the offerings of $1.59 billion after deducting the initial purchasers' fees and original issuance discount. The 2026 Notes were sold at par and the 2032 Notes were sold at 99.922% of par in private placement transactions exempt from the registration requirements of the Securities Act to eligible purchasers. The Company used the net proceeds from the offerings to finance a portion of its December 2021 acquisition of properties in the Permian Basin as discussed in Note 2. Property Acquisitions and Dispositions. 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, 2021. 2023 Notes 2024 Notes 2026 Notes 2028 Notes 2031 Notes 2032 Notes 2044 Notes Face value (in thousands) $649,625 $911,000 $800,000 $1,000,000 $1,500,000 $800,000 $700,000 Maturity date April 15, 2023 June 1, 2024 November 15, 2026 January 15, 2028 January 15, 2031 April 1, 2032 June 1, 2044 Interest payment dates April 15, Oct 15 June 1, Dec 1 May 15, Nov 15 Jan 15, July 15 Jan 15, April 1, Oct 1 June 1, Dec 1 Make-whole redemption period (1) Jan 15, 2023 Mar 1, 2024 Nov 15, 2023 Oct 15, 2027 Jul 15, 2030 January 1. 2032 Dec 1, 2043 (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. 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. These covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at December 31, 2021. The senior notes are obligations of Continental Resources, Inc. Additionally, as of December 31, 2021 three of the Company’s wholly-owned consolidated subsidiaries, Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, and The Mineral Resources Company, whose assets, equity, and results of operations are not material, fully and unconditionally guarantee the senior notes on a joint and several basis. The Company plans to designate Jagged Peak Energy LLC and Parsley SoDe Water LLC, its recently acquired consolidated subsidiaries discussed in Note 2. Property Acquisitions and Dispositions , as restricted subsidiaries under the Company’s senior note indentures. As a result, such entities will fully and unconditionally guarantee the senior notes on a joint and several basis along with the Company’s other subsidiary guarantors. The Company’s other subsidiaries existing at December 31, 2021, whose assets, equity, and results of operations attributable to the Company are not material, do not guarantee the senior notes. Retirement of Senior Notes 2021 In January 2021, the Company redeemed $400.0 million principal amount of its outstanding 2022 Notes and subsequently redeemed the remaining $230.8 million principal amount of its 2022 Notes in April 2021. The Company recognized pre-tax losses on extinguishment of debt totaling $0.3 million related to the redemptions, which included the pro-rata write-off of deferred financing costs and unamortized debt premium associated with the redeemed notes. The losses are reflected in the caption “Gain (loss) on extinguishment of debt” in the consolidated statements of comprehensive income (loss). 2020 In March and April 2020, the Company repurchased a portion of its 2023 Notes and 2024 Notes in open market transactions at a substantial discount to the face value of the notes, including $50.4 million face value of its 2023 Notes at an aggregate cost of $29.3 million and $89.0 million face value of its 2024 Notes at an aggregate cost of $46.9 million, in each case, including accrued and unpaid interest to the repurchase dates. The Company recognized pre-tax gains on extinguishment of debt totaling $64.6 million related to the repurchases, which included the pro-rata write-off of deferred financing costs and unamortized debt discount associated with the notes. In November 2020, the Company repurchased $469.2 million of its 2022 Notes and $800.0 million of its 2023 Notes using proceeds from its November 2020 issuance of $1.5 billion of 5.75% Senior Notes due 2031. For the 2022 Notes, the purchase price was equal to 100.250% of the principal amount repurchased plus accrued and unpaid interest to the repurchase date. The aggregate of the principal amount, premium, and accrued interest paid upon repurchase of the 2022 Notes was $475.0 million. For the 2023 Notes, the purchase price was equal to 103.000% of the principal amount repurchased plus accrued and unpaid interest to the repurchase date. The aggregate of the principal amount, premium, and accrued interest paid upon repurchase of the 2023 Notes was $828.0 million. The Company recorded pre-tax losses on extinguishment of debt related to these repurchases totaling $28.9 million, which included the premium and pro-rata write-off of deferred financing costs and unamortized debt premium associated with the notes. 2019 In September 2019, the Company redeemed $500 million of its previously outstanding $1.6 billion of 2022 Notes. 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. Notes payable In June 2020, the Company borrowed an aggregate of $26.0 million under two 10-year amortizing term loans secured by the Company’s corporate office building and its interest in parking facilities in Oklahoma City, Oklahoma. The loans mature in May 2030 and bear interest at a fixed rate of 3.50% per annum through June 9, 2025, at which time the interest rate will be reset and fixed through the maturity date. Principal and interest are payable monthly through the maturity date and, accordingly, $2.3 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, 2021 associated with the loans. A portion of the proceeds from the new loans was used to fully repay the Company's previous note payable that was set to mature in February 2022, which had a balance at pay-off of $4.4 million.

Revenues

Revenues	12 Months Ended
Revenues	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	Revenues 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 $185.1 million, $159.0 million, and $192.0 million for the years ended December 31, 2021, 2020, and 2019, 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, in periods of significantly depressed prices for natural gas and NGLs the contractual pricing adjustments applied by the midstream customer in a particular month may exceed the consideration to be received by the Company under the arrangement, resulting in a net payment owed by the Company to the midstream customer. In these situations, the net amounts paid or payable by the Company are reflected as a reduction of natural gas sales in the caption "Crude oil and natural gas sales" in the consolidated statements of comprehensive income (loss). Such payments, which are referred to herein as negative gas revenues, were immaterial for 2021 and 2019 and totaled $25.6 million for operated properties for 2020. Under certain arrangements, the Company has the right to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of the Company's operated natural gas production. When the Company elects to take volumes in kind, it pays third parties to transport the processed products it took in-kind to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, operated revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Operated sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, the Company's revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula, but exclude the transportation expenses the Company incurs to transport the processed products to downstream customers. Transportation expenses associated with these arrangements totaled $39.9 million, $37.7 million, and $33.7 million for the years ended December 31, 2021, 2020, and 2019, 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. In periods of significantly depressed prices for natural gas and NGLs the costs incurred by the outside operator in a particular month may exceed the consideration to be received by the Company, resulting in a net payment owed by the Company to the outside operator. In these situations, the net amounts paid or payable by the Company are reflected as a reduction of natural gas sales in the caption "Crude oil and natural gas sales" in the consolidated statements of comprehensive income (loss). Such negative gas revenues associated with non-operated properties were immaterial for 2021 and 2019 and totaled $17.3 million for 2020. Revenues from derivative instruments – See Note 6. 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, 2021 2020 2019 In thousands North Region South Region Total North Region South Region Total North Region South Region Total Crude oil revenues: Operated properties $ 2,392,465 $ 838,129 $ 3,230,594 $ 1,264,149 $ 537,961 $ 1,802,110 $ 2,365,574 $ 786,652 $ 3,152,226 Non-operated properties 656,727 61,973 718,700 362,952 34,914 397,866 727,068 50,700 777,768 Total crude oil revenues 3,049,192 900,102 3,949,294 1,627,101 572,875 2,199,976 3,092,642 837,352 3,929,994 Natural gas revenues: Operated properties (1) 460,376 1,186,937 1,647,313 28,086 301,486 329,572 109,668 411,464 521,132 Non-operated properties (2) 115,420 81,714 197,134 720 25,166 25,886 25,188 38,075 63,263 Total natural gas revenues 575,796 1,268,651 1,844,447 28,806 326,652 355,458 134,856 449,539 584,395 Crude oil and natural gas sales $ 3,624,988 $ 2,168,753 $ 5,793,741 $ 1,655,907 $ 899,527 $ 2,555,434 $ 3,227,498 $ 1,286,891 $ 4,514,389 Timing of revenue recognition Goods transferred at a point in time $ 3,624,988 $ 2,168,753 $ 5,793,741 $ 1,655,907 $ 899,527 $ 2,555,434 $ 3,227,498 $ 1,286,891 $ 4,514,389 Goods transferred over time — — — — — — — — — $ 3,624,988 $ 2,168,753 $ 5,793,741 $ 1,655,907 $ 899,527 $ 2,555,434 $ 3,227,498 $ 1,286,891 $ 4,514,389 (1) Operated natural gas revenues for the North region include negative gas revenues totaling $25.6 million for the year ended December 31, 2020. (2) Non-operated natural gas revenues for the North region include negative gas revenues totaling $17.3 million for the year ended December 31, 2020. 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. The Company's outstanding crude oil sales contracts at December 31, 2021 are primarily short-term in nature with contract terms of less than one year. For such contracts, the Company has utilized the practical expedient in Accounting Standards Codification ("ASC") 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations, if any, if the performance obligation is part of a contract that has an original expected duration of one year or less. The majority of the Company's operated natural gas production is sold at lease locations to midstream customers under multi-year term contracts. For such contracts having a term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14A which indicates an entity is not required to disclose the transaction price allocated to remaining performance obligations, if any, if variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under 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," 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, 2021, 2020, and 2019 related to performance obligations satisfied in prior reporting periods were not material.

Allowance for Credit Losses

Allowance for Credit Losses	12 Months Ended
Allowance for Credit Losses	Dec. 31, 2021
Credit Loss [Abstract]
Allowance for Credit Losses	Allowance for Credit Losses The Company's principal exposure to credit risk is through the sale of its crude oil and natural gas production and its receivables associated with billings to joint interest owners. Accordingly, the Company classifies its receivables into two portfolio segments as depicted on the consolidated balance sheets as "Receivables — Crude oil and natural gas sales” and "Receivables — Joint interest and other.” Historically, the Company's credit losses on receivables have been immaterial. The Company’s aggregate allowance for credit losses totaled $2.8 million and $2.5 million at December 31, 2021 and 2020, respectively, which is reported as "Allowance for credit losses" in the consolidated balance sheets. Aggregate credit loss expenses totaled $0.8 million, $1.8 million, and $1.6 million for the years ended December 31, 2021, 2020, and 2019, respectively, which are included in “General and administrative expenses” in the consolidated statements of comprehensive income (loss). Receivables—Crude oil and natural gas sales The Company's crude oil and natural gas production from operated properties is generally sold to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies. The Company monitors its credit loss exposure to these counterparties primarily by reviewing credit ratings, financial statements, and payment history. Credit terms are extended based on an evaluation of each counterparty’s credit worthiness. The Company has not generally required its counterparties to provide collateral to secure its crude oil and natural gas sales receivables. Receivables associated with crude oil and natural gas sales are short term in nature. Receivables from the sale of crude oil and natural gas from operated properties are generally collected within one month after the month in which a sale has occurred, while receivables associated with non-operated properties are generally collected within two to three months after the month in which production occurs. The Company’s allowance for credit losses on crude oil and natural gas sales was negligible at both December 31, 2021 and December 31, 2020. The allowance was determined by considering a number of factors, primarily including the Company’s history of credit losses with adjustment as needed to reflect current conditions, the length of time accounts are past due, whether amounts relate to operated properties or non-operated properties, and the counterparty's ability to pay. There were no significant write-offs, recoveries, or changes in the provision for credit losses on this portfolio segment during the years ended December 31, 2021, 2020, and 2019. Receivables—Joint interest and other Joint interest and other receivables primarily arise from billing the individuals and entities who own a partial interest in the wells we operate. Joint interest receivables are due within 30 days and are considered delinquent after 60 days. In order to minimize our exposure to credit risk with these counterparties we generally request prepayment of drilling costs where it is allowed by contract or state law. Such prepayments are used to offset future capital costs when billed, thereby reducing the Company's credit risk. We may have the right to place a lien on a co-owner's interest in the well, to net production proceeds against amounts owed in order to secure payment or, if necessary, foreclose on the co-owner's interest.

Income Taxes

Income Taxes	12 Months Ended
Income Taxes	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income Taxes	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 2021 2020 2019 Current income tax provision (benefit): United States federal $ — $ (2,248) $ — Various states — 29 — Total current income tax provision (benefit) — (2,219) — Deferred income tax provision (benefit): United States federal 467,051 (148,828) 191,328 Various states 52,679 (18,143) 21,361 Total deferred income tax provision (benefit) 519,730 (166,971) 212,689 Provision (benefit) for income taxes $ 519,730 $ (169,190) $ 212,689 Effective tax rate 23.8 % 21.8 % 21.5 % The Company's effective tax rate differs from the United States federal statutory tax rate due to the effect of state income taxes, equity compensation, changes in valuation allowances, and other tax items as reflected in the table below. Year ended December 31, In thousands, except tax rates 2021 2020 2019 Income (loss) before income taxes $ 2,186,138 $ (774,751) $ 987,162 U.S. federal statutory tax rate 21.0 % 21.0 % 21.0 % Expected income tax provision (benefit) based on U.S. federal statutory tax rate 459,089 (162,698) 207,304 Items impacting the effective tax rate: State and local income taxes, net of federal benefit 77,979 (24,808) 31,967 Tax (benefit) deficiency from stock-based compensation 5,869 4,927 (7,971) Sale of Canadian subsidiary and assets — — (16,860) Other, net (8,733) (1,085) (1,751) Change in valuation allowance (14,474) 14,474 — Provision (benefit) for income taxes $ 519,730 $ (169,190) $ 212,689 Effective tax rate 23.8 % 21.8 % 21.5 % In assessing the realizability of deferred tax assets the Company must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company applies judgment to determine the weight of both positive and negative evidence in order to conclude whether a valuation allowance is necessary for its deferred tax assets. In determining whether a valuation allowance is required, the Company considers, among other factors, the Company's financial position, results of operations, projected future taxable income, reversal of existing deferred tax liabilities against deferred tax assets, and tax planning strategies. During 2020, a $14.5 million valuation allowance was established for the deferred tax asset associated with a portion of the Company's Oklahoma state net operating loss carryforwards. In 2021, the Company reassessed the realizability of the deferred tax asset related to Oklahoma state net operating loss carryforwards, and based on current year activity, determined it was more likely than not that such assets would be realized. Therefore, it was determined that the previously recorded valuation allowance in 2020 should be released in 2021. The Company will continue to evaluate both the positive and negative evidence on a quarterly basis in determining the need for a valuation allowance with respect to its deferred tax assets. Changes in positive and negative evidence, including differences between estimated and actual results, could result in changes in the valuation of our deferred tax assets that could have a material impact on our consolidated financial statements. Changes in existing tax laws could also affect actual tax results and the realization of deferred tax assets over time. In 2019, the Company sold its Canadian subsidiary and associated properties. Prior to the sale, the Company had recognized cumulative valuation allowances totaling $19.6 million against deferred tax assets associated with operating loss carryforwards generated by the Canadian subsidiary for which the Company did not expect to realize a benefit. 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. The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2021 and 2020 are reflected in the table below. December 31, In thousands 2021 2020 Deferred tax assets United States net operating loss carryforwards $ 365,602 $ 579,781 Equity compensation 12,751 12,900 Other 29,421 10,691 Total deferred tax assets 407,774 603,372 Valuation allowance — (14,474) Total deferred tax assets, net of valuation allowance 407,774 588,898 Deferred tax liabilities Property and equipment (2,536,938) (2,204,378) Other (10,720) (4,674) Total deferred tax liabilities (2,547,658) (2,209,052) Deferred income tax liabilities, net $ (2,139,884) $ (1,620,154) As of December 31, 2021, the Company had federal and state net operating loss carryforwards of $1.17 billion and $3.63 billion, respectively. Approximately $283 million of the Company's federal net operating loss carryforwards were generated in tax years prior to 2018 and expire in 2037, with the remaining $887 million having an indefinite life. The Company’s net operating loss carryforward in Oklahoma totaled $3.07 billion at December 31, 2021, of which $1.96 billion expires between 2030 and 2037, and the remaining $1.11 billion has an indefinite life. The Company’s net operating loss carryforward in North Dakota totaled $457 million at December 31, 2021 and has an indefinite life. Any available statutory depletion carryforwards will be recognized when realized. The Company files income tax returns in U.S. federal and state 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 2018.

Leases (Notes)

Leases (Notes)	12 Months Ended
Leases (Notes)	Dec. 31, 2021
Leases [Abstract]
Lessee, Operating Leases [Text Block]	LeasesThe Company’s lease liabilities recognized on the balance sheet as a lessee totaled $15.5 million and $8.4 million as of December 31, 2021 and 2020, respectively, 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. The amounts disclosed herein primarily represent costs associated with properties operated by the Company that are presented on a gross basis and do not represent 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 accounts for lease and non-lease components in its contracts as a single lease component for all asset classes. Additionally, the Company does not apply the recognition requirements of ASC Topic 842 to leases with durations of twelve months or less and uses hindsight in determining the lease term for all leases. The Company's leasing activities as a lessor are negligible. December 31, In thousands 2021 2020 Drilling rig commitments $ — $ 2,025 Surface use agreements 12,354 4,928 Field equipment 2,095 928 Other 1,025 546 Total $ 15,474 $ 8,427 Minimum future commitments by year for the Company's operating leases as of December 31, 2021 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 2022 $ 2,369 2023 2,263 2024 1,831 2025 1,295 2026 1,258 Thereafter 13,084 Total operating lease liabilities, at undiscounted value $ 22,100 Less: Imputed interest (6,626) Total operating lease liabilities, at discounted present value $ 15,474 Less: Current portion of operating lease liabilities (1,674) Operating lease liabilities, net of current portion $ 13,800 Additional information for the Company's operating leases is presented below. Lease costs 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. Short-term lease costs primarily represent operating day-rate charges for drilling rig contracts with durations of one year or less and month-to-month field equipment rentals. A portion of such lease costs are borne by other interest owners. Year ended December 31, In thousands, except weighted average data 2021 2020 2019 Lease costs: Operating lease costs $ 6,653 $ 6,444 $ 11,130 Variable lease costs 3,271 4,956 11,930 Short-term lease costs 77,551 107,984 176,586 Total lease costs $ 87,475 $ 119,384 $ 199,646 Other information: Right-of-use assets obtained in exchange for new operating lease liabilities (1) $ 10,481 $ 7,377 $ 1,208 Operating cash flows from operating leases included in lease liabilities 1,731 890 804 Weighted average remaining lease term as of December 31 (in years) 14.4 13.2 11.5 Weighted average discount rate as of December 31 5.0 % 4.8 % 4.9 %
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	Minimum future commitments by year for the Company's operating leases as of December 31, 2021 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 2022 $ 2,369 2023 2,263 2024 1,831 2025 1,295 2026 1,258 Thereafter 13,084 Total operating lease liabilities, at undiscounted value $ 22,100 Less: Imputed interest (6,626) Total operating lease liabilities, at discounted present value $ 15,474 Less: Current portion of operating lease liabilities (1,674) Operating lease liabilities, net of current portion $ 13,800
Lease, Cost [Table Text Block]	Year ended December 31, In thousands, except weighted average data 2021 2020 2019 Lease costs: Operating lease costs $ 6,653 $ 6,444 $ 11,130 Variable lease costs 3,271 4,956 11,930 Short-term lease costs 77,551 107,984 176,586 Total lease costs $ 87,475 $ 119,384 $ 199,646 Other information: Right-of-use assets obtained in exchange for new operating lease liabilities (1) $ 10,481 $ 7,377 $ 1,208 Operating cash flows from operating leases included in lease liabilities 1,731 890 804 Weighted average remaining lease term as of December 31 (in years) 14.4 13.2 11.5 Weighted average discount rate as of December 31 5.0 % 4.8 % 4.9 %

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies 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, 2021 under the arrangements amount to approximately $1.31 billion, of which $275 million is expected to be incurred in 2022, $270 million in 2023, $251 million in 2024, $164 million in 2025, $139 million in 2026, and $214 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. Lease commitments – The Company has various lease commitments primarily associated with surface use agreements and field equipment. See Note 12. Leases for additional information. Pledge commitment – The Company entered into a $25.0 million ten-year irrevocable pledge agreement with Oklahoma State University in December 2021. The pledge agreement provides for ten equal payments of $2.5 million to be paid annually on or before December 31 of each year until the pledge is paid in full on December 31, 2030. In connection with the pledge, the Company recognized a $25.0 million charge to earnings which is reflected in the caption “Other income (expense)—Other” in the consolidated statements of comprehensive income (loss) for the year ended December 31, 2021. Pending property acquisition – See Note 20. Subsequent Events for discussion of a definitive acquisition agreement executed by the Company subsequent to December 31, 2021. Litigation – The Company is involved in various 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, 2021 and 2020, the Company had recognized a liability within “Other noncurrent liabilities” of $7.9 million and $7.7 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
Related Party Transactions	Dec. 31, 2021
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, $0.2 million, and $0.4 million and received payments from these affiliates of $0.1 million, $0.3 million, and $0.3 million during the years ended December 31, 2021, 2020, and 2019, respectively, relating to the operations of the respective properties. At December 31, 2021 and 2020, approximately $39,000 and $18,000, respectively, was due from these affiliates relating to these transactions, which is included in “Receivables — Joint interest and other” on the consolidated balance sheets. At December 31, 2021 and 2020, approximately $37,000 and $18,000, 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 2021, 2020, and 2019, the Company charged affiliates approximately $11,300, $8,100, and $17,600, respectively, for use of its corporate aircraft crews, fuel, and reimbursement of expenses and received approximately $5,000, $9,500, and $18,900 from affiliates in 2021, 2020, and 2019, respectively, in connection with such items. The Company was charged approximately $117,000, $120,000, and $303,000, respectively, by affiliates for use of their aircraft and reimbursement of expenses during 2021, 2020, and 2019 and paid $84,000, $158,000, and $426,000 to the affiliates in 2021, 2020, and 2019, respectively. At December 31, 2021, approximately $6,300 was due from an affiliate relating to these transactions, which is included in “Receivables —

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
Stock-Based Compensation	Dec. 31, 2021
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 (loss), was $63.2 million, $64.6 million, and $52.0 million for the years ended December 31, 2021, 2020, and 2019, respectively. In March 2019, the Company amended and restated its 2013 Plan and specified 12,983,543 shares of common stock may be issued pursuant to the amended plan. Subject to limited exceptions, the 2013 Plan allows previously issued shares to be reissued if such shares are subsequently forfeited or withheld to satisfy tax withholdings. As of December 31, 2021, the Company had 8,492,645 shares of common stock available for long-term incentive awards to employees and directors under the 2013 Plan. Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan or agreement relevant to a given award, includes the right to vote the restricted stock and to receive dividends, subject to forfeiture. Restricted stock grants generally vest over periods ranging from 1 to 3 years. A summary of changes in non-vested restricted shares from December 31, 2018 to December 31, 2021 is presented below. Number of Weighted 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 Granted 2,738,625 26.93 Vested (1,146,618) 45.78 Forfeited (163,277) 36.69 Non-vested restricted shares at December 31, 2020 4,890,638 $ 36.26 Granted 3,050,491 24.73 Vested (1,750,483) 44.36 Forfeited (296,138) 26.61 Non-vested restricted shares at December 31, 2021 5,894,508 $ 28.38 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 2021, 2020, and 2019 was approximately $46.7 million, $27.5 million, and $79.7 million, respectively. As of December 31, 2021, there was approximately $70 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.4 years.

Shareholders' Equity Attributab

Shareholders' Equity Attributable to Continental Resources (Notes)	12 Months Ended
	Dec. 31, 2021
Shareholders' Equity Attributable to Continental Resources [Abstract]
Shareholders' Equity Attributable to Continental Resources	Shareholders' Equity Attributable to Continental Resources Share Repurchases 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. See Note 20. Subsequent Events for discussion of an increase in the authorized amount of the Company's share repurchase program made subsequent to December 31, 2021. As of December 31, 2021, the Company has repurchased and retired a cumulative total of approximately 17.0 million shares under the program at an aggregate cost of $441.1 million as reflected in the table below by year. Number of Aggregate cost (in thousands) 2019 Share Repurchases 5,646,553 $ 190,239 2020 Share Repurchases 8,122,104 126,906 2021 Share Repurchases 3,198,571 123,924 Total 16,967,228 $ 441,069 The timing and amount of the Company's share repurchases are subject to market conditions and management discretion. 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 Payments The following table summarizes the dividends paid by the Company on its outstanding common stock for the years ended December 31, 2021, 2020, and 2019. Amount (in thousands) Dividend per share Year Ended December 31, 2019 Fourth quarter $ 18,747 $ 0.05 Total $ 18,747 Year Ended December 31, 2020 First quarter $ 18,580 $ 0.05 Total $ 18,580 Year Ended December 31, 2021 Second quarter $ 40,429 $ 0.11 Third quarter 55,132 $ 0.15 Fourth quarter 72,975 $ 0.20 Total $ 168,536 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 (loss), net of tax” in the consolidated statements of comprehensive income (loss). The following table summarizes the change in accumulated other comprehensive income for the year ended December 31, 2019. In thousands 2019 Beginning accumulated other comprehensive income, net of tax $ 415 Foreign currency translation adjustments 140 Release of cumulative translation adjustments (1) (555) Income taxes (2) — Other comprehensive income (loss), net of tax (415) Ending accumulated other comprehensive income, net of tax $ — (1) In conjunction with the Company’s sale of its Canadian operations in 2019, the cumulative translation adjustments were released. See Note 2. Property Acquisitions and 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
Noncontrolling Interests Noncontrolling Interests	Dec. 31, 2021
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 within an area of mutual interest 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 and 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. Periodically, Franco-Nevada makes capital contributions to, and receives revenue distributions from, TMRC II and the portion of Continental’s consolidated net assets attributable to Franco-Nevada totaled $369.8 million and $355.1 million at December 31, 2021 and 2020, respectively. Joint ownership arrangement

Crude Oil and Natural Gas Prope

Crude Oil and Natural Gas Property Information	12 Months Ended
Crude Oil and Natural Gas Property Information	Dec. 31, 2021
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, 2021, 2020 and 2019. Year ended December 31, In thousands 2021 2020 2019 Crude oil and natural gas sales $ 5,793,741 $ 2,555,434 $ 4,514,389 Production expenses (406,906) (359,267) (444,649) Production taxes (404,362) (192,718) (357,988) Transportation expenses (224,989) (196,692) (225,649) Exploration expenses (21,047) (17,732) (14,667) Depreciation, depletion, amortization and accretion (1,872,075) (1,859,893) (1,997,854) Property impairments (38,370) (277,941) (86,202) Income tax (provision) benefit (1) (690,902) 83,427 (323,025) Results from crude oil and natural gas producing activities $ 2,135,090 $ (265,382) $ 1,064,355 (1) Income taxes reflect the application of a combined federal and state tax rate of 24.5% on pre-tax income/loss generated by our 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 that year. 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, 2021, 2020 and 2019 are presented below. See Note 2. Property Acquisitions and Dispositions for discussion of notable property acquisitions executed in 2021 that gave rise to the significant increase in costs incurred and aggregate capitalized costs in the current year. Year ended December 31, In thousands 2021 2020 2019 Property acquisition costs: Proved $ 2,580,271 $ 60,494 $ 51,558 Unproved 1,197,507 201,919 312,680 Total property acquisition costs 3,777,778 262,413 364,238 Exploration Costs 171,549 48,282 50,143 Development Costs 1,174,828 1,053,532 2,388,582 Total $ 5,124,155 $ 1,364,227 $ 2,802,963 Costs incurred above include asset retirement costs and revisions thereto of $31.1 million, $18.1 million and $6.7 million for the years ended December 31, 2021, 2020 and 2019, 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, 2021 and 2020 are as follows: December 31, In thousands 2021 2020 Proved crude oil and natural gas properties $ 31,613,656 $ 27,726,954 Unproved crude oil and natural gas properties 1,358,673 368,256 Total 32,972,329 28,095,210 Less accumulated depreciation, depletion and amortization (16,310,054) (14,622,376) Net capitalized costs $ 16,662,275 $ 13,472,834 Under the successful efforts method of accounting, the costs of drilling an exploratory well are capitalized pending determination of whether proved reserves can be attributed to the discovery. When initial drilling and completion operations are complete, management attempts to determine whether the well has discovered crude oil and natural gas reserves and, if so, whether those reserves can be classified as proved reserves. Often, the determination of whether proved reserves can be recorded under SEC guidelines cannot be made when drilling is completed. In those situations where management believes that economically producible hydrocarbons have not been discovered, the exploratory drilling costs are reflected on the consolidated statements of comprehensive income (loss) as dry hole costs, a component of “Exploration expenses.” Where sufficient hydrocarbons have been discovered to justify further exploration or appraisal activities, exploratory drilling costs are deferred under the caption “Net property and equipment” on the consolidated balance sheets pending the outcome of those activities. On at least a quarterly basis, operating and financial management review the status of all deferred exploratory drilling costs in light of ongoing exploration activities—in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts. If management determines that future appraisal drilling or development activities are not likely to occur, any associated exploratory well costs are expensed in that period of determination. The following table presents the amount of capitalized exploratory well costs pending evaluation at December 31 for each of the last three years and changes in those amounts during the years then ended: Year ended December 31, In thousands 2021 2020 2019 Balance at January 1 $ 32,737 $ 6,257 $ 3,959 Additions to capitalized exploratory well costs pending determination of proved reserves 122,068 32,880 28,280 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves (117,131) (72) (23,200) Capitalized exploratory well costs charged to expense (1) (6,328) (2,782) Balance at December 31 $ 37,673 $ 32,737 $ 6,257 Number of gross wells 17 16 11 As of December 31, 2021, 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, 2021
Supplemental Crude Oil and Natural Gas Information [Abstract]
Supplemental Crude Oil and Natural Gas Information (Unaudited)	Supplemental Crude Oil and Natural Gas Information (Unaudited) The table below shows estimates of proved reserves prepared by the Company’s internal technical staff and independent external reserve engineers in accordance with SEC definitions. Ryder Scott Company, L.P. prepared reserve estimates for properties comprising approximately 98%, 95%, and 91% of the Company's total proved reserves as of December 31, 2021, 2020, and 2019, 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, 2021, 2020, and 2019 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, 2021, 2020, and 2019 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, 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 (249,845) (1,530,174) (504,874) Extensions, discoveries and other additions 42,106 295,686 91,387 Production (58,745) (306,528) (109,833) Sales of minerals in place — — — Purchases of minerals in place 3,272 27,269 7,817 Proved reserves as of December 31, 2020 496,975 3,640,724 1,103,762 Revisions of previous estimates 14,574 233,966 53,569 Extensions, discoveries and other additions 165,268 1,235,022 371,105 Production (58,636) (370,110) (120,321) Sales of minerals in place (70) (469) (148) Purchases of minerals in place 175,419 371,546 237,343 Proved reserves as of December 31, 2021 793,530 5,110,679 1,645,310 Revisions of previous estimates. Revisions for 2021 are comprised of (i) upward price revisions of 92 MMBo and 458 Bcf (totaling 168 MMBoe) due to the significant increase in average crude oil and natural gas prices in 2021 compared to 2020 resulting from the lifting of COVID-19 restrictions, the resumption of normal economic activity, and the resulting improvement in supply and demand fundamentals, (ii) the removal of 31 MMBo and 155 Bcf (totaling 57 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due continual refinement of our drilling and development programs and reallocation of capital to areas providing the best opportunities to improve efficiencies, recoveries, and rates of return, (iii) downward revisions of 12 MMBo and 263 Bcf (totaling 56 MMBoe) from the removal of PUD reserves due to changes in anticipated well densities, economics, performance, and other factors, and (iv) downward revisions for oil reserves of 35 MMBo and upward revisions for natural gas reserves of 195 Bcf (netting to 2 MMBoe of downward revisions) due to changes in ownership interests, operating costs, anticipated production, and other factors. Revisions for 2020 are comprised of (i) the removal of 50 MMBo and 345 Bcf (totaling 107 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to a reduction in the scope of future drilling programs based on adverse market conditions, reduced demand, and lower prices caused by the COVID-19 pandemic and our resulting allocation of capital to areas providing the best opportunities to improve efficiencies, recoveries, and rates of return, (ii) downward revisions of 29 MMBo and 172 Bcf (totaling 58 MMBoe) from the removal of PUD reserves due to changes in economics, performance, and other factors, (iii) downward price revisions of 214 MMBo and 1,043 Bcf (totaling 388 MMBoe) due to a significant decrease in average crude oil and natural gas prices in 2020 compared to 2019 resulting from the economic turmoil caused by the COVID-19 pandemic and other factors, and (iv) net upward revisions for oil reserves of 43 MMBo and 31 Bcf (totaling 48 MMBoe) due to changes in ownership interests, operating costs, anticipated production, and other factors. 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 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. 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. For 2021, proved reserve additions in the Bakken totaled 140 MMBo and 375 Bcf (totaling 202 MMBoe) and proved reserve additions in Oklahoma totaled 25 MMBo and 860 Bcf (totaling 169 MMBoe). Sales of minerals in place. There were no individually significant dispositions of proved reserves in the three years reflected in the table above. Purchases of minerals in place. Purchases for 2021 primarily represent acquisitions of proved reserves in the Permian Basin and Powder River Basin as discussed in Note 2. Property Acquisitions and Dispositions . Proved reserves acquired in the Permian Basin in 2021 totaled 149 MMBo and 326 Bcf (totaling 203 MMBoe) and proved reserves acquired in the Powder River Basin totaled 26 MMBo and 46 Bcf (totaling 34 MMBoe). There were no individually significant acquisitions of proved reserves in 2019 or 2020. 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, 2021, 2020 and 2019: December 31, 2021 2020 2019 Proved Developed Reserves Crude oil (MBbl) 424,153 281,906 336,405 Natural Gas (MMcf) 2,901,147 2,073,011 2,226,117 Total (MBoe) 907,678 627,407 707,424 Proved Undeveloped Reserves Crude oil (MBbl) 369,377 215,069 423,782 Natural Gas (MMcf) 2,209,532 1,567,713 2,928,354 Total (MBoe) 737,632 476,355 911,841 Total Proved Reserves Crude oil (MBbl) 793,530 496,975 760,187 Natural Gas (MMcf) 5,110,679 3,640,724 5,154,471 Total (MBoe) 1,645,310 1,103,762 1,619,265 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, 2021, 2020, and 2019. 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 2021 2020 2019 Future cash inflows $ 67,034,046 $ 21,334,235 $ 49,893,470 Future production costs (18,837,000) (7,750,834) (15,309,672) Future development and abandonment costs (7,751,678) (3,950,752) (10,033,887) Future income taxes (1) (7,862,849) (724,569) (3,351,657) Future net cash flows 32,582,519 8,908,080 21,198,254 10% annual discount for estimated timing of cash flows (15,946,126) (4,254,515) (10,736,613) Standardized measure of discounted future net cash flows $ 16,636,393 $ 4,653,565 $ 10,461,641 (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, 2021, 2020, and 2019. The weighted average crude oil price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $62.19, $34.34, and $51.95 per barrel at December 31, 2021, 2020, and 2019, respectively. The weighted average natural gas price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $3.46, $1.17, and $2.02 per Mcf at December 31, 2021, 2020, and 2019, 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 2021 2020 2019 Standardized measure of discounted future net cash flows at January 1 $ 4,653,565 $ 10,461,641 $ 15,684,817 Extensions, discoveries and improved recoveries, less related costs 2,985,056 187,981 1,649,322 Revisions of previous quantity estimates 816,674 (2,952,489) (1,564,503) Changes in estimated future development and abandonment costs 706,168 4,760,286 1,401,513 Purchases (sales) of minerals in place, net 3,408,365 53,742 49,330 Net change in prices and production costs 9,396,945 (6,912,031) (6,591,347) Accretion of discount 489,273 1,183,993 1,865,034 Sales of crude oil and natural gas produced, net of production costs (4,757,483) (1,806,758) (3,486,103) Development costs incurred during the period 683,212 863,101 1,557,121 Change in timing of estimated future production and other 1,871,903 (2,325,024) (1,690,779) Change in income taxes (3,617,285) 1,139,123 1,587,236 Net change 11,982,828 (5,808,076) (5,223,176) Standardized measure of discounted future net cash flows at December 31 $ 16,636,393 $ 4,653,565 $ 10,461,641

Subsequent Events

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2021
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events Acquisition Agreement On January 24, 2022, the Company executed a definitive agreement to acquire oil and gas properties in the Powder River Basin for $450 million of cash, subject to customary closing price adjustments. The properties include approximately 172,000 net leasehold acres and producing properties with production totaling approximately 16,000 barrels of oil equivalent per day based on two-stream reporting. Closing of the acquisition is expected to occur in late March 2022 and remains subject to the completion of customary due diligence procedures and closing conditions. Increase in Share Repurchase Program On February 8, 2022, the Company's Board of Directors approved an increase in the size of the Company's existing share repurchase program from $1.0 billion to $1.5 billion, inclusive of cumulative amounts repurchased to date. As of the date of this filing, the Company has repurchased a cumulative $441.1 million of its common stock, leaving approximately $1.06 billion of authorized repurchasing capacity under the modified program. 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 On February 9, 2022, the Company declared a quarterly cash dividend of $0.23 per share on its outstanding common stock, which will be paid on March 4, 2022 to shareholders of record as of February 22, 2022.

Organization and Summary of S_2

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
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, management, 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. In 2021 the Company executed strategic acquisitions to expand its operations into the Permian Basin of Texas and the Powder River Basin of Wyoming. See Note 2. Property Acquisitions and Dispositions
Basis of presentation of consolidated financial statements	Basis of presentation of consolidated financial statementsThe 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 (loss) and equity attributable to the noncontrolling interests are presented separately in the Company’s financial statements.
Use of Estimates	Use of estimatesThe 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	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, 2021, the Company had cash deposits in excess of federally insured amounts of approximately $19.4 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 writes off specific receivables when they become noncollectable and any payments subsequently received on those receivables are credited to the allowance for credit losses. Write-offs of noncollectable receivables have historically not been material. The Company’s allowance for credit losses totaled $2.8 million and $2.5 million as of December 31, 2021 and 2020, respectively. See Note 10. Allowance for Credit Losses
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, 2021, sales to the Company’s largest purchaser accounted for approximately 10% 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 2021. 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, 2021 and 2020 consisted of the following: December 31, In thousands 2021 2020 Tubular goods and equipment $ 12,506 $ 13,671 Crude oil 93,062 58,486 Total $ 105,568 $ 72,157 In the first quarter of 2020 the Company recognized a $24.5 million impairment to reduce its crude oil inventory to estimated net realizable value at the time of impairment. The impairment is included in the caption “Property impairments” in the consolidated statements of comprehensive income (loss) for the year ended December 31, 2020.
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 and repairs 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 Automobiles and aircraft 5-10 Machinery and equipment 6-20 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 impairmentProved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Impairment losses for unproved properties are generally recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The Company’s impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management.
Debt Issuance Costs	Debt issuance costsCosts incurred in connection with the execution of the Company’s notes payable and revolving credit facility and any amendments thereto are capitalized and amortized over the terms of the arrangements on a straight-line basis, the use of which approximates the effective interest method. Costs incurred upon the issuances of the Company’s various senior notes (collectively, the “Notes”) were capitalized and are being amortized over the terms of the Notes using the effective interest method.
Derivative Instruments	Derivative instruments The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value with such amounts classified as current or long-term based on contractual settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income (loss) under the caption “Gain (loss) on derivative instruments, net.” See Note 6. Derivative Instruments for additional information.
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 7. 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, 2021 and 2020.
Income Taxes	Income taxes Income taxes are accounted for using the asset and 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. The Company establishes a valuation allowance if it believes it is more likely than not that some or all of its deferred tax assets will not be realized. Significant judgment is applied in evaluating the need for and the magnitude of appropriate valuation allowances against deferred tax assets. See Note 11. Income Taxes for additional information.
Earnings Per Share	Earnings per share attributable to Continental ResourcesBasic net income (loss) per share is computed by dividing net income (loss) attributable to the Company by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method.
Foreign Currency Transactions and Translations Policy	Foreign currency translation In 2014, the Company initiated operations in Canada through a wholly-owned Canadian subsidiary. The Company’s operations in Canada were immaterial and were sold in the fourth quarter of 2019. See Note 11. Income Taxes and Note 2. Property Acquisitions and 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 (loss), net of tax” in the consolidated statements of comprehensive income (loss).
New Accounting Pronouncements	Adoption of new accounting pronouncement On January 1, 2021 the Company adopted ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. This standard eliminated 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 clarified certain aspects of the existing guidance, among other things. The Company adopted the standard on a prospective basis, which did not have a material impact on its financial position, results of operations, or cash flows.
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 $185.1 million, $159.0 million, and $192.0 million for the years ended December 31, 2021, 2020, and 2019, 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, in periods of significantly depressed prices for natural gas and NGLs the contractual pricing adjustments applied by the midstream customer in a particular month may exceed the consideration to be received by the Company under the arrangement, resulting in a net payment owed by the Company to the midstream customer. In these situations, the net amounts paid or payable by the Company are reflected as a reduction of natural gas sales in the caption "Crude oil and natural gas sales" in the consolidated statements of comprehensive income (loss). Such payments, which are referred to herein as negative gas revenues, were immaterial for 2021 and 2019 and totaled $25.6 million for operated properties for 2020. Under certain arrangements, the Company has the right to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of the Company's operated natural gas production. When the Company elects to take volumes in kind, it pays third parties to transport the processed products it took in-kind to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, operated revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Operated sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, the Company's revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula, but exclude the transportation expenses the Company incurs to transport the processed products to downstream customers. Transportation expenses associated with these arrangements totaled $39.9 million, $37.7 million, and $33.7 million for the years ended December 31, 2021, 2020, and 2019, 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. In periods of significantly depressed prices for natural gas and NGLs the costs incurred by the outside operator in a particular month may exceed the consideration to be received by the Company, resulting in a net payment owed by the Company to the outside operator. In these situations, the net amounts paid or payable by the Company are reflected as a reduction of natural gas sales in the caption "Crude oil and natural gas sales" in the consolidated statements of comprehensive income (loss). Such negative gas revenues associated with non-operated properties were immaterial for 2021 and 2019 and totaled $17.3 million for 2020. Revenues from derivative instruments – See Note 6. Derivative Instruments for discussion of the Company's accounting for its derivative instruments.

Revenue from Contract with Cust

Revenue from Contract with Customer (Policies)	12 Months Ended
Revenue from Contract with Customer (Policies)	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
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 $185.1 million, $159.0 million, and $192.0 million for the years ended December 31, 2021, 2020, and 2019, 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, in periods of significantly depressed prices for natural gas and NGLs the contractual pricing adjustments applied by the midstream customer in a particular month may exceed the consideration to be received by the Company under the arrangement, resulting in a net payment owed by the Company to the midstream customer. In these situations, the net amounts paid or payable by the Company are reflected as a reduction of natural gas sales in the caption "Crude oil and natural gas sales" in the consolidated statements of comprehensive income (loss). Such payments, which are referred to herein as negative gas revenues, were immaterial for 2021 and 2019 and totaled $25.6 million for operated properties for 2020. Under certain arrangements, the Company has the right to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of the Company's operated natural gas production. When the Company elects to take volumes in kind, it pays third parties to transport the processed products it took in-kind to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, operated revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Operated sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, the Company's revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula, but exclude the transportation expenses the Company incurs to transport the processed products to downstream customers. Transportation expenses associated with these arrangements totaled $39.9 million, $37.7 million, and $33.7 million for the years ended December 31, 2021, 2020, and 2019, 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. In periods of significantly depressed prices for natural gas and NGLs the costs incurred by the outside operator in a particular month may exceed the consideration to be received by the Company, resulting in a net payment owed by the Company to the outside operator. In these situations, the net amounts paid or payable by the Company are reflected as a reduction of natural gas sales in the caption "Crude oil and natural gas sales" in the consolidated statements of comprehensive income (loss). Such negative gas revenues associated with non-operated properties were immaterial for 2021 and 2019 and totaled $17.3 million for 2020. Revenues from derivative instruments – See Note 6. Derivative Instruments for discussion of the Company's accounting for its derivative instruments.

Organization and Summary of S_3

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Components of Inventories	The components of inventory as of December 31, 2021 and 2020 consisted of the following: December 31, In thousands 2021 2020 Tubular goods and equipment $ 12,506 $ 13,671 Crude oil 93,062 58,486 Total $ 105,568 $ 72,157
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 Automobiles and aircraft 5-10 Machinery and equipment 6-20 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, 2019 through December 31, 2021: In thousands 2021 2020 2019 Asset retirement obligations at January 1 $ 179,676 $ 153,673 $ 141,360 Accretion expense 11,125 9,393 8,443 Revisions (1) (1,291) 10,743 (1,762) Plus: Additions for new assets (2) 32,351 7,048 8,392 Less: Plugging costs and sold assets (2,037) (1,181) (2,760) Total asset retirement obligations at December 31 $ 219,824 $ 179,676 $ 153,673 Less: Current portion of asset retirement obligations at December 31 (3) 4,123 2,482 1,899 Non-current portion of asset retirement obligations at December 31 $ 215,701 $ 177,194 $ 151,774 (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 for 2021 includes $21.4 million of asset retirement obligations recognized in conjunction with the 2021 property acquisitions discussed in Note 2. Property Acquisitions and Dispositions .
Calculation of Basic and Diluted Weighted Average Shares and Net Income per Share	The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share attributable to the Company for the years ended December 31, 2021, 2020 and 2019. Year ended December 31, In thousands, except per share data 2021 2020 2019 Net income (loss) attributable to Continental Resources (numerator) $ 1,660,968 $ (596,869) $ 775,641 Weighted average shares (denominator): Weighted average shares - basic 360,434 361,538 370,699 Non-vested restricted stock (1) 4,019 — 1,839 Weighted average shares - diluted 364,453 361,538 372,538 Net income (loss) per share attributable to Continental Resources: Basic $ 4.61 $ (1.65) $ 2.09 Diluted $ 4.56 $ (1.65) $ 2.08 (1) For the year ended December 31, 2020, the Company had a net loss and therefore the potential dilutive effect of approximately 934,000 weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computation.

Property Acquisitions and Dis_2

Property Acquisitions and Dispositions (Tables)	12 Months Ended
Property Acquisitions and Dispositions (Tables)	Dec. 31, 2021
Business Combination and Asset Acquisition [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The Company will finalize the purchase price allocation during the twelve-month period following the acquisition date, during which time the value of the assets and liabilities presented below may be revised if necessary. In millions As of December 21, 2021 Receivables $ 3 Proved crude oil and natural gas properties 2,396 Unproved crude oil and natural gas properties 693 Service properties, equipment and other 6 Operating lease right-of-use assets 2 Total assets acquired $ 3,100 Revenues and royalties payable $ 14 Accrued liabilities and other 8 Operating lease liabilities 2 Asset retirement obligations 16 Total liabilities assumed $ 40 Net assets acquired $ 3,060
Business Acquisition, Pro Forma Information	The table below summarizes the Company's pro forma results as if the Pioneer Acquisition and associated increase in debt described in Note 8. Long-Term Debt had been completed on January 1, 2020 and were combined with the Company's historical results. The following pro forma information is unaudited, is provided for informational purposes only, and does not represent actual results that would have occurred if the Pioneer Acquisition was completed on January 1, 2020, nor are they indicative of future results. Year Ended December 31, In millions 2021 2020 Pro forma combined total revenues $ 6,657 $ 3,174 Pro forma combined net income (loss) attributable to Continental $ 2,097 $ (481)

Net Property and Equipment (Tab

Net Property and Equipment (Tables)	12 Months Ended
Net Property and Equipment (Tables)	Dec. 31, 2021
Property, Plant and Equipment, Net [Abstract]
Schedule of Net Property and Equipment	Net property and equipment includes the following at December 31, 2021 and 2020. See Note 2. Property Acquisitions and Dispositions for discussion of certain acquisitions executed in 2021 that contributed to the increase in net property and equipment in 2021. December 31, In thousands 2021 2020 Proved crude oil and natural gas properties $ 31,613,656 $ 27,726,954 Unproved crude oil and natural gas properties 1,358,673 368,256 Service properties, equipment and other 484,989 414,066 Total property and equipment 33,457,318 28,509,276 Accumulated depreciation, depletion and amortization (16,481,853) (14,771,984) Net property and equipment $ 16,975,465 $ 13,737,292

Accrued Liabilities and Other (

Accrued Liabilities and Other (Tables)	12 Months Ended
Accrued Liabilities and Other (Tables)	Dec. 31, 2021
Accrued Liabilities and Other Liabilities [Abstract]
Schedule of Accrued Liabilities and Other	Accrued liabilities and other includes the following at December 31, 2021 and 2020: December 31, In thousands 2021 2020 Prepaid advances from joint interest owners $ 18,964 $ 25,209 Accrued compensation 82,844 47,985 Accrued production taxes, ad valorem taxes and other non-income taxes 90,597 40,818 Accrued interest 75,983 50,009 Current portion of asset retirement obligations 4,123 2,482 Other 13,229 510 Accrued liabilities and other $ 285,740 $ 167,013

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
Derivative Instruments (Tables)	Dec. 31, 2021
Derivative [Line Items]
Schedule of Derivative Instruments	At December 31, 2021 the Company had outstanding derivative contracts as set forth in the tables below. Natural gas derivatives Weighted Average Hedge Price ($/MMBtu) Period and Type of Contract Average Volumes Hedged Basis Swaps Swaps Sold Put Floor Ceiling January 2022 - December 2023 Basis Swaps - NGPL TXOK 75,000 MMBtus/day $ (0.17) January 2022 - March 2022 Collars - Henry Hub 90,000 MMBtus/day $ 3.00 $ 6.33 Three-way collars - Henry Hub 280,000 MMBtus/day $ 2.33 $ 3.02 $ 4.46 Swaps - Henry Hub 45,000 MMBtus/day $ 3.86 April 2022 - September 2022 Swaps - Henry Hub 190,000 MMBtus/day $ 4.02 October 2022 - December 2022 Collars - Henry Hub 150,000 MMBtus/day $ 3.54 $ 5.34 Three-way collars - Henry Hub 50,000 MMBtus/day $ 3.00 $ 4.07 $ 5.00 Swaps - Henry Hub 50,000 MMBtus/day $ 4.20 January 2023 - December 2023 Collars - Henry Hub 62,500 MMBtus/day $ 3.41 $ 4.87 Three-way collars - Henry Hub 12,500 MMBtus/day $ 3.00 $ 4.32 $ 5.00 Swaps - Henry Hub 175,000 MMBtus/day $ 3.38 January 2024 - December 2024 Swaps - Henry Hub 125,000 MMBtus/day $ 3.12 Collars - Henry Hub 25,000 MMBtus/day $ 3.10 $ 4.18 January 2025 - December 2025 Swaps - Henry Hub 10,000 MMBtus/day $ 3.08 Crude oil derivatives Period and Type of Contract Average Volumes Hedged Weighted Average Hedge Price ($/Bbl) January 2022 - March 2022 NYMEX Roll Swaps 32,500 Bbls/day $ 0.71 April 2022 - June 2022 NYMEX Roll Swaps 15,000 Bbls/day $ 0.85 July 2022 - December 2022 NYMEX Roll Swaps 7,500 Bbls/day $ 0.90
Realized and Unrealized Gains and Losses on Derivative Instruments	Year ended December 31, In thousands 2021 2020 2019 Cash received (paid) on derivatives: Crude oil fixed price swaps $ (44,463) $ (31,179) $ — Crude oil collars (9,365) — — Crude oil NYMEX roll swaps (163) — — Natural gas fixed price swaps (84,141) 1,071 58,836 Natural gas collars (11,546) 1,958 5,859 Cash received (paid) on derivatives, net (149,678) (28,150) 64,695 Non-cash gain (loss) on derivatives: Crude oil collars 227 (227) — Crude oil NYMEX roll swaps 957 — — Natural gas fixed price swaps 25,565 2,043 (10,130) Natural gas basis swaps (177) — — Natural gas collars (7,690) 11,676 (5,482) Natural gas three-way collars 1,932 — — Non-cash gain (loss) on derivatives, net 20,814 13,492 (15,612) Gain (loss) on derivative instruments, net $ (128,864) $ (14,658) $ 49,083
Balance sheet offsetting of derivative assets and liabilities	The following table presents the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets at December 31, 2021, all at fair value. December 31, In thousands 2021 2020 Commodity derivative assets: Gross amounts of recognized assets $ 42,903 $ 15,900 Gross amounts offset on balance sheet (7,381) (597) Net amounts of assets on balance sheet 35,522 15,303 Commodity derivative liabilities: Gross amounts of recognized liabilities (8,598) (2,408) Gross amounts offset on balance sheet 7,381 597 Net amounts of liabilities on balance sheet $ (1,217) $ (1,811)
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 2021 2020 Derivative assets $ 22,334 $ 15,303 Derivative assets, noncurrent 13,188 — Net amounts of assets on balance sheet 35,522 15,303 Derivative liabilities (899) (227) Derivative liabilities, noncurrent (318) (1,584) Net amounts of liabilities on balance sheet (1,217) (1,811) Total derivative assets, net $ 34,305 $ 13,492

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
Fair Value Measurements (Tables)	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Valuation of Financial Instruments by Pricing Levels	The following tables summarize the valuation of derivative instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31, 2021 and 2020. Fair value measurements at December 31, 2021 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Fixed price swaps $ — $ 27,608 $ — $ 27,608 Basis swaps — (177) — (177) Collars — 3,986 — 3,986 Three-way collars — 1,931 — 1,931 NYMEX roll swaps — 957 — 957 Total $ — $ 34,305 $ — $ 34,305
Unobservable inputs used in level 3 fair value measurements	Unobservable inputs to the Company's fair value assessments are reviewed and 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 year ended December 31, 2021, estimated future net cash flows were determined to be in excess of cost basis, and therefore no impairment was recorded for the Company's proved crude oil and natural gas properties in 2021.
Property Impairments	The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the consolidated statements of comprehensive income (loss). Year ended December 31, In thousands 2021 2020 2019 Proved property and inventory impairments $ — $ 207,119 $ 3,745 Unproved property impairments 38,370 70,822 82,457 Total $ 38,370 $ 277,941 $ 86,202
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. See Note 8. Long-Term Debt for discussion of the changes in the Company's outstanding debt during the year ended December 31, 2021. December 31, 2021 December 31, 2020 In thousands Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Debt: Credit facility $ 500,000 $ 500,000 $ 160,000 $ 160,000 Notes payable 22,356 22,000 24,590 24,700 5% Senior Notes due 2022 — — 630,470 632,900 4.5% Senior Notes due 2023 648,078 670,200 646,943 669,900 3.8% Senior Notes due 2024 908,061 950,000 906,922 939,500 2.268% Senior Notes due 2026 792,621 795,200 — — 4.375% Senior Notes due 2028 991,880 1,082,100 990,746 1,024,400 5.75% Senior Notes due 2031 1,482,319 1,769,600 1,480,879 1,651,900 2.875% Senior Notes due 2032 791,521 780,500 — — 4.9% Senior Notes due 2044 692,056 781,500 691,868 689,600 Total debt $ 6,828,892 $ 7,351,100 $ 5,532,418 $ 5,792,900

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
Long-Term Debt (Tables)	Dec. 31, 2021
Debt Disclosure [Abstract]
Long-Term Debt	Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $54.2 million and $43.7 million at December 31, 2021 and 2020, respectively, consists of the following. December 31, In thousands 2021 2020 Credit facility $ 500,000 $ 160,000 Notes payable 22,356 24,590 5% Senior Notes due 2022 — 630,470 4.5% Senior Notes due 2023 648,078 646,943 3.8% Senior Notes due 2024 908,061 906,922 2.268% Senior Notes due 2026 792,621 — 4.375% Senior Notes due 2028 991,880 990,746 5.75% Senior Notes due 2031 1,482,319 1,480,879 2.875% Senior Notes due 2032 791,521 — 4.9% Senior Notes due 2044 692,056 691,868 Total debt 6,828,892 5,532,418 Less: Current portion of long-term debt 2,326 2,245 Long-term debt, net of current portion $ 6,826,566 $ 5,530,173
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, 2021. 2023 Notes 2024 Notes 2026 Notes 2028 Notes 2031 Notes 2032 Notes 2044 Notes Face value (in thousands) $649,625 $911,000 $800,000 $1,000,000 $1,500,000 $800,000 $700,000 Maturity date April 15, 2023 June 1, 2024 November 15, 2026 January 15, 2028 January 15, 2031 April 1, 2032 June 1, 2044 Interest payment dates April 15, Oct 15 June 1, Dec 1 May 15, Nov 15 Jan 15, July 15 Jan 15, April 1, Oct 1 June 1, Dec 1 Make-whole redemption period (1) Jan 15, 2023 Mar 1, 2024 Nov 15, 2023 Oct 15, 2027 Jul 15, 2030 January 1. 2032 Dec 1, 2043 (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 (Tables)

Revenues (Tables)	12 Months Ended
Revenues (Tables)	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
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, 2021 2020 2019 In thousands North Region South Region Total North Region South Region Total North Region South Region Total Crude oil revenues: Operated properties $ 2,392,465 $ 838,129 $ 3,230,594 $ 1,264,149 $ 537,961 $ 1,802,110 $ 2,365,574 $ 786,652 $ 3,152,226 Non-operated properties 656,727 61,973 718,700 362,952 34,914 397,866 727,068 50,700 777,768 Total crude oil revenues 3,049,192 900,102 3,949,294 1,627,101 572,875 2,199,976 3,092,642 837,352 3,929,994 Natural gas revenues: Operated properties (1) 460,376 1,186,937 1,647,313 28,086 301,486 329,572 109,668 411,464 521,132 Non-operated properties (2) 115,420 81,714 197,134 720 25,166 25,886 25,188 38,075 63,263 Total natural gas revenues 575,796 1,268,651 1,844,447 28,806 326,652 355,458 134,856 449,539 584,395 Crude oil and natural gas sales $ 3,624,988 $ 2,168,753 $ 5,793,741 $ 1,655,907 $ 899,527 $ 2,555,434 $ 3,227,498 $ 1,286,891 $ 4,514,389 Timing of revenue recognition Goods transferred at a point in time $ 3,624,988 $ 2,168,753 $ 5,793,741 $ 1,655,907 $ 899,527 $ 2,555,434 $ 3,227,498 $ 1,286,891 $ 4,514,389 Goods transferred over time — — — — — — — — — $ 3,624,988 $ 2,168,753 $ 5,793,741 $ 1,655,907 $ 899,527 $ 2,555,434 $ 3,227,498 $ 1,286,891 $ 4,514,389

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
Income Taxes (Tables)	Dec. 31, 2021
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 2021 2020 2019 Current income tax provision (benefit): United States federal $ — $ (2,248) $ — Various states — 29 — Total current income tax provision (benefit) — (2,219) — Deferred income tax provision (benefit): United States federal 467,051 (148,828) 191,328 Various states 52,679 (18,143) 21,361 Total deferred income tax provision (benefit) 519,730 (166,971) 212,689 Provision (benefit) for income taxes $ 519,730 $ (169,190) $ 212,689 Effective tax rate 23.8 % 21.8 % 21.5 %
Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate	Year ended December 31, In thousands, except tax rates 2021 2020 2019 Income (loss) before income taxes $ 2,186,138 $ (774,751) $ 987,162 U.S. federal statutory tax rate 21.0 % 21.0 % 21.0 % Expected income tax provision (benefit) based on U.S. federal statutory tax rate 459,089 (162,698) 207,304 Items impacting the effective tax rate: State and local income taxes, net of federal benefit 77,979 (24,808) 31,967 Tax (benefit) deficiency from stock-based compensation 5,869 4,927 (7,971) Sale of Canadian subsidiary and assets — — (16,860) Other, net (8,733) (1,085) (1,751) Change in valuation allowance (14,474) 14,474 — Provision (benefit) for income taxes $ 519,730 $ (169,190) $ 212,689 Effective tax rate 23.8 % 21.8 % 21.5 %
Components of Deferred Tax Assets and Liabilities	The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2021 and 2020 are reflected in the table below. December 31, In thousands 2021 2020 Deferred tax assets United States net operating loss carryforwards $ 365,602 $ 579,781 Equity compensation 12,751 12,900 Other 29,421 10,691 Total deferred tax assets 407,774 603,372 Valuation allowance — (14,474) Total deferred tax assets, net of valuation allowance 407,774 588,898 Deferred tax liabilities Property and equipment (2,536,938) (2,204,378) Other (10,720) (4,674) Total deferred tax liabilities (2,547,658) (2,209,052) Deferred income tax liabilities, net $ (2,139,884) $ (1,620,154)

Leases Leases (Tables)

Leases Leases (Tables)	12 Months Ended
Leases Leases (Tables)	Dec. 31, 2021
Leases [Abstract]
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	Minimum future commitments by year for the Company's operating leases as of December 31, 2021 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 2022 $ 2,369 2023 2,263 2024 1,831 2025 1,295 2026 1,258 Thereafter 13,084 Total operating lease liabilities, at undiscounted value $ 22,100 Less: Imputed interest (6,626) Total operating lease liabilities, at discounted present value $ 15,474 Less: Current portion of operating lease liabilities (1,674) Operating lease liabilities, net of current portion $ 13,800
Lease, Cost [Table Text Block]	Year ended December 31, In thousands, except weighted average data 2021 2020 2019 Lease costs: Operating lease costs $ 6,653 $ 6,444 $ 11,130 Variable lease costs 3,271 4,956 11,930 Short-term lease costs 77,551 107,984 176,586 Total lease costs $ 87,475 $ 119,384 $ 199,646 Other information: Right-of-use assets obtained in exchange for new operating lease liabilities (1) $ 10,481 $ 7,377 $ 1,208 Operating cash flows from operating leases included in lease liabilities 1,731 890 804 Weighted average remaining lease term as of December 31 (in years) 14.4 13.2 11.5 Weighted average discount rate as of December 31 5.0 % 4.8 % 4.9 %

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
Stock-Based Compensation (Tables)	Dec. 31, 2021
Stock-Based Compensation Expense	The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the consolidated statements of comprehensive income (loss), was $63.2 million, $64.6 million, and $52.0 million for the years ended December 31, 2021, 2020, and 2019, 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, 2018 to December 31, 2021 is presented below. Number of Weighted 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 Granted 2,738,625 26.93 Vested (1,146,618) 45.78 Forfeited (163,277) 36.69 Non-vested restricted shares at December 31, 2020 4,890,638 $ 36.26 Granted 3,050,491 24.73 Vested (1,750,483) 44.36 Forfeited (296,138) 26.61 Non-vested restricted shares at December 31, 2021 5,894,508 $ 28.38

Shareholders' Equity Attribut_2

Shareholders' Equity Attributable to Continental Resources (Tables)	12 Months Ended
	Dec. 31, 2021
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 for the year ended December 31, 2019. In thousands 2019 Beginning accumulated other comprehensive income, net of tax $ 415 Foreign currency translation adjustments 140 Release of cumulative translation adjustments (1) (555) Income taxes (2) — Other comprehensive income (loss), net of tax (415) Ending accumulated other comprehensive income, net of tax $ — (1) In conjunction with the Company’s sale of its Canadian operations in 2019, the cumulative translation adjustments were released. See Note 2. Property Acquisitions and 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
Crude Oil and Natural Gas Property Information (Tables)	Dec. 31, 2021
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, 2021, 2020 and 2019. Year ended December 31, In thousands 2021 2020 2019 Crude oil and natural gas sales $ 5,793,741 $ 2,555,434 $ 4,514,389 Production expenses (406,906) (359,267) (444,649) Production taxes (404,362) (192,718) (357,988) Transportation expenses (224,989) (196,692) (225,649) Exploration expenses (21,047) (17,732) (14,667) Depreciation, depletion, amortization and accretion (1,872,075) (1,859,893) (1,997,854) Property impairments (38,370) (277,941) (86,202) Income tax (provision) benefit (1) (690,902) 83,427 (323,025) Results from crude oil and natural gas producing activities $ 2,135,090 $ (265,382) $ 1,064,355
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, 2021, 2020 and 2019 are presented below. See Note 2. Property Acquisitions and Dispositions for discussion of notable property acquisitions executed in 2021 that gave rise to the significant increase in costs incurred and aggregate capitalized costs in the current year. Year ended December 31, In thousands 2021 2020 2019 Property acquisition costs: Proved $ 2,580,271 $ 60,494 $ 51,558 Unproved 1,197,507 201,919 312,680 Total property acquisition costs 3,777,778 262,413 364,238 Exploration Costs 171,549 48,282 50,143 Development Costs 1,174,828 1,053,532 2,388,582 Total $ 5,124,155 $ 1,364,227 $ 2,802,963
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, 2021 and 2020 are as follows: December 31, In thousands 2021 2020 Proved crude oil and natural gas properties $ 31,613,656 $ 27,726,954 Unproved crude oil and natural gas properties 1,358,673 368,256 Total 32,972,329 28,095,210 Less accumulated depreciation, depletion and amortization (16,310,054) (14,622,376) Net capitalized costs $ 16,662,275 $ 13,472,834
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 2021 2020 2019 Balance at January 1 $ 32,737 $ 6,257 $ 3,959 Additions to capitalized exploratory well costs pending determination of proved reserves 122,068 32,880 28,280 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves (117,131) (72) (23,200) Capitalized exploratory well costs charged to expense (1) (6,328) (2,782) Balance at December 31 $ 37,673 $ 32,737 $ 6,257 Number of gross wells 17 16 11

Supplemental Crude Oil and Na_2

Supplemental Crude Oil and Natural Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2021
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, 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 (249,845) (1,530,174) (504,874) Extensions, discoveries and other additions 42,106 295,686 91,387 Production (58,745) (306,528) (109,833) Sales of minerals in place — — — Purchases of minerals in place 3,272 27,269 7,817 Proved reserves as of December 31, 2020 496,975 3,640,724 1,103,762 Revisions of previous estimates 14,574 233,966 53,569 Extensions, discoveries and other additions 165,268 1,235,022 371,105 Production (58,636) (370,110) (120,321) Sales of minerals in place (70) (469) (148) Purchases of minerals in place 175,419 371,546 237,343 Proved reserves as of December 31, 2021 793,530 5,110,679 1,645,310
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, 2021, 2020 and 2019: December 31, 2021 2020 2019 Proved Developed Reserves Crude oil (MBbl) 424,153 281,906 336,405 Natural Gas (MMcf) 2,901,147 2,073,011 2,226,117 Total (MBoe) 907,678 627,407 707,424 Proved Undeveloped Reserves Crude oil (MBbl) 369,377 215,069 423,782 Natural Gas (MMcf) 2,209,532 1,567,713 2,928,354 Total (MBoe) 737,632 476,355 911,841 Total Proved Reserves Crude oil (MBbl) 793,530 496,975 760,187 Natural Gas (MMcf) 5,110,679 3,640,724 5,154,471 Total (MBoe) 1,645,310 1,103,762 1,619,265
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, 2021, 2020, and 2019. 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 2021 2020 2019 Future cash inflows $ 67,034,046 $ 21,334,235 $ 49,893,470 Future production costs (18,837,000) (7,750,834) (15,309,672) Future development and abandonment costs (7,751,678) (3,950,752) (10,033,887) Future income taxes (1) (7,862,849) (724,569) (3,351,657) Future net cash flows 32,582,519 8,908,080 21,198,254 10% annual discount for estimated timing of cash flows (15,946,126) (4,254,515) (10,736,613) Standardized measure of discounted future net cash flows $ 16,636,393 $ 4,653,565 $ 10,461,641
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 2021 2020 2019 Standardized measure of discounted future net cash flows at January 1 $ 4,653,565 $ 10,461,641 $ 15,684,817 Extensions, discoveries and improved recoveries, less related costs 2,985,056 187,981 1,649,322 Revisions of previous quantity estimates 816,674 (2,952,489) (1,564,503) Changes in estimated future development and abandonment costs 706,168 4,760,286 1,401,513 Purchases (sales) of minerals in place, net 3,408,365 53,742 49,330 Net change in prices and production costs 9,396,945 (6,912,031) (6,591,347) Accretion of discount 489,273 1,183,993 1,865,034 Sales of crude oil and natural gas produced, net of production costs (4,757,483) (1,806,758) (3,486,103) Development costs incurred during the period 683,212 863,101 1,557,121 Change in timing of estimated future production and other 1,871,903 (2,325,024) (1,690,779) Change in income taxes (3,617,285) 1,139,123 1,587,236 Net change 11,982,828 (5,808,076) (5,223,176) Standardized measure of discounted future net cash flows at December 31 $ 16,636,393 $ 4,653,565 $ 10,461,641

Organization and Summary of S_4

Organization and Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Organization And Summary Of Significant Accounting Policies [Line Items]
Allowance for credit losses	$ 2,800	$ 2,500
Unamortized Debt Issuance Expense	50,900	42,500
Cash deposits in excess of federally insured amounts	19,400
Net asset retirement costs	72,800	56,100
Capitalized debt issue costs, relating to long-term debt	60,600	45,800
Accumulated amortization, relating to capitalized debt issue costs	36,900	30,500
Amortization expense related to capitalized debt issuance costs	$ 7,200	7,800	$ 8,300
Concentration Risk, Customer	10
Allowance for credit losses	$ (2,814)	(2,462)
Inventory Valuation and Obsolescence [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Inventory Write-down		24,500
Revolving Credit Facility [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Unamortized Debt Issuance Expense	$ 9,700	$ 3,300
Customer one concentration [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Concentration Risk, Customer	10

Organization and Summary of S_5

Organization and Summary of Significant Accounting Policies - Components of Inventories (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Tubular goods and equipment	$ 12,506	$ 13,671
Crude oil	93,062	58,486
Total	$ 105,568	$ 72,157

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, 2021
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)	20 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, 2021	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at January 1		$ 179,676	$ 153,673	$ 141,360
Accretion expense		11,125	9,393	8,443
Revisions	[1]	(1,291)	10,743	(1,762)
Plus: Additions for new assets	[2]	32,351	7,048	8,392
Less: Plugging costs and sold assets		(2,037)	(1,181)	(2,760)
Total asset retirement obligations at December 31		219,824	179,676	153,673
Less: Current portion of asset retirement obligations at December 31	[3]	4,123	2,482	1,899
Non-current portion of asset retirement obligations at December 31		$ 215,701	$ 177,194	$ 151,774

[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 for 2021 includes $21.4 million of asset retirement obligations recognized in conjunction with the 2021 property acquisitions discussed in Note 2. Property Acquisitions and Dispositions
[3]	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, $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020		Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Sale of Canadian subsidiary and assets	$ 0	$ 0		$ (16,860)
Income (numerator):
Net income (loss) attributable to Continental Resources	$ 1,660,968	$ (596,869)		$ 775,641
Weighted average shares - basic	360,434	361,538		370,699
Non-vested restricted stock	4,019	0	[1]	1,839
Weighted average shares - diluted	364,453	361,538		372,538
Net income per share:
Basic (in dollars per share)	$ 4.61	$ (1.65)		$ 2.09
Diluted (in dollars per share)	$ 4.56	$ (1.65)		$ 2.08
Weighted Average Number Diluted Shares Outstanding Adjustment		934

[1]	For the year ended December 31, 2020, the Company had a net loss and therefore the potential dilutive effect of approximately 934,000 weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computation.

Property Acquisitions and Dis_3

Property Acquisitions and Dispositions (Details)	Dec. 31, 2021USD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 21, 2021USD ($)aBoe
Business Combination and Asset Acquisition [Abstract]
Business combination net leasehold acres acquired \| a					92,000
Business combination net royalty acres acquired \| a					50,000
Business combination net production BOE per day \| Boe					42,000
Payments to Acquire Businesses, Gross		$ 3,060,000,000
Business combination purchase price prior to closing adjustments		3,250,000,000
Receivables					$ 3,000,000
Proved crude oil and natural gas properties					2,396,000,000
Unproved crude oil and natural gas properties					693,000,000
Service properties, equipment and other					6,000,000
Operating lease right-of-use assets					2,000,000
Total assets acquired					3,100,000,000
Revenues and royalties payable					14,000,000
Accrued liabilities and other					8,000,000
Operating lease liabilities					2,000,000
Asset retirement obligations					16,000,000
Total liabilities assumed					40,000,000
Net assets acquired					$ 3,060,000,000
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual	$ 29,400,000
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual	14,100,000
Business Acquisition Pro forma net income basic and diluted per share, actual contribution of acquired assets	0.04
Business Acquisition, Transaction Costs	$ 13,900,000	$ 13,900,000	$ 13,900,000
Business Acquisition, Pro Forma Revenue			6,657	$ 3,174
Business Acquisition, Pro Forma Net Income (Loss)			$ 2,097	$ (481)

Property Acquisitions, Asset Ac

Property Acquisitions, Asset Acquisitions and Dispositions (Details) $ in Thousands		3 Months Ended		12 Months Ended
		Dec. 31, 2021USD ($)	Mar. 31, 2021USD ($)a	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Nov. 30, 2021aBoe
Asset Acquisition and Disposition [Line Items]
Costs Incurred, Acquisition of Oil and Gas Properties				$ 3,777,778	$ 262,413	$ 364,238
Proceeds from Sale of Oil and Gas Property and Equipment						85,300
Gain (Loss) on Disposition of Property Plant Equipment				$ (5,146)	187	(535)
Translation Adjustment Functional to Reporting Currency, Gain (Loss), Reclassified to Earnings, Net of Tax	[1]					555
Escrow deposit per PSA					21,500
Remaining payment made at asset acquisition closing			$ 185,100
Asset acquisition net leasehold acres acquired \| a							72,000
Asset acquisition net production BOE per day \| Boe							7,200
SCOOP [Member]
Asset Acquisition and Disposition [Line Items]
Costs Incurred, Acquisition of Oil and Gas Properties					$ 162,800
CANADA
Asset Acquisition and Disposition [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment						1,700
Gain (Loss) on Disposition of Property Plant Equipment						1,000
Translation Adjustment Functional to Reporting Currency, Gain (Loss), Reclassified to Earnings, Net of Tax						$ 500
Powder River Basin
Asset Acquisition and Disposition [Line Items]
Costs Incurred, Acquisition of Oil and Gas Properties		$ 246,800	206,600
Asset acquisition recognition of proved crude oil and natural gas properties		27,000	183,000
Asset acquisition recognition of unproved crude oil and natural gas properties		220,000	$ 24,000
Asset acquisition net leasehold acres acquired \| a			130,000
Asset acquisition recognition of asset retirement obligation		$ 500	$ 4,900
Asset acquisition recognition of right of use assets			$ 8,200

[1]	In conjunction with the Company’s sale of its Canadian operations in 2019, the cumulative translation adjustments were released. See Note 2. Property Acquisitions and Dispositions for further information.

Net Property and Equipment - Sc

Net Property and Equipment - Schedule of Net Property and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment, Net [Abstract]
Proved crude oil and natural gas properties	$ 31,613,656	$ 27,726,954
Unproved crude oil and natural gas properties	1,358,673	368,256
Service properties, equipment and other	484,989	414,066
Total property and equipment	33,457,318	28,509,276
Accumulated depreciation, depletion and amortization	(16,481,853)	(14,771,984)
Net property and equipment	$ 16,975,465	$ 13,737,292

Accrued Liabilities and Other -

Accrued Liabilities and Other - Schedule of Accrued Liabilities and Other (Detail) - USD ($) $ in Thousands		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accrued Liabilities and Other Liabilities [Abstract]
Prepaid advances from joint interest owners		$ 18,964	$ 25,209
Accrued compensation		82,844	47,985
Accrued production taxes, ad valorem taxes and other non-income taxes		90,597	40,818
Accrued interest		75,983	50,009
Current portion of asset retirement obligations	[1]	4,123	2,482	$ 1,899
Other		13,229	510
Accrued liabilities and other		$ 285,740	$ 167,013

[1]	Balance is included in the caption “Accrued liabilities and other” in the consolidated balance sheets

Derivative Instruments - Summar

Derivative Instruments - Summary of Outstanding Contracts with Respect to Crude Oil (Detail) - Crude Oil [Member]	12 Months Ended
	Dec. 31, 2021$ / bblbbl
Jan22 to Mar22 NYMEX Roll Swaps
Derivative [Line Items]
Crude oil production volume hedged \| bbl	32,500
Derivative, Swap Type, Average Fixed Price \| $ / bbl	0.71
April22 to June22 NYMEX Roll Swaps
Derivative [Line Items]
Crude oil production volume hedged \| bbl	15,000
Derivative, Swap Type, Average Fixed Price \| $ / bbl	0.85
July22 to Dec22 NYMEX Roll Swaps
Derivative [Line Items]
Crude oil production volume hedged \| bbl	7,500
Derivative, Swap Type, Average Fixed Price \| $ / bbl	0.90

Derivative Instruments - Summ_2

Derivative Instruments - Summary of Outstanding Contracts with Respect to Natural Gas (Detail) - Natural Gas [Member]	12 Months Ended
	Dec. 31, 2021MMBTU$ / MMBTU
April 2022 to September 2022 Swaps
Derivative [Line Items]
Natural Gas Production Derivative Volume \| MMBTU	190,000
Derivative, Swap Type, Average Fixed Price	4.02
Oct 2022 to Dec 2022 Collars
Derivative [Line Items]
Natural Gas Production Derivative Volume \| MMBTU	150,000
Derivative, Average Floor Price	3.54
Derivative, Average Cap Price	5.34
Jan 2022 to Mar 2022 Three Way Collars
Derivative [Line Items]
Natural Gas Production Derivative Volume \| MMBTU	280,000
Derivative, Floor Price	2.33
Derivative, Average Floor Price	3.02
Derivative, Average Cap Price	4.46
Jan 2022 to March 2022 Collars
Derivative [Line Items]
Natural Gas Production Derivative Volume \| MMBTU	90,000
Derivative, Average Floor Price	3
Derivative, Average Cap Price	6.33
Jan 2022 to March 2022 Swaps
Derivative [Line Items]
Natural Gas Production Derivative Volume \| MMBTU	45,000
Derivative, Swap Type, Average Fixed Price	3.86
Oct 2022 to Dec 2022 Swaps
Derivative [Line Items]
Natural Gas Production Derivative Volume \| MMBTU	50,000
Derivative, Swap Type, Average Fixed Price	4.20
Oct2022 to Dec2022 Three-way Collars
Derivative [Line Items]
Natural Gas Production Derivative Volume \| MMBTU	50,000
Derivative, Floor Price	3
Derivative, Average Floor Price	4.07
Derivative, Average Cap Price	5
Jan23 to Dec23 Collar
Derivative [Line Items]
Natural Gas Production Derivative Volume \| MMBTU	62,500
Derivative, Average Floor Price	3.41
Derivative, Average Cap Price	4.87
Jan23 to Dec23 Three-way Collars
Derivative [Line Items]
Natural Gas Production Derivative Volume \| MMBTU	12,500
Derivative, Floor Price	3
Derivative, Average Floor Price	4.32
Derivative, Average Cap Price	5
Jan23 to Dec 23 Swaps
Derivative [Line Items]
Natural Gas Production Derivative Volume \| MMBTU	175,000
Derivative, Swap Type, Average Fixed Price	3.38
Jan24 to Dec 24 Swaps
Derivative [Line Items]
Natural Gas Production Derivative Volume \| MMBTU	125,000
Derivative, Swap Type, Average Fixed Price	3.12
Jan25 to Dec 25 Swaps
Derivative [Line Items]
Natural Gas Production Derivative Volume \| MMBTU	10,000
Derivative, Swap Type, Average Fixed Price	3.08
Jan24 to Dec24 Collar
Derivative [Line Items]
Natural Gas Production Derivative Volume \| MMBTU	25,000
Derivative, Average Floor Price	3.10
Derivative, Average Cap Price	4.18
Jan 2022 to Dec 2023 NGPL Basis Swaps
Derivative [Line Items]
Natural Gas Production Derivative Volume \| MMBTU	75,000
Derivative, Swap Type, Average Fixed Price	(0.17)

Derivative Instruments - Realiz

Derivative Instruments - Realized and Unrealized Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	$ 20,814	$ 13,492	$ (15,612)
Gain (loss) on derivative instruments, net	(128,864)	(14,658)	49,083
Fixed Price Swaps [Member] \| Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	(84,141)	1,071	58,836
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	25,565	2,043	(10,130)
Collars [Member] \| Crude Oil [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	(9,365)	0	0
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	227	(227)	0
Collars [Member] \| Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	(11,546)	1,958	5,859
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	(7,690)	11,676	(5,482)
Swap [Member] \| Crude Oil [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	(44,463)	(31,179)	0
NYMEX Roll Swaps \| Crude Oil [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	(163)	0	0
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	957	0	0
Basis Swaps \| Natural Gas [Member]
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	(177)	0	0
Three-way collars \| Natural Gas [Member]
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	1,932	0	0
Crude Oil and Natural Gas
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	(149,678)	(28,150)	64,695
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	20,814	13,492	(15,612)
Gain (loss) on derivative instruments, net	$ (128,864)	$ (14,658)	$ 49,083

Derivative Instruments Derivati

Derivative Instruments Derivative Instruments - Gross Amounts of Recognized Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Commodity derivative assets, Gross amounts of recognized assets	$ 42,903	$ 15,900
Commodity derivative assets, Gross amounts offset on balance sheet	(7,381)	(597)
Derivative assets, Net amounts of assets on balance sheet	35,522	15,303
Commodity derivative liability, Gross amounts of recognized liabilities	(8,598)	(2,408)
Commodity derivative liability, Gross amounts offset on balance sheet	7,381	597
Derivative liability, Net amounts of liabilities on balance sheet	$ (1,217)	$ (1,811)

Derivative Instruments Deriva_2

Derivative Instruments Derivative Instruments - Reconciles Net Amounts Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets	$ 22,334	$ 15,303
Derivative assets, noncurrent	13,188	0
Derivative assets, Net amounts of assets on balance sheet	35,522	15,303
Derivative liabilities	(899)	(227)
Derivative liabilities, noncurrent	(318)	(1,584)
Derivative liability, Net amounts of liabilities on balance sheet	(1,217)	(1,811)
Total derivative assets, net	$ 34,305	$ 13,492

Fair Value Measurements - Valua

Fair Value Measurements - Valuation of Financial Instruments by Pricing Levels (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Derivative assets (liabilities):
Derivative assets (liabilities)	$ 34,305	$ 13,492
Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	27,608	2,043
Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	3,986	11,449
Basis Swaps
Derivative assets (liabilities):
Derivative assets (liabilities)	(177)
Three-way collars
Derivative assets (liabilities):
Derivative assets (liabilities)	1,931
NYMEX Roll Swaps
Derivative assets (liabilities):
Derivative assets (liabilities)	957
Fair Value, Inputs, Level 1 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 1 [Member] \| Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 1 [Member] \| Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 1 [Member] \| Basis Swaps
Derivative assets (liabilities):
Derivative assets (liabilities)	0
Fair Value, Inputs, Level 1 [Member] \| Three-way collars
Derivative assets (liabilities):
Derivative assets (liabilities)	0
Fair Value, Inputs, Level 1 [Member] \| NYMEX Roll Swaps
Derivative assets (liabilities):
Derivative assets (liabilities)	0
Fair Value, Inputs, Level 2 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	34,305	13,492
Fair Value, Inputs, Level 2 [Member] \| Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	27,608	2,043
Fair Value, Inputs, Level 2 [Member] \| Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	3,986	11,449
Fair Value, Inputs, Level 2 [Member] \| Basis Swaps
Derivative assets (liabilities):
Derivative assets (liabilities)	(177)
Fair Value, Inputs, Level 2 [Member] \| Three-way collars
Derivative assets (liabilities):
Derivative assets (liabilities)	1,931
Fair Value, Inputs, Level 2 [Member] \| NYMEX Roll Swaps
Derivative assets (liabilities):
Derivative assets (liabilities)	957
Fair Value, Inputs, Level 3 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 3 [Member] \| Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 3 [Member] \| Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	$ 0
Fair Value, Inputs, Level 3 [Member] \| Basis Swaps
Derivative assets (liabilities):
Derivative assets (liabilities)	0
Fair Value, Inputs, Level 3 [Member] \| Three-way collars
Derivative assets (liabilities):
Derivative assets (liabilities)	0
Fair Value, Inputs, Level 3 [Member] \| NYMEX Roll Swaps
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, 2021	Dec. 31, 2020	Dec. 31, 2019
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	$ 0	$ 207,119	$ 3,745
Estimated fair value of proved properties		145,700
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		$ 14,500

Fair Value Measurements - Prope

Fair Value Measurements - Property Impairments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments	$ 0	$ 207,119	$ 3,745
Unproved property impairments	38,370	70,822	82,457
Total	$ 38,370	277,941	$ 86,202
Estimated fair value of proved properties		145,700
Inventory Valuation and Obsolescence [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Inventory Write-down		24,500
Non-core [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments		14,500
Red River Units [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments		$ 168,100

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, 2021	Dec. 31, 2020	Jun. 30, 2019
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		$ 906,922
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		990,746
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		691,868
Senior Notes due 2031
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2031
Debt instrument, stated interest rate	5.75%
Two Point Two Six Eights Percent Senior Notes due 2026
Fair Value Measurements [Line Items]
Senior notes	$ 800,000
Two And Eight Seven Fifths Percent Senior Notes Due 2032
Fair Value Measurements [Line Items]
Senior notes	800,000
Carrying Amount [Member]
Fair Value Measurements [Line Items]
Revolving credit facility	500,000	160,000
Note payable	22,356	24,590
Total debt	6,828,892	5,532,418
Carrying Amount [Member] \| 5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Senior notes	0	630,470	$ 1,600,000
Carrying Amount [Member] \| 4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Senior notes	648,078	646,943
Carrying Amount [Member] \| 3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Senior notes	908,061	906,922
Carrying Amount [Member] \| 4.375% Senior Notes Due 2028
Fair Value Measurements [Line Items]
Senior notes	991,880	990,746
Carrying Amount [Member] \| 4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Senior notes	692,056	691,868
Carrying Amount [Member] \| Senior Notes due 2031
Fair Value Measurements [Line Items]
Senior notes	1,482,319	1,480,879
Carrying Amount [Member] \| Two Point Two Six Eights Percent Senior Notes due 2026
Fair Value Measurements [Line Items]
Senior notes	792,621	0
Carrying Amount [Member] \| Two And Eight Seven Fifths Percent Senior Notes Due 2032
Fair Value Measurements [Line Items]
Senior notes	791,521	0
Fair Value [Member]
Fair Value Measurements [Line Items]
Revolving credit facility	500,000	160,000
Note payable	22,000	24,700
Total debt	7,351,100	5,792,900
Fair Value [Member] \| 5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Senior notes	0	632,900
Fair Value [Member] \| 4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Senior notes	670,200	669,900
Fair Value [Member] \| 3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Senior notes	950,000	939,500
Fair Value [Member] \| 4.375% Senior Notes Due 2028
Fair Value Measurements [Line Items]
Senior notes	1,082,100	1,024,400
Fair Value [Member] \| 4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Senior notes	781,500	689,600
Fair Value [Member] \| Senior Notes due 2031
Fair Value Measurements [Line Items]
Senior notes	1,769,600	1,651,900
Fair Value [Member] \| Two Point Two Six Eights Percent Senior Notes due 2026
Fair Value Measurements [Line Items]
Senior notes	795,200	0
Fair Value [Member] \| Two And Eight Seven Fifths Percent Senior Notes Due 2032
Fair Value Measurements [Line Items]
Senior notes	$ 780,500	$ 0

Long-Term Debt - Long-Term Debt

Long-Term Debt - Long-Term Debt (Detail) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2020	Jun. 30, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Nov. 25, 2020	Sep. 12, 2019	Jun. 30, 2019
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net			$ 54,200	$ 43,700
TotalRedemptionAmount							$ 516,500
Less: Current portion of long-term debt			(2,326)	(2,245)
Long-term debt, net of current portion			6,826,566	5,530,173
Gain (loss) on extinguishment of debt	$ 64,600	$ 300	$ (290)	35,719	$ (4,584)
5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
TotalRedemptionAmount						$ 475,000
Debt instrument, stated interest rate			5.00%
4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate			4.50%
3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes				906,922
Debt instrument, stated interest rate			3.80%
4.375% Senior Notes Due 2028
Debt Instrument [Line Items]
Senior notes				990,746
Debt instrument, stated interest rate			4.375%
4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes				691,868
Debt instrument, stated interest rate			4.90%
Senior Notes due 2031
Debt Instrument [Line Items]
Debt instrument, stated interest rate			5.75%
Two Point Two Six Eights Percent Senior Notes due 2026
Debt Instrument [Line Items]
Senior notes			$ 800,000
Two And Eight Seven Fifths Percent Senior Notes Due 2032
Debt Instrument [Line Items]
Senior notes			800,000
Carrying Amount [Member]
Debt Instrument [Line Items]
Revolving credit facility			500,000	160,000
Note payable			22,356	24,590
Total debt			6,828,892	5,532,418
Carrying Amount [Member] \| 5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior notes			0	630,470				$ 1,600,000
Carrying Amount [Member] \| 4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Senior notes			648,078	646,943
Carrying Amount [Member] \| 3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes			908,061	906,922
Carrying Amount [Member] \| 4.375% Senior Notes Due 2028
Debt Instrument [Line Items]
Senior notes			991,880	990,746
Carrying Amount [Member] \| 4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes			692,056	691,868
Carrying Amount [Member] \| Senior Notes due 2031
Debt Instrument [Line Items]
Senior notes			1,482,319	1,480,879
Carrying Amount [Member] \| Two Point Two Six Eights Percent Senior Notes due 2026
Debt Instrument [Line Items]
Senior notes			792,621	0
Carrying Amount [Member] \| Two And Eight Seven Fifths Percent Senior Notes Due 2032
Debt Instrument [Line Items]
Senior notes			$ 791,521	$ 0

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, 2020	Mar. 31, 2020	Sep. 30, 2019	Jun. 30, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Nov. 22, 2021	Oct. 29, 2021	Apr. 30, 2021	Jan. 31, 2021	Nov. 25, 2020	Jun. 30, 2020	Sep. 12, 2019	Jun. 30, 2019
Debt Instrument [Line Items]
Proceeds from sale of assets					$ 8,041	$ 2,779	$ 88,734
(Gain) loss on extinguishment of debt		$ (64,600)		$ (300)	290	(35,719)	4,584
TotalRedemptionAmount														$ 516,500
Aggregate amount of lender commitments on credit facility	$ 1,500,000				$ 2,000,000	1,500,000		$ 1,700,000	$ 1,700,000
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					$ 1,587,776	1,485,000	0
Repayments of Lines of Credit					1,323,000	1,947,000	1,161,000
Current portion of long-term debt	$ 2,245				2,326	$ 2,245
Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount										$ 230,800	$ 400,000	$ 469,200		$ 500,000
Debt Instrument, Redemption Price, Percentage	100.25%		100.833%
Debt Instrument, Face Amount					$ 649,625
(Gain) loss on extinguishment of debt	$ 28,900						$ 4,600
Debt instrument, maturity date					Apr. 15, 2023
Senior Notes due 2028 [Domain]
Debt Instrument [Line Items]
Debt Instrument, Face Amount					$ 1,000,000
Debt instrument, maturity date					Jan. 15, 2028
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate					1.60%
Line of Credit Facility, Remaining Borrowing Capacity					$ 1,500,000
Note Payable [Member]
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount													$ 4,400
Notes Payable													$ 26,000
Debt instrument, stated interest rate					3.50%
Debt Instrument, Term						10 years
5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
TotalRedemptionAmount												475,000
Debt instrument, stated interest rate					5.00%
Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount		50,400										800,000
Debt Instrument, Redemption Price, Percentage	103.00%
Debt Instrument, Repurchase Amount		29,300										$ 828,000
4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate					4.50%
3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount		89,000
Senior notes	$ 906,922					$ 906,922
Debt instrument, stated interest rate					3.80%
Debt Instrument, Repurchase Amount		$ 46,900
4.375% Senior Notes Due 2028
Debt Instrument [Line Items]
Senior notes	990,746					990,746
Debt instrument, stated interest rate					4.375%
4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	691,868					691,868
Debt instrument, stated interest rate					4.90%
Senior Notes due 2031
Debt Instrument [Line Items]
Debt Instrument, Face Amount					$ 1,500,000
Debt instrument, stated interest rate					5.75%
Debt instrument, maturity date					Jan. 15, 2031
Two Point Two Six Eights Percent Senior Notes due 2026
Debt Instrument [Line Items]
Senior notes					$ 800,000
Two And Eight Seven Fifths Percent Senior Notes Due 2032
Debt Instrument [Line Items]
Senior notes					800,000
Senior Notes
Debt Instrument [Line Items]
Proceeds from issuance of Senior Notes					1,590,000
Carrying Amount [Member]
Debt Instrument [Line Items]
Line of credit facility, amount outstanding	160,000				500,000	160,000
Notes Payable	24,590				22,356	24,590
Carrying Amount [Member] \| 5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior notes	630,470				0	630,470									$ 1,600,000
Carrying Amount [Member] \| 4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Senior notes	646,943				648,078	646,943
Carrying Amount [Member] \| 3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes	906,922				908,061	906,922
Carrying Amount [Member] \| 4.375% Senior Notes Due 2028
Debt Instrument [Line Items]
Senior notes	990,746				991,880	990,746
Carrying Amount [Member] \| 4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	691,868				692,056	691,868
Carrying Amount [Member] \| Senior Notes due 2031
Debt Instrument [Line Items]
Senior notes	1,480,879				1,482,319	1,480,879
Carrying Amount [Member] \| Two Point Two Six Eights Percent Senior Notes due 2026
Debt Instrument [Line Items]
Senior notes	0				792,621	0
Carrying Amount [Member] \| Two And Eight Seven Fifths Percent Senior Notes Due 2032
Debt Instrument [Line Items]
Senior notes	$ 0				$ 791,521	$ 0

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, 2021USD ($)
Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 649,625
Maturity date	Apr. 15, 2023
Interest Payment Dates	April 15, Oct 15
Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Period, Start Date	Jan. 15, 2023
Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 911,000
Maturity date	Jun. 1, 2024
Interest Payment Dates	June 1, Dec 1
Debt Instrument, Redemption Period, Start Date	Mar. 1, 2024
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
Debt Instrument, Redemption Period, Start Date	Oct. 15, 2027
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
Debt Instrument, Redemption Period, Start Date	Dec. 1, 2043
Senior Notes due 2031
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 1,500,000
Maturity date	Jan. 15, 2031
Interest Payment Dates	Jan 15, Jul 15
Debt Instrument, Redemption Period, Start Date	Jul. 15, 2030
Senior Notes due 2026 [Domain]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 800,000
Maturity date	Nov. 15, 2026
Interest Payment Dates	May 15, Nov 15
Debt Instrument, Redemption Period, Start Date	Nov. 15, 2023
Senior Notes due 2032 [Domain]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 800,000
Maturity date	Apr. 1, 2032
Interest Payment Dates	April 1, Oct 1
Debt Instrument, Redemption Period, Start Date	Jan. 1, 2032

Revenues (Details)

Revenues (Details) - USD ($) $ in Thousands	12 Months Ended
Revenues (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Transportation expenses	$ 224,989	$ 196,692	$ 225,649

Revenues Revenues Disaggregatio

Revenues Revenues Disaggregation of Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Transportation expenses	$ 224,989	$ 196,692	$ 225,649
Crude oil and natural gas sales	5,793,741	2,555,434	4,514,389
Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	5,793,741	2,555,434	4,514,389
Transferred over Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	0	0	0
North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	3,624,988	1,655,907	3,227,498
North Region [Member] \| Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	3,624,988	1,655,907	3,227,498
North Region [Member] \| Transferred over Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	0	0	0
South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	2,168,753	899,527	1,286,891
South Region [Member] \| Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	2,168,753	899,527	1,286,891
South Region [Member] \| Transferred over Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	0	0	0
Crude oil sales
Disaggregation of Revenue [Line Items]
Transportation expenses	185,100	159,000	192,000
Crude oil and natural gas sales	3,949,294	2,199,976	3,929,994
Crude oil sales \| North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	3,049,192	1,627,101	3,092,642
Crude oil sales \| South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	900,102	572,875	837,352
Natural gas sales
Disaggregation of Revenue [Line Items]
Transportation expenses	39,900	37,700	33,700
Crude oil and natural gas sales	1,844,447	355,458	584,395
Natural gas sales \| North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	575,796	28,806	134,856
Natural gas sales \| South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	1,268,651	326,652	449,539
Operated properties \| Crude oil sales
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	3,230,594	1,802,110	3,152,226
Operated properties \| Crude oil sales \| North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	2,392,465	1,264,149	2,365,574
Operated properties \| Crude oil sales \| South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	838,129	537,961	786,652
Operated properties \| Natural gas sales
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	1,647,313	329,572	521,132
negative gas revenues		25,600
Operated properties \| Natural gas sales \| North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	460,376	28,086	109,668
Operated properties \| Natural gas sales \| South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	1,186,937	301,486	411,464
Non-operated properties \| Crude oil sales
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	718,700	397,866	777,768
Non-operated properties \| Crude oil sales \| North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	656,727	362,952	727,068
Non-operated properties \| Crude oil sales \| South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	61,973	34,914	50,700
Non-operated properties \| Natural gas sales
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	197,134	25,886	63,263
negative gas revenues		17,300
Non-operated properties \| Natural gas sales \| North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	115,420	720	25,188
Non-operated properties \| Natural gas sales \| South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	$ 81,714	$ 25,166	$ 38,075

Allowance for Credit Losses (De

Allowance for Credit Losses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Financing Receivable, Allowance for Credit Loss [Line Items]
Allowance for credit losses	$ 2.8	$ 2.5
Accounts Receivable, Credit Loss Expense (Reversal)	0.8	1.8	$ 1.6
Allowance for credit losses on joint interest receivables [Member]
Financing Receivable, Allowance for Credit Loss [Line Items]
Allowance for credit losses	$ 2.8	$ 2.5

Income Taxes - Provision for In

Income Taxes - Provision for Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Current federal income tax (provision) benefit	$ 0	$ (2,248)	$ 0
Current tax (provision), various states	0	29	0
Total current income tax provision (benefit)	0	(2,219)	0
Deferred federal income tax (provision) benefit	467,051	(148,828)	191,328
Deferred tax (provision) benefit, various states	52,679	(18,143)	21,361
Total deferred income tax provision (benefit)	519,730	(166,971)	212,689
Provision (benefit) for income taxes	$ 519,730	$ (169,190)	$ 212,689
Effective tax rate	23.80%	21.80%	21.50%

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income (loss) before income taxes	$ 2,186,138	$ (774,751)	$ 987,162
Expected income tax provision (benefit) based on U.S. federal statutory tax rate	459,089	(162,698)	207,304
State and local income taxes, net of federal benefit	77,979	(24,808)	31,967
Tax benefit (deficiency) from stock-based compensation	5,869	4,927	(7,971)
Sale of Canadian subsidiary and assets	0	0	(16,860)
Other, net	(8,733)	(1,085)	(1,751)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	(14,474)	14,474	0
Provision (benefit) for income taxes	$ 519,730	$ (169,190)	$ 212,689
Federal statutory income tax rate	21.00%	21.00%	21.00%
Effective tax rate	23.80%	21.80%	21.50%

Income Taxes - Components of De

Income Taxes - Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Sep. 30, 2020
Income Tax Disclosure [Abstract]
Deferred tax assets, Net operating loss carryforwards	$ 365,602	$ 579,781
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	12,751	12,900
Deferred Tax Assets, Other	29,421	10,691
Total deferred tax assets	407,774	603,372
Deferred Tax Assets, Valuation Allowance	0	14,474	$ 14,500
Total deferred tax assets, net of valuation allowance	407,774	588,898
Deferred tax liabilities, Property and equipment	(2,536,938)	(2,204,378)
Deferred Tax Liabilities, Other	(10,720)	(4,674)
Total deferred tax liabilities	2,547,658	2,209,052
Deferred income tax liabilities, net	$ 2,139,884	$ 1,620,154

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State	$ 3,630
UNITED STATES
Operating Loss Carryforwards [Line Items]
Federal Operating Loss Carryforwards	$ 1,170
Operating Loss Carryforwards, Limitations on Use	283 million
Operating loss carryforward with indefinite life	$ 887
OKLAHOMA
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State	3,070
Operating loss carryforward subject to expiration	1,960
State operating loss carryforward indefinite life	1,110
NORTH DAKOTA
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State	$ 457

Income Taxes Income Taxes - (De

Income Taxes Income Taxes - (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Sep. 30, 2020
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Valuation Allowance		$ 0	$ 14,474	$ 14,500
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	$ 19,600
Income tax benefit related to sale of Canadian subsidiary	$ 16,900

Leases Description of leases (D

Leases Description of leases (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Lessee, Lease, Description [Line Items]
Operating Lease, Liability	$ 15,474	$ 8,427
Drilling rig commitments [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Liability	0	2,025
Surface use agreements [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Liability	12,354	4,928
Field equipment [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Liability	2,095	928
Other [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Liability	$ 1,025	$ 546

Leases Leases additional inform

Leases Leases additional information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Operating Lease, Liability	$ 15,474	$ 8,427
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	10,481	7,377	$ 1,208
Short-term Lease, Cost	77,551	107,984	176,586
Lease, Cost	87,475	119,384	199,646
Operating Lease, Cost	6,653	6,444	11,130
Variable Lease, Cost	3,271	4,956	11,930
Operating cash flows from operating leases	$ 1,731	$ 890	$ 804
Operating Lease, Weighted Average Remaining Lease Term	14 years 4 months 24 days	13 years 2 months 12 days	11 years 6 months
Weighted average discount rate	5.00%	4.80%	4.90%

Leases Leases, maturities of op

Leases Leases, maturities of operating leases (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	$ 2,369
Lessee, Operating Lease, Liability, Payments, Due Year Two	2,263
Lessee, Operating Lease, Liability, Payments, Due Year Three	1,831
Lessee, Operating Lease, Liability, Payments, Due Year Four	1,295
Lessee, Operating Lease, Liability, Payments, Due Year Five	1,258
Lessee, Operating Lease, Liability, Payments, Due after Year Five	13,084
Lessee, Operating Lease, Liability, Payments, Due	22,100
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	6,626
Operating Lease, Liability	15,474	$ 8,427
Current portion of operating lease liabilities	1,674	2,588
Operating lease liabilities, net of current portion	$ 13,800	$ 5,839

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)
Long-term Purchase Commitment [Line Items]
Purchase Obligation Agreement Expiration Date	2031
Purchase Obligation	$ 1,310
Purchase Obligation, Due in Next Twelve Months	275
Purchase Obligation, Due in Second Year	270
Purchase Obligation, Due in Third Year	251
Purchase Obligation, Due in Fourth Year	164
Purchase Obligation, Due in Fifth Year	139
Purchase Obligation, Due after Fifth Year	214
Pledge agreement with Oklahoma State University	$ 25

Commitments and Contingencies L

Commitments and Contingencies Loss Contingencies (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Loss Contingencies [Line Items]
Legal proceedings recorded as a liability under other noncurrent liabilities	$ 7.9	$ 7.7

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Related Party Transaction [Line Items]
Amount charged to affiliate for aircraft use	$ 11,300	$ 8,100	$ 17,600
Amount charged to company by affiliate for aircraft use	117,000	120,000	303,000
Officers And Other Key Employees [Member]
Related Party Transaction [Line Items]
Revenues from transactions with related party	100,000	300,000	300,000
Due to affiliates	37,000	18,000
Revenues paid to related party	400,000	200,000	400,000
Due from affiliates	39,000	18,000
Other Affiliates [Member]
Related Party Transaction [Line Items]
Total amount paid to related party	84,000	158,000	426,000
Due to affiliates		33,000
Due from affiliates		6,300
Total amount received from related party	$ 5,000	$ 9,500	$ 18,900

Stock Based Compensation - Asso

Stock Based Compensation - Associated Compensation Expense (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Stock-based compensation	$ 63,173	$ 64,613	$ 52,044

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value at vesting date	$ 46.7	$ 27.5	$ 79.7
Unrecognized compensation expense related to non-vested	$ 70
Unrecognized compensation expense related to non-vested, period for recognition, in years	1 year 4 months 24 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	8,492,645

Stock Based Compensation - Summ

Stock Based Compensation - Summary of Changes in Non Vested Shares of Restricted Stock (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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	4,890,638	3,461,908	4,022,409
Granted shares	3,050,491	2,738,625	1,526,825
Vested shares	(1,750,483)	(1,146,618)	(1,737,304)
Forfeited shares	(296,138)	(163,277)	(350,022)
Non-vested shares, ending balance	5,894,508	4,890,638	3,461,908
Non-vested, weighted average grant-date fair value, beginning of period	$ 36.26	$ 46.82	$ 38.44
Granted, weighted average grant-date fair value	24.73	26.93	43.21
Vested, weighted average grant-date fair value	44.36	45.78	24.19
Forfeited, weighted average grant-date fair value	26.61	36.69	47.13
Non-vested, weighted average grant-date fair value, end of period	$ 28.38	$ 36.26	$ 46.82

Shareholders' Equity Attribut_3

Shareholders' Equity Attributable to Continental Resources Share Repurchase Program (Details) - USD ($) $ in Thousands	12 Months Ended			36 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2021
Share Repurchase Program [Abstract]
Stock Repurchased and Retired During Period, Shares	3,198,571	8,122,104	5,646,553	16,967,228
Treasury Stock, Retired, Cost Method, Amount	$ 123,924	$ 126,906	$ 190,239	$ 441,069

Shareholders' Equity Attribut_4

Shareholders' Equity Attributable to Continental Resources Dividend (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended					12 Months Ended
	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2020	Dec. 31, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Dividend [Abstract]
Payments of Dividends	$ 72,975	$ 55,132	$ 40,429	$ 18,580		$ 168,536	$ 18,580	$ 18,747
Common Stock, Dividends, Per Share, Declared	$ 0.20	$ 0.15	$ 0.11	$ 0.05	$ 0.05

Shareholders' Equity Attribut_5

Shareholders' Equity Attributable to Continental Resources (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive income				$ 0	$ 415
Foreign currency translation adjustments		$ 0	$ 0	140
Release of cumulative translation adjustment	[1]			(555)
Translation Adjustment Functional to Reporting Currency, Tax Expense (Benefit)	[2]			0
Other Comprehensive Income (Loss), Net of Tax		$ 0	$ 0	$ (415)

[1]	In conjunction with the Company’s sale of its Canadian operations in 2019, the cumulative translation adjustments were released. See Note 2. Property Acquisitions and 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 (Detai

Noncontrolling Interests (Details) - USD ($) $ in Millions	3 Months Ended
Noncontrolling Interests (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2021	Dec. 31, 2020
TMRC II [Member]
Noncontrolling Interest [Line Items]
Proceeds from formation of new mineral relationship	$ 214.8
Other Noncontrolling Interests		$ 369.8	$ 355.1
SFPG, LLC [Member]
Noncontrolling Interest [Line Items]
Other Noncontrolling Interests		$ 11.1	$ 11.2
Continental Resources ownership in TMRCII [Member] \| TMRC II [Member]
Noncontrolling Interest [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	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%

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, 2021		Dec. 31, 2020	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Sale of Canadian subsidiary and assets	$ 0		$ 0	$ (16,860)
Crude oil and natural gas sales	5,793,741		2,555,434	4,514,389
Production expenses	(406,906)		(359,267)	(444,649)
Production taxes	(404,362)		(192,718)	(357,988)
Results of Operations, Transportation Costs	(224,989)		(196,692)	(225,649)
Exploration Expense	(21,047)		(17,732)	(14,667)
Depreciation, depletion, amortization and accretion	(1,872,075)		(1,859,893)	(1,997,854)
Property impairments	(38,370)		(277,941)	(86,202)
Income tax (provision) benefit (1)	(690,902)	[1]	83,427	(323,025)	[1]
Results from crude oil and natural gas producing activities	$ 2,135,090		$ (265,382)	$ 1,064,355

[1]	Income taxes reflect the application of a combined federal and state tax rate of 24.5% on pre-tax income/loss generated by our 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 that year.

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Property Acquisition Costs - Proved	$ 2,580,271	$ 60,494	$ 51,558
Property Acquisition Costs - Unproved	1,197,507	201,919	312,680
Total property acquisition costs	3,777,778	262,413	364,238
Exploration Costs	171,549	48,282	50,143
Development Costs	1,174,828	1,053,532	2,388,582
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities	$ 5,124,155	$ 1,364,227	$ 2,802,963

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Development costs included in asset retirement costs	$ 31.1	$ 18.1	$ 6.7

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, 2021	Dec. 31, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved crude oil and natural gas properties	$ 31,613,656	$ 27,726,954
Unproved crude oil and natural gas properties	1,358,673	368,256
Total	32,972,329	28,095,210
Less accumulated depreciation, depletion and amortization	(16,310,054)	(14,622,376)
Net capitalized costs	$ 16,662,275	$ 13,472,834

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, 2021USD ($)Well	Dec. 31, 2020USD ($)Well	Dec. 31, 2019USD ($)Well
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Balance at January 1	$ 32,737	$ 6,257	$ 3,959
Additions to capitalized exploratory well costs pending determination of proved reserves	122,068	32,880	28,280
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves	(117,131)	(72)	(23,200)
Capitalized exploratory well costs charged to expense	(1)	(6,328)	(2,782)
Balance at December 31	$ 37,673	$ 32,737	$ 6,257
Number of wells \| Well	17	16	11

Supplemental Crude Oil and Na_3

Supplemental Crude Oil and Natural Gas Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2021MBbls	Dec. 31, 2021MMcf	Dec. 31, 2021MBoe	Dec. 31, 2021$ / bbl	Dec. 31, 2021$ / Mcf	Dec. 31, 2020$ / Mcf$ / bblMBoeMMcfMBbls	Dec. 31, 2019$ / bbl$ / McfMBoeMBblsMMcf
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)				(53,569)			504,874	148,848
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)				(371,105)			(91,387)	(365,034)
Discount factor utilized as standardized measure for future net cash flows	10.00%
Purchases of minerals in place, Total				237,343			7,817	6,798
Percent of proved crude oil reserve estimates prepared by external reserve engineers	98.00%						95.00%	91.00%
Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates \| MBbls		14,574					(249,845)	(88,307)
Extensions, discoveries and other additions \| MBbls		165,268					42,106	162,710
Purchases of minerals in place \| MBbls		175,419					3,272	1,758
Weighted average price utilized in computation of future cash inflows \| $ / bbl					62.19		34.34	51.95
Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates \| MMcf			233,966				(1,530,174)	(363,239)
Extensions, discoveries and other additions \| MMcf			1,235,022				295,686	1,213,947
Purchases of minerals in place \| MMcf			371,546				27,269	30,238
Weighted average price utilized in computation of future cash inflows \| $ / Mcf						3.46	1.17	2.02
Bakken [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)				(202,000)
Extensions, discoveries and other additions		140	375
SCOOP [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)				(169,000)
Extensions, discoveries and other additions		25	860
Permian Basin
Reserve Quantities [Line Items]
Purchases of minerals in place		149	326
Purchases of minerals in place, Total				203
Powder River Basin
Reserve Quantities [Line Items]
Purchases of minerals in place		26	46
Purchases of minerals in place, Total				34
Change in development plans \| Proved Undeveloped Reserves [Domain]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)				57,000			107	35
Price Driven \| Proved Reserves [Domain]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)				(168,000)			(388)
Economics, Performance and Other [Domain] \| Proved Reserves [Domain]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)								85
Other \| Proved Reserves [Domain]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)				2			48	14
Instrument Type [Domain] \| Proved Reserves [Domain]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)				56,000			58	43

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, 2021MBoeMBblsMMcf	Dec. 31, 2020MBoeMBblsMMcf	Dec. 31, 2019MBoeMBblsMMcf	Dec. 31, 2018MBoe
Changes in Proved Reserves [Roll Forward]
Proved Developed and Undeveloped Reserve, Net (Energy) \| MBoe	1,645,310	1,103,762	1,619,265	1,522,365
Revisions of previous estimates \| MBoe	53,569	(504,874)	(148,848)
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) \| MBoe	371,105	91,387	365,034
Proved Developed and Undeveloped Reserve, Production (Energy) \| MBoe	120,321	109,833	124,244
Proved Developed and Undeveloped Reserves, Sale of Mineral in Place (Energy) \| MBoe	148	0	1,840
Purchases of minerals in place, Total \| MBoe	237,343	7,817	6,798
Percent of proved crude oil reserve estimates prepared by external reserve engineers	98.00%	95.00%	91.00%
Natural Gas [Member]
Changes in Proved Reserves [Roll Forward]
Proved reserves at beginning of period \| MMcf	3,640,724	5,154,471	4,591,614
Revisions of previous estimates \| MMcf	233,966	(1,530,174)	(363,239)
Extensions, discoveries and other additions \| MMcf	1,235,022	295,686	1,213,947
Proved Developed and Undeveloped Reserves, Production \| MMcf	(370,110)	(306,528)	(311,865)
Sales of minerals in place \| MMcf	(469)	0	(6,224)
Purchases of minerals in place \| MMcf	371,546	27,269	30,238
Proved reserves at end of period \| MMcf	5,110,679	3,640,724	5,154,471
Crude Oil [Member]
Changes in Proved Reserves [Roll Forward]
Proved reserves at beginning of period \| MBbls	496,975	760,187	757,096
Revisions of previous estimates \| MBbls	14,574	(249,845)	(88,307)
Extensions, discoveries and other additions \| MBbls	165,268	42,106	162,710
Proved Developed and Undeveloped Reserves, Production \| MBbls	(58,636)	(58,745)	(72,267)
Sales of minerals in place \| MBbls	(70)	0	(803)
Purchases of minerals in place \| MBbls	175,419	3,272	1,758
Proved reserves at end of period \| MBbls	793,530	496,975	760,187

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)	Dec. 31, 2021MBoeMBblsMMcf	Dec. 31, 2020MBoeMBblsMMcf	Dec. 31, 2019MBoeMBblsMMcf	Dec. 31, 2018MBoeMBblsMMcf
Reserve Quantities [Line Items]
Proved Developed Reserves (MBOE) \| MBoe	907,678	627,407	707,424
Proved Undeveloped Reserve (MBOE) \| MBoe	737,632	476,355	911,841
Proved Developed and Undeveloped Reserve, Net (MBOE) \| MBoe	1,645,310	1,103,762	1,619,265	1,522,365
Crude Oil [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume) \| MBbls	424,153	281,906	336,405
Proved Undeveloped Reserve (Volume) \| MBbls	369,377	215,069	423,782
Proved Developed and Undeveloped Reserves, Net \| MBbls	793,530	496,975	760,187	757,096
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume) \| MMcf	2,901,147	2,073,011	2,226,117
Proved Undeveloped Reserve (Volume) \| MMcf	2,209,532	1,567,713	2,928,354
Proved Developed and Undeveloped Reserves, Net \| MMcf	5,110,679	3,640,724	5,154,471	4,591,614

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, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Supplemental Crude Oil and Natural Gas Information [Abstract]
Discount factor utilized as standardized measure for future net cash flows	10.00%
Future cash inflows	$ 67,034,046	$ 21,334,235	$ 49,893,470
Future production costs	(18,837,000)	(7,750,834)	(15,309,672)
Future development and abandonment costs	(7,751,678)	(3,950,752)	(10,033,887)
Future income taxes	(7,862,849)	(724,569)	(3,351,657)
Future net cash flows	32,582,519	8,908,080	21,198,254
10% annual discount for estimated timing of cash flows	(15,946,126)	(4,254,515)	(10,736,613)
Standardized measure of discounted future net cash flows	$ 16,636,393	$ 4,653,565	$ 10,461,641	$ 15,684,817

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, 2021	Dec. 31, 2020	Dec. 31, 2019
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	$ 4,653,565	$ 10,461,641	$ 15,684,817
Extensions, discoveries and improved recoveries, less related costs	2,985,056	187,981	1,649,322
Revisions of previous quantity estimates	816,674	(2,952,489)	(1,564,503)
Changes in estimated future development and abandonment costs	706,168	4,760,286	1,401,513
Increase Due to Purchases of Minerals in Place	3,408,365	53,742	49,330
Net change in prices and production costs	9,396,945	(6,912,031)	(6,591,347)
Accretion of discount	489,273	1,183,993	1,865,034
Sales of crude oil and natural gas produced, net of production costs	(4,757,483)	(1,806,758)	(3,486,103)
Development costs incurred during the period	683,212	863,101	1,557,121
Change in timing of estimated future production and other	1,871,903	(2,325,024)	(1,690,779)
Change in income taxes	(3,617,285)	1,139,123	1,587,236
Net change	11,982,828	(5,808,076)	(5,223,176)
Standardized measure of discounted future net cash flows at end of year	$ 16,636,393	$ 4,653,565	$ 10,461,641

Subsequent Events (Details)

Subsequent Events (Details) $ / shares in Units, $ in Thousands	2 Months Ended	3 Months Ended						12 Months Ended			36 Months Ended
	Feb. 14, 2022USD ($)$ / shares	Dec. 31, 2021USD ($)$ / shares	Sep. 30, 2021$ / shares	Jun. 30, 2021$ / shares	Mar. 31, 2021USD ($)a	Mar. 31, 2020$ / shares	Dec. 31, 2019$ / shares	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2021USD ($)	Jan. 24, 2022aBoe	Nov. 30, 2021aBoe
Subsequent Event [Line Items]
Costs Incurred, Acquisition of Oil and Gas Properties								$ 3,777,778	$ 262,413	$ 364,238
Asset acquisition net leasehold acres acquired \| a													72,000
Asset acquisition net production BOE per day \| Boe													7,200
Common Stock, Dividends, Per Share, Declared \| $ / shares		$ 0.20	$ 0.15	$ 0.11		$ 0.05	$ 0.05
Stock Repurchase Program, Authorized Amount		$ 1,000,000						1,000,000			$ 1,000,000
Treasury Stock, Retired, Cost Method, Amount								$ 123,924	$ 126,906	$ 190,239	$ 441,069
Powder River Basin
Subsequent Event [Line Items]
Costs Incurred, Acquisition of Oil and Gas Properties		$ 246,800			$ 206,600
Asset acquisition net leasehold acres acquired \| a					130,000
Subsequent Event [Member]
Subsequent Event [Line Items]
Common Stock, Dividends, Per Share, Declared \| $ / shares	$ 0.23
Stock Repurchase Program, Authorized Amount	$ 1,500,000
Treasury Stock, Retired, Cost Method, Amount	441,100
Stock Repurchase Program, Remaining Authorized Repurchase Amount	1,060,000
Subsequent Event [Member] \| Powder River Basin
Subsequent Event [Line Items]
Costs Incurred, Acquisition of Oil and Gas Properties	$ 450,000
Asset acquisition net leasehold acres acquired \| a												172,000
Asset acquisition net production BOE per day \| Boe												16,000

Uncategorized Items - clr-20211

Label	Element	Value
Crude Oil [Member] \| Proved Reserves [Domain] \| Price Driven [Domain]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(92,000)
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(24)
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(214)
Crude Oil [Member] \| Proved Reserves [Domain] \| Other [Domain]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(9)
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(43)
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(35,000)
Crude Oil [Member] \| Proved Reserves [Domain] \| Economics, Performance and Other [Domain]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(29)
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(12,000)
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(38)
Crude Oil [Member] \| Proved Undeveloped Reserves [Domain] \| Change in development plans [Member]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(31,000)
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(17)
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(50)
Natural Gas [Member] \| Proved Reserves [Domain] \| Price Driven [Domain]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	458,000
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(118)
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	1,043
Natural Gas [Member] \| Proved Reserves [Domain] \| Other [Domain]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(139)
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(31)
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(195,000)
Natural Gas [Member] \| Proved Reserves [Domain] \| Economics, Performance and Other [Domain]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(172)
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(263,000)
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(278)
Natural Gas [Member] \| Proved Undeveloped Reserves [Domain] \| Change in development plans [Member]
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(155,000)
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(108)
Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates	srt_ProvedDevelopedAndUndevelopedReservesRevisionsOfPreviousEstimatesIncreaseDecrease	(345)