Continental Resources Inc (CLR) 10-K 22 Feb 23 2022 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Jun. 30, 2022
Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
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	2022
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	No
Entity Voluntary Filers	Yes
Entity Current Reporting Status	No
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	false
Entity Shell Company	false
Entity Public Float		$ 4.1
Entity Common Stock, Shares Outstanding	0
Documents Incorporated by Reference	DOCUMENTS INCORPORATED BY REFERENCE Part III (Items 10, 11, 12, 13 and 14) of this Annual Report on Form 10-K is incorporated by reference from the registrant’s amendment to this Form 10-K to be filed on Form 10-K/A with the Securities and Exchange Commission no later than 120 days after the end of the registrant’s fiscal year covered by this report.
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Current assets:
Cash and cash equivalents	$ 137,788	$ 20,868
Crude oil, natural gas, and natural gas liquids sales	1,313,538	1,122,415
Joint interest and other	458,391	278,753
Allowance for credit losses	(5,514)	(2,814)
Receivables, net	1,766,415	1,398,354
Derivative assets	39,280	22,334
Inventories	173,264	105,568
Prepaid expenses and other	27,508	17,266
Total current assets	2,144,255	1,564,390
Net property and equipment, based on successful efforts method of accounting	18,471,914	16,975,465
Investment in unconsolidated affiliates	210,805	0
Operating lease right-of-use assets	25,158	16,370
Derivative assets, noncurrent	3,548	13,188
Other noncurrent assets	22,670	21,698
Total assets	20,878,350	18,591,111
Current liabilities:
Accounts payable trade	850,547	582,317
Revenues and royalties payable	882,256	627,171
Accrued liabilities and other	343,777	285,740
Current portion of incentive compensation liability	125,653	0
Current portion of income tax liabilities	152,149	0
Derivative liabilities	88,136	899
Current portion of operating lease liabilities	4,086	1,674
Current portion of long-term debt	638,058	2,326
Total current liabilities	3,084,662	1,500,127
Long-term debt, net of current portion	7,571,582	6,826,566
Other noncurrent liabilities:
Deferred income tax liabilities, net	2,538,312	2,139,884
Incentive compensation liability, net of current portion	100,066	0
Asset retirement obligations, net of current portion	257,152	215,701	$ 177,194
Derivative liabilities, noncurrent	133,363	318
Operating lease liabilities, net of current portion	20,055	13,800
Other noncurrent liabilities	43,550	38,390
Total other noncurrent liabilities	3,092,498	2,408,093
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; 299,610,267 shares issued and outstanding at December 31, 2022; 364,297,520 shares issued and outstanding at December 31, 2021;	2,996	3,643
Additional paid-in capital	0	1,131,602
Retained earnings	6,754,174	6,340,211
Total shareholders’ equity attributable to Continental Resources	6,757,170	7,475,456
Noncontrolling interests	372,438	380,869
Total equity	7,129,608	7,856,325	$ 6,422,725
Total liabilities and equity	$ 20,878,350	$ 18,591,111

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	25,000,000	25,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	1,000,000,000	1,000,000,000
Common stock, shares issued	299,610,267	364,297,520
Common stock, outstanding	299,610,267	364,297,520

Consolidated Statements of Inco

Consolidated Statements of Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues:
Crude oil, natural gas, and natural gas liquids sales	$ 10,074,675	$ 5,793,741	$ 2,555,434
Loss on derivative instruments, net	(671,095)	(128,864)	(14,658)
Crude oil and natural gas service operations	70,128	54,441	45,694
Total revenues	9,473,708	5,719,318	2,586,470
Operating costs and expenses:
Production expenses	621,921	406,906	359,267
Production and ad valorem taxes	730,132	404,362	192,718
Transportation, gathering, processing, and compression	316,414	224,989	196,692
Exploration expenses	23,068	21,047	17,732
Crude oil and natural gas service operations	37,002	21,480	18,294
Depreciation, depletion, amortization and accretion	1,885,465	1,898,082	1,880,959
Property impairments	70,417	38,370	277,941
Transaction costs	33,796	13,920	0
General and administrative expenses	401,551	233,628	196,572
Net (gain) loss on sale of assets and other	262	(5,146)	187
Total operating costs and expenses	4,120,028	3,257,638	3,140,362
Income (loss) from operations	5,353,680	2,461,680	(553,892)
Other income (expense):
Interest expense	(300,662)	(251,598)	(258,240)
Gain (loss) on extinguishment of debt	(403)	(290)	35,719
Other	15,798	(23,654)	1,662
Total other income (expense)	(285,267)	(275,542)	(220,859)
Income (loss) before income taxes	5,068,413	2,186,138	(774,751)
(Provision) benefit for income taxes	(1,020,804)	(519,730)	169,190
Income (loss) before equity in net loss of affiliate	4,047,609	1,666,408	(605,561)
Equity in net loss of affiliate	(1,489)	0	0
Net income (loss)	4,046,120	1,666,408	(605,561)
Net income (loss) attributable to noncontrolling interests	21,562	5,440	(8,692)
Net income (loss) attributable to Continental Resources	$ 4,024,558	$ 1,660,968	$ (596,869)
Basic net income (loss) per share attributable to Continental Resources	$ 11.45	$ 4.61	$ (1.65)
Diluted net income (loss) per share attributable to Continental Resources	$ 11.45	$ 4.56	$ (1.65)

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) $ in Thousands	Total	Common stock	Additional paid-in capital	Treasury Stock [Member]	Retained earnings	Continental Resources Shareholders' Equity	Noncontrolling Interests
Balance at Dec. 31, 2019		$ 3,711	$ 1,274,732		$ 5,463,224	$ 6,741,667
Balance, shares at Dec. 31, 2019		371,074,036
Noncontrolling interests at Dec. 31, 2019							$ 366,684
Total equity at Dec. 31, 2019	$ 7,108,351
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)
Adoption of ASU 2016-13	(137)				(137)	(137)
Dividends, Common Stock, Cash	(18,580)				(18,580)	(18,580)
Change in dividends payable	8				8	8
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
Stock-based compensation	64,585		64,585			64,585
Restricted stock:
Issued	$ 27	$ 27	0			27
Issued, shares	2,738,625	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)	(163,277)
Contributions from noncontrolling interests	$ 21,557						21,557
Distributions to noncontrolling interests	(13,270)						(13,270)
Balance at Dec. 31, 2020		$ 3,652	1,205,148		4,847,646	6,056,446
Balance, shares at Dec. 31, 2020		365,220,435
Noncontrolling interests at Dec. 31, 2020							366,279
Total equity at Dec. 31, 2020	6,422,725
Balance at Dec. 31, 2019		$ 3,711	1,274,732		5,463,224	6,741,667
Balance, shares at Dec. 31, 2019		371,074,036
Noncontrolling interests at Dec. 31, 2019							366,684
Total equity at Dec. 31, 2019	7,108,351
Increase (Decrease) in Equity [Roll Forward]
Treasury Stock, Retired, Cost Method, Amount	$ (350,685)
Restricted stock:
Repurchased and canceled, shares	(13,163,097)
Balance at Dec. 31, 2022	$ 6,757,170	$ 2,996			6,754,174	6,757,170
Balance, shares at Dec. 31, 2022	299,610,267	299,610,267
Noncontrolling interests at Dec. 31, 2022	$ 372,438						372,438
Total equity at Dec. 31, 2022	7,129,608
Balance at Dec. 31, 2020		$ 3,652	1,205,148		4,847,646	6,056,446
Balance, shares at Dec. 31, 2020		365,220,435
Noncontrolling interests at Dec. 31, 2020							366,279
Total equity at Dec. 31, 2020	6,422,725
Increase (Decrease) in Equity [Roll Forward]
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
Stock-based compensation	63,145		63,145			63,145
Restricted stock:
Issued	$ 31	$ 31	0			31
Issued, shares	3,050,491	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)	(296,138)
Contributions from noncontrolling interests	$ 33,086						33,086
Distributions to noncontrolling interests	(23,936)						(23,936)
Balance at Dec. 31, 2021	$ 7,475,456	$ 3,643	1,131,602		6,340,211	7,475,456
Balance, shares at Dec. 31, 2021	364,297,520	364,297,520
Noncontrolling interests at Dec. 31, 2021	$ 380,869						380,869
Total equity at Dec. 31, 2021	7,856,325
Increase (Decrease) in Equity [Roll Forward]
Net income (loss) attributable to Continental Resources	4,024,558				4,024,558	4,024,558
Net income (loss) attributable to noncontrolling interests	21,562						21,562
Net income (loss)	4,046,120
Dividends, Common Stock, Cash	(287,035)				(287,035)	(287,035)
Change in dividends payable	205				205	205
Treasury Stock, Retired, Cost Method, Amount	(99,855)
Common stock repurchased prior to take-private transaction	(99,855)			(99,855)		(99,855)
Common stock retired prior to take-private transaction		$ (18)	(99,837)	$ 99,855
Common stock retired prior to take-private transaction, shares		(1,842,422)
Stock-based compensation	(8,085)		(8,085)			(8,085)
Restricted stock:
Issued	$ 16	$ 16	0			16
Issued, shares	1,575,847	1,575,847
Repurchased and canceled	$ (35,445)	$ (7)	(35,438)			(35,445)
Repurchased and canceled, shares	(1,842,422)	(627,742)
Forfeited	$ (4)	$ (4)				(4)
Forfeited shares	(384,536)	(384,536)
Restricted stock cancelled from take-private transaction	$ (53)	$ (53)				(53)
Restricted stock cancelled from take-private transaction, shares		(5,349,141)
Take-private transaction (see Note 1)	(4,312,588)	$ (581)	$ (988,242)		(3,323,765)	(4,312,588)
Take-private transaction (see Note 1), Shares		(58,059,259)
Contributions from noncontrolling interests	12,498						12,498
Distributions to noncontrolling interests	(42,491)						(42,491)
Balance at Dec. 31, 2022	$ 6,757,170	$ 2,996			$ 6,754,174	$ 6,757,170
Balance, shares at Dec. 31, 2022	299,610,267	299,610,267
Noncontrolling interests at Dec. 31, 2022	$ 372,438						$ 372,438
Total equity at Dec. 31, 2022	$ 7,129,608

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flows from operating activities:
Net income (loss)	$ 4,046,120	$ 1,666,408	$ (605,561)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion, amortization and accretion	1,886,491	1,893,106	1,882,458
Property impairments	70,417	38,370	277,941
Non-cash (gain) loss on derivatives, net	212,976	(20,814)	(13,492)
Stock/incentive-based compensation	217,650	63,173	64,613
Provision (benefit) for deferred income taxes	398,429	519,730	(166,971)
Equity in net loss of affiliate	1,489	0	0
Dry hole costs	12,305	0	0
Net (gain) loss on sale of assets and other	262	(5,146)	187
(Gain) loss on extinguishment of debt	403	290	(35,719)
Other, net	27,294	35,614	16,970
Changes in assets and liabilities:
Accounts receivable	(372,529)	(694,981)	332,128
Inventories	(67,478)	(33,411)	12,859
Other current assets	(10,242)	(2,144)	1,471
Accounts payable trade	164,071	106,367	(133,977)
Revenues and royalties payable	253,286	298,552	(143,260)
Accrued liabilities and other	51,222	109,540	(66,071)
Current income taxes liability	152,149	0	0
Other noncurrent assets and liabilities	(4,625)	(803)	(1,272)
Net cash provided by operating activities	7,039,690	3,973,851	1,422,304
Cash flows from investing activities:
Exploration and development	(2,838,075)	(2,382,413)	(1,408,149)
Purchase of producing crude oil and natural gas properties	(421,850)	(2,548,575)	(81,994)
Purchase of other property and equipment	(68,189)	(66,598)	(23,994)
Proceeds from sale of assets	5,740	8,041	2,779
Contributions to unconsolidated affiliates	(212,294)	0	0
Net cash used in investing activities	(3,534,668)	(4,989,545)	(1,511,358)
Cash flows from financing activities:
Credit facility borrowings	3,886,000	1,663,000	2,052,000
Repayment of credit facility	(3,226,000)	(1,323,000)	(1,947,000)
Proceeds from issuance of Senior Notes	0	1,587,776	1,485,000
Redemption and repurchase of Senior Notes	(31,829)	(630,782)	(1,343,250)
Premium and costs on redemption of Senior Notes	0	0	(25,173)
Proceeds from other debt	750,000	0	26,000
Repayment of other debt	(2,326)	(2,243)	(6,679)
Debt issuance costs	(5,148)	(12,082)	(4,368)
Contributions from noncontrolling interests	13,665	31,493	27,116
Distributions to noncontrolling interests	(40,685)	(22,447)	(13,809)
Repurchase of common stock prior to take-private transaction	(99,855)	(123,924)	(126,906)
Take-private transaction (see Note 1)	(4,312,642)	0	0
Repurchase of restricted stock for tax withholdings	(35,444)	(12,804)	(7,347)
Dividends paid on common stock	(283,838)	(165,895)	(18,460)
Net cash provided by (used in) financing activities	(3,388,102)	989,092	97,124
Net change in cash and cash equivalents	116,920	(26,602)	8,070
Cash and cash equivalents at beginning of period	20,868	47,470	39,400
Cash and cash equivalents at end of period	$ 137,788	$ 20,868	$ 47,470

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and summary of significant accounting policies	Note 1. 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 the exploration, development, management, and production of crude oil and natural gas and associated products with properties primarily located in four leading basins in the United States – the Bakken field of North Dakota and Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. Additionally, the Company pursues the acquisition and management of perpetually owned minerals located in certain of its key operating areas. Take-Private Transaction On October 16, 2022 , the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Omega Acquisition, Inc. (“Merger Sub”), an entity owned by the Company’s founder, Harold G. Hamm. Pursuant to the Merger Agreement, on October 24, 2022 Merger Sub commenced a tender offer (the “Offer”) to purchase any and all of the outstanding shares of the Company’s common stock for $ 74.28 per share in cash (the “Offer Price”), other than: (i) shares of common stock owned by Mr. Hamm, certain of his family members and their affiliated entities (collectively, the “Hamm Family”) and (ii) shares of common stock underlying unvested equity awards issued pursuant to the Company’s long-term incentive plans (collectively, the “Rollover Shares”). The Offer expired at one minute after 11:59 p.m., New York City time, on November 21, 2022. As of the expiration of the Offer, a total of approximately 36.3 million shares were validly tendered and not validly withdrawn pursuant to the Offer. In addition, notices of guaranteed delivery were delivered for approximately 3.4 million shares. Each condition to the Offer was satisfied and, on November 22, 2022, Merger Sub irrevocably accepted for payment all shares that were validly tendered and not withdrawn. On November 22, 2022, immediately prior to the acceptance of shares for payment, Mr. Hamm contributed 100 % of the capital stock of Merger Sub to the Company. In addition, following consummation of the Offer, Merger Sub merged with and into the Company, with the Company continuing as the surviving corporation wholly-owned by the Hamm Family (the “Merger”). At the effective time of the Merger, each remaining share of the Company not purchased in the Offer (other than (i) the Rollover Shares; (ii) shares owned by the Company as treasury stock or owned by any wholly owned subsidiary of the Company, including shares irrevocably accepted by Merger Sub pursuant to the Offer; and (iii) shares held by a holder who properly demanded appraisal rights for such shares in accordance with Oklahoma law), was converted into the right to receive an amount in cash equal to the Offer Price, without interest and subject to any required tax withholding. At the effective time of the Merger: (i) each share of the Company held by a member of the Hamm Family was converted into an identical number of newly issued shares of the Company, as the surviving corporation, having identical rights to the previously existing shares held by such holder, and such converted shares of the surviving corporation are the only capital stock of the surviving corporation outstanding following the Merger; and (ii) the Rollover Shares underlying each unvested restricted stock award issued under the Company’s long-term incentive plans that was outstanding immediately prior to the effective time were replaced with a restricted stock unit award issued by the Company that provides the holder of such previous award with the right to receive, on the date that such restricted stock award otherwise would have been settled, and at the Company’s sole discretion, either a share of the Company, a cash award designed to provide substantially equivalent value, or any combination of the two, in each case, together with any unpaid dividends accrued on such restricted stock award. A total of approximately 58.1 million shares of Continental’s common stock were purchased pursuant to the take-private transaction for total cash consideration of approximately $ 4.31 billion, inclusive of payments issued to holders who demanded appraisal rights for their untendered shares in accordance with Oklahoma law. The purchase of outstanding shares was funded by Continental through the use of approximately $ 2.2 billion of cash on hand, $ 1.3 billion of credit facility borrowings, and the execution of a $ 750 million three-year term loan as further described in Note 8. Long-Term Debt . See the Consolidated Statements of Equity for the year ended December 31, 2022 for the impact on the components of Shareholders’ Equity resulting from the take-private transaction. As of December 31, 2022, the Hamm Family holds approximately 299.6 million shares of capital stock of the Company, as the surviving corporation, and there remains approximately 5.3 million Rollover Shares. See Note 15. Stock-Based Compensation for a discussion of the Company’s accounting for the Rollover Shares. The Company incurred $ 32 million of legal and advisory fees in connection with the take-private transaction which are included in the caption “Transaction costs” in the consolidated statements of income (loss) for the year ended December 31, 2022. Following the completion of the take-private transaction: (i) our common stock ceased to be listed on the New York Stock Exchange effective November 23, 2022, (ii) our common stock was deregistered under Section 12(b) of the Securities Exchange Act of 1934 as amended (the “Exchange Act”), and (iii) we suspended our reporting obligations under Section 15(d) of the Exchange Act. As a result, certain of the corporate governance, disclosure, and other provisions applicable to a company with listed equity securities and reporting obligations under the Exchange Act no longer apply to us. We will continue to furnish Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K with the SEC as required by our senior note indentures. 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. 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, natural gas, and natural gas liquids in the United States. Investments in entities in which the Company has the ability to exercise significant influence, but does not control, are accounted for using the equity method of accounting. In applying the equity method, the investments are initially recognized at cost and are subsequently adjusted for the Company’s proportionate share of earnings, losses, contributions, and distributions as applicable. See Note 18. Equity Investment for discussion of a strategic investment made by the Company in 2022 that is accounted for under the equity method. The Company evaluated its December 31, 2022 financial statements for subsequent events through February 22, 2023, the date the financial statements were available to be issued. 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, 2022 , the Company had cash deposits in excess of federally insured amounts of approximately $ 136.4 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 $ 5.5 million and $ 2.8 million as of December 31, 2022 and 2021, 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, 2022 , no purchaser accounted for more than 10 % of the Company’s total crude oil, natural gas, and natural gas liquids sales for 2022 . 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, 2022 and 2021 consisted of the following: December 31, In thousands 2022 2021 Tubular goods and equipment $ 38,636 $ 12,506 Crude oil 130,192 93,062 Natural gas 4,436 — Total $ 173,264 $ 105,568 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 - 30 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, 2020 through December 31, 2022: In thousands 2022 2021 2020 Asset retirement obligations at January 1 $ 219,824 $ 179,676 $ 153,673 Accretion expense 12,857 11,125 9,393 Revisions (1) ( 6,672 ) ( 1,291 ) 10,743 Plus: Additions for new assets 37,413 32,351 7,048 Less: Plugging costs and sold assets ( 2,335 ) ( 2,037 ) ( 1,181 ) Total asset retirement obligations at December 31 $ 261,087 $ 219,824 $ 179,676 Less: Current portion of asset retirement obligations at December 31 (2) 3,935 4,123 2,482 Non-current portion of asset retirement obligations at December 31 $ 257,152 $ 215,701 $ 177,194 (1) Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties. (2) Balance is included in the caption “Accrued liabilities and other” in the consolidated balance sheets. As of December 31, 2022 and 2021 , net property and equipment on the consolidated balance sheets included $ 96.5 million and $ 72.8 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, revolving credit facility, term loan 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 $ 56.3 million and $ 60.6 million (net of accumulated amortization of $ 46.3 million and $ 36.9 million) relating to its long-term debt at December 31, 2022 and 2021, respectively. Unamortized capitalized costs associated with the Company’s Notes, note payable, and term loan totaled $ 46.8 million and $ 50.9 million at December 31, 2022 and 2021, 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 $ 9.4 million and $ 9.7 million at December 31, 2022 and 2021, respectively, and are reflected in “Other noncurrent assets” on the consolidated balance sheets. For the years ended December 31, 2022, 2021 and 2020 , the Company recognized amortization expense associated with capitalized debt issuance costs of $ 9.3 million, $ 7.2 million, and $ 7.8 million, respectively, which are reflected in “Interest expense” on the consolidated statements of 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 income (loss) under the caption “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, 2022 and 2021 . 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. Prior to the Hamm Family's take-private transaction, in periods where the Company had net income, diluted earnings per share reflected the potential dilution of non-vested restricted stock awards, which was 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, 2022, 2021, and 2020. Year ended December 31, In thousands, except per share data 2022 2021 2020 Net income (loss) attributable to Continental Resources (numerator) $ 4,024,558 $ 1,660,968 $ ( 596,869 ) Weighted average shares (denominator): Weighted average shares - basic 351,392 360,434 361,538 Non-vested restricted stock and restricted stock units (1) — 4,019 — Weighted average shares - diluted 351,392 364,453 361,538 Net income (loss) per share attributable to Continental Resources: Basic $ 11.45 $ 4.61 $ ( 1.65 ) Diluted $ 11.45 $ 4.56 $ ( 1.65 ) (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. At December 31, 2022, the Company's outstanding Rollover Shares are expected to be paid in cash, not common stock, upon vesting and are classified as liability awards pursuant to ASC Topic 718, Compensation—Stock Compensation. As a result, no potential dilutive effect for the Rollover Shares is presented for the year ended December 31, 2022.

Property Acquisitions

Property Acquisitions	12 Months Ended
	Dec. 31, 2022
Business Combination and Asset Acquisition [Abstract]
Property Acquisitions	Note 2. Property Acquisitions 2022 In March 2022, the Company acquired oil and gas properties in the Powder River Basin for cash consideration of $ 403 million, representing a $ 450 million purchase price less customary closing adjustments made pursuant to the acquisition agreement. The acquisition was accounted for as an asset acquisition under ASC Topic 805—Business Combinations and included approximately 172,000 net leasehold acres and producing properties with production totaling approximately 18,000 net barrels of oil equivalent per day at the time of closing. Of the purchase price, $ 381.3 million was allocated to proved properties and $ 21.7 million was allocated to unproved properties. The Company recognized approximately $ 15.3 million of asset retirement obligations, $ 31.3 million of assumed production and ad valorem tax payment obligations, and $ 10.1 million of right-of-use assets and corresponding lease liabilities associated with the acquired properties. In April 2022, the Company acquired oil and gas properties in the Permian Basin for cash consideration of $ 197.0 million, representing a $ 200 million purchase price less customary closing adjustments made pursuant to the acquisition agreement. The acquisition was accounted for as an asset acquisition under ASC Topic 805 and was comprised primarily of undeveloped leasehold acreage with an immaterial amount of production. Nearly all of the purchase price was allocated to unproved properties. 2021 Permian Basin Acquisition In December 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 owned 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 (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 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. The Pioneer Acquisition was accounted for using the acquisition method under ASC Topic 805, which required all assets acquired and liabilities assumed to be recorded at fair value at the acquisition date. Of the purchase price, $ 2.4 billion was allocated to proved properties and $ 0.7 billion was allocated to unproved properties. The Company recognized approximately $ 16 million of asset retirement obligations and $ 2 million of right-of-use assets and corresponding lease liabilities associated with the acquired properties. 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 “Transaction costs” in the consolidated statements of 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 oil and gas properties in the Powder River Basin for cash consideration of $ 206.6 million, consisting of a $ 21.5 million escrow deposit paid in December 2020 upon execution of the 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 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 oil and gas properties in the Powder River Basin for cash consideration of $ 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 oil and gas properties in the SCOOP play in the Anadarko Basin for cash consideration of $ 162.8 million. The acquisition included approximately 19,500 net acres and immaterial amounts of production. Of the purchase price, $ 15.3 million was allocated to proved properties and $ 147.5 million was allocated to unproved properties.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2022
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	Note 3. 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 2022 2021 2020 Supplemental cash flow information: Cash paid for interest $ 279,571 $ 214,727 $ 256,633 Cash paid for income taxes (1) 470,147 3 4 Cash received for income tax refunds 16 58 9,600 Non-cash investing activities: Asset retirement obligation additions and revisions, net 30,741 31,060 17,791 (1) Amount for 2022 represents estimated quarterly payments for 2022 U.S. federal income taxes based on an estimate of federal taxable income for the year. As of December 31, 2022 and 2021 , the Company had $ 344.9 million and $ 242.9 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, 2022 and 2021 , the Company had $ 0.5 million and $ 1.7 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 consolidated balance sheets. As of December 31, 2022 and 2021 , the Company had $ 4.3 million and $ 2.5 million, respectively, of accrued distributions to noncontrolling interests included in "Revenues and royalties payable" with an offsetting amount in “Equity – Noncontrolling interests” in the consolidated balance sheets.

Net Property and Equipment

Net Property and Equipment	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment, Net [Abstract]
Net Property and Equipment	Note 4. Net Property and Equipment Net property and equipment includes the following at December 31, 2022 and 2021. December 31, In thousands 2022 2021 Proved crude oil and natural gas properties $ 34,741,054 $ 31,613,656 Unproved crude oil and natural gas properties 1,513,627 1,358,673 Service properties, equipment and other 549,528 484,989 Total property and equipment 36,804,209 33,457,318 Accumulated depreciation, depletion and amortization ( 18,332,295 ) ( 16,481,853 ) Net property and equipment $ 18,471,914 $ 16,975,465

Accrued Liabilities and Other

Accrued Liabilities and Other	12 Months Ended
	Dec. 31, 2022
Accrued Liabilities and Other Liabilities [Abstract]
Accrued Liabilities and Other	Note 5. Accrued Liabilities and Other Accrued liabilities and other includes the following at December 31, 2022 and 2021: December 31, In thousands 2022 2021 Prepaid advances from joint interest owners $ 15,575 $ 18,964 Accrued compensation 81,646 82,844 Accrued production taxes, ad valorem taxes and other non-income taxes 145,436 90,597 Accrued interest 83,724 75,983 Current portion of asset retirement obligations 3,935 4,123 Other 13,461 13,229 Accrued liabilities and other $ 343,777 $ 285,740

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Note 6. 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, 2022 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 Sold Floor Ceiling January 2023 - December 2023 Basis Swaps - NGPL TXOK 75,000 MMBtus/day $ ( 0.17 ) January 2023 - March 2023 Collars - Henry Hub 360,000 MMBtus/day $ 3.91 $ 5.45 Three-way collars - Henry Hub 50,000 MMBtus/day $ 3.00 $ 4.32 $ 5.00 Swaps - Henry Hub 210,000 MMBtus/day $ 4.26 Swaps - WAHA 55,000 MMBtus/day $ 2.81 April 2023 - September 2023 Swaps - Henry Hub 405,000 MMBtus/day $ 3.28 Swaps - WAHA 55,000 MMBtus/day $ 2.81 October 2023 - December 2023 Collars - Henry Hub 200,000 MMBtus/day $ 3.12 $ 4.09 Swaps - Henry Hub 210,000 MMBtus/day $ 3.51 Swaps - WAHA 55,000 MMBtus/day $ 2.81 January 2024 - December 2024 Collars - Henry Hub 50,000 MMBtus/day $ 3.12 $ 4.09 Swaps - Henry Hub 325,000 MMBtus/day $ 3.31 Swaps - WAHA 25,000 MMBtus/day $ 3.43 January 2025 - December 2025 Swaps - Henry Hub 60,000 MMBtus/day $ 3.75 January 2026 - December 2026 Swaps - Henry Hub 50,000 MMBtus/day $ 4.42 Crude oil derivatives Weighted Average Period and Type of Contract Average Volumes Hedged Roll Swaps Fixed Swaps January 2023 - December 2023 Roll Swaps - NYMEX 12,000 Bbls/day $ 1.07 Fixed Swaps - WTI 8,000 Bbls/day $ 83.19 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 2022 2021 2020 Cash received (paid) on derivatives: Crude oil fixed price swaps $ — $ ( 44,463 ) $ ( 31,179 ) Crude oil collars — ( 9,365 ) — Crude oil NYMEX roll swaps ( 9,234 ) ( 163 ) — Natural gas basis swaps 9,674 — — Natural gas WAHA swaps ( 16,350 ) — — Natural gas fixed price swaps ( 353,326 ) ( 84,141 ) 1,071 Natural gas collars ( 66,596 ) ( 11,546 ) 1,958 Natural gas three-way collars ( 22,287 ) — — Cash received (paid) on derivatives, net ( 458,119 ) ( 149,678 ) ( 28,150 ) Non-cash gain (loss) on derivatives: Crude oil collars — 227 ( 227 ) Crude oil fixed price swaps 11,696 — — Crude oil NYMEX roll swaps 1,879 957 — Natural gas basis swaps 9,088 ( 177 ) — Natural gas WAHA swaps 19,386 — — Natural gas fixed price swaps ( 219,388 ) 25,565 2,043 Natural gas collars ( 34,303 ) ( 7,690 ) 11,676 Natural gas three-way collars ( 1,334 ) 1,932 — Non-cash gain (loss) on derivatives, net ( 212,976 ) 20,814 13,492 Loss on derivative instruments, net $ ( 671,095 ) $ ( 128,864 ) $ ( 14,658 ) 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, 2022, all at fair value. December 31, In thousands 2022 2021 Commodity derivative assets: Gross amounts of recognized assets $ 50,559 $ 42,903 Gross amounts offset on balance sheet ( 7,731 ) ( 7,381 ) Net amounts of assets on balance sheet 42,828 35,522 Commodity derivative liabilities: Gross amounts of recognized liabilities ( 229,230 ) ( 8,598 ) Gross amounts offset on balance sheet 7,731 7,381 Net amounts of liabilities on balance sheet $ ( 221,499 ) $ ( 1,217 ) 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 2022 2021 Derivative assets $ 39,280 $ 22,334 Derivative assets, noncurrent 3,548 13,188 Net amounts of assets on balance sheet 42,828 35,522 Derivative liabilities ( 88,136 ) ( 899 ) Derivative liabilities, noncurrent ( 133,363 ) ( 318 ) Net amounts of liabilities on balance sheet ( 221,499 ) ( 1,217 ) Total derivative assets (liabilities), net $ ( 178,671 ) $ 34,305

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 7. 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, 2022 and 2021. Fair value measurements at December 31, 2022 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Crude oil fixed price swaps $ — $ 11,696 $ — $ 11,696 Crude oil NYMEX roll swaps — 2,836 — 2,836 Natural gas basis swaps — 8,910 — 8,910 Natural gas WAHA swaps — 19,386 — 19,386 Natural gas fixed price swaps — ( 191,779 ) — ( 191,779 ) Natural gas collars — ( 30,318 ) — ( 30,318 ) Natural gas three-way collars — 598 — 598 Total $ — $ ( 178,671 ) $ — $ ( 178,671 ) Fair value measurements at December 31, 2021 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Natural gas fixed price swaps $ — $ 27,608 $ — $ 27,608 Natural gas basis swaps — ( 177 ) — ( 177 ) Natural gas collars — 3,986 — 3,986 Natural gas three-way collars — 1,931 — 1,931 Crude oil NYMEX roll swaps — 957 — 957 Total $ — $ 34,305 $ — $ 34,305 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, 2022 , the Company’s commodity price assumptions were based on forward NYMEX strip prices through year-end 2027 and were then escalated at 3 % per year thereafter. Operating cost assumptions were based on current costs escalated at 3 % per year beginning in 2024. 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, 2022 , the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows, and therefore, were impaired. Such impairments totaled $ 17.5 million, which primarily reflected fair value adjustments on a property in an emerging play and on legacy properties in the Red River Units. The impaired properties were written down to their estimated fair value at the time of impairment of $ 2.1 million. 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 year ended December 31, 2020, 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, which 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. Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2022, 2021, and 2020, 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 income (loss). Year ended December 31, In thousands 2022 2021 2020 Proved property and inventory impairments $ 17,520 $ — $ 207,119 Unproved property impairments 52,897 38,370 70,822 Total $ 70,417 $ 38,370 $ 277,941 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 in 2022 and 2021. December 31, 2022 December 31, 2021 In thousands Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Debt: Credit facility $ 1,160,000 $ 1,160,000 $ 500,000 $ 500,000 Term Loan 747,073 747,073 — — Notes payable 20,041 18,300 22,356 22,000 4.5 % Senior Notes due 2023 635,648 633,600 648,078 670,200 3.8 % Senior Notes due 2024 891,404 867,400 908,061 950,000 2.268 % Senior Notes due 2026 794,062 693,100 792,621 795,200 4.375 % Senior Notes due 2028 993,076 917,200 991,880 1,082,100 5.75 % Senior Notes due 2031 1,483,843 1,412,300 1,482,319 1,769,600 2.875 % Senior Notes due 2032 792,238 600,900 791,521 780,500 4.9 % Senior Notes due 2044 692,255 527,900 692,056 781,500 Total debt $ 8,209,640 $ 7,577,773 $ 6,828,892 $ 7,351,100 The fair value of credit facility and term loan 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
	Dec. 31, 2022
Debt Disclosure [Abstract]
Long-Term Debt	Note 8. Long-Term Debt Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $ 49.6 million and $ 54.2 million at December 31, 2022 and 2021, respectively, consists of the following. December 31, In thousands 2022 2021 Credit facility $ 1,160,000 $ 500,000 Term loan 747,073 — Notes payable 20,041 22,356 4.5 % Senior Notes due 2023 (1) 635,648 648,078 3.8 % Senior Notes due 2024 891,404 908,061 2.268 % Senior Notes due 2026 794,062 792,621 4.375 % Senior Notes due 2028 993,076 991,880 5.75 % Senior Notes due 2031 1,483,843 1,482,319 2.875 % Senior Notes due 2032 792,238 791,521 4.9 % Senior Notes due 2044 692,255 692,056 Total debt 8,209,640 6,828,892 Less: Current portion of long-term debt 638,058 2,326 Long-term debt, net of current portion $ 7,571,582 $ 6,826,566 (1) The Company's 2023 Notes, which have a face value of $ 636.0 million at December 31, 2022, are scheduled to mature on April 15, 2023 and, accordingly, are included as a current liability in the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, 2022 along with the current portion of the Company's notes payable. Credit Facility On August 24, 2022, the Company amended its credit facility to increase the amount of aggregate commitments by $ 255 million from $ 2.0 billion to $ 2.255 billion and to replace LIBOR as a benchmark reference rate with Term SOFR, with all other terms, conditions, and covenants remaining substantially unchanged. The Company’s credit facility, which matures in October 2026, is unsecured and has no borrowing base requirement subject to redetermination. The Company had $ 1.16 billion of outstanding borrowings on its credit facility at December 31, 2022, which were incurred to fund a portion of the Hamm Family's November 2022 take-private transaction . 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, 2022 was 5.9 %. The Company had approximately $ 1.09 billion of borrowing availability on its credit facility at December 31, 2022 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, 2022. Senior Notes The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at December 31, 2022. 2023 Notes 2024 Notes 2026 Notes 2028 Notes 2031 Notes 2032 Notes 2044 Notes Face value (in thousands) $ 636,000 $ 893,126 $ 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, Jul 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, 2022. The senior notes are obligations of Continental Resources, Inc. Additionally, certain of the Company’s wholly-owned consolidated subsidiaries (Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, The Mineral Resources Company, SCS1 Holdings LLC, Continental Innovations LLC, Jagged Peak Energy LLC, and Parsley SoDe Water LLC) fully and unconditionally guarantee the senior notes on a joint and several basis. The financial information of the guarantor group is not materially different from the consolidated financial statements of the Company. The Company’s other subsidiaries, whose assets, equity, and results of operations attributable to the Company are not material, do not guarantee the senior notes. Issuance of Senior Notes 2021 In November 2021, the Company issued $ 800 million of 2.268% Senior Notes due 2026 and $ 800 million of 2.875% Senior Notes due 2032 and received combined total net proceeds from the offerings of $ 1.59 billion after deducting the initial purchasers' fees and original issuance discount. 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. 2020 In November 2020, the Company issued $ 1.5 billion of 5.75% Senior Notes due 2031 and received total net proceeds of $ 1.49 billion after deducting the initial purchasers' fees. The Company used the net proceeds from the offering to finance the partial repurchases of its 2022 Notes and 2023 Notes in November 2020 as further discussed below, to repay a portion of the borrowings then-outstanding on its credit facility, and for general corporate purposes. Retirement of Senior Notes 2022 In the second quarter of 2022, the Company repurchased a portion of its 2023 Notes and 2024 Notes in open market transactions, including $ 13.6 million face value of its 2023 Notes at an aggregate cost of $ 13.9 million and $ 17.9 million face value of its 2024 Notes at an aggregate cost of $ 18.3 million, in each case, including accrued and unpaid interest to the repurchase dates. The Company recognized pre-tax losses on extinguishment of debt totaling $ 0.4 million related to the repurchases. The losses are reflected in the caption “Gain (loss) on extinguishment of debt” in the consolidated statements of income (loss). 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. 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. 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. The aggregate of the principal amount, premium, and accrued interest paid upon repurchase of the 2022 Notes and 2023 Notes was $ 475.0 million and $ 828.0 million, respectively. The Company recorded pre-tax losses on extinguishment of debt totaling $ 28.9 million related to these repurchases. Term Loan In November 2022, the Company borrowed $ 750 million under a three-year term loan agreement, the proceeds of which were used to fund a portion of the Hamm Family’s November 2022 take-private transaction. The term loan matures in November 2025 and bears 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 interest rate on the term loan was 6.1 % at December 31, 2022. The term loan contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.0, consistent with the covenant requirement in the Company’s revolving credit facility. The Company was in compliance with the term loan covenants at December 31, 2022. 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, $ 2.4 million is included as a current liability in the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, 2022 associated with the loans.

Revenues

Revenues	12 Months Ended
	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer	Note 9. 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 $ 254.0 million , $ 185.1 million , and $ 159.0 million for the years ended December 31, 2022, 2021, and 2020, respectively. Operated natural gas revenues – The Company sells a substantial 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 inclusive of natural gas liquids (“NGLs”) 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 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 and NGL sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Under certain arrangements, the Company may elect 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 production. When the Company elects to take volumes in kind, it takes possession of the processed products at the tailgate of the processing facility and either sells them at the tailgate or pays third parties to transport the products 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 $ 62.4 million , $ 39.9 million , and $ 37.7 million for the years ended December 31, 2022, 2021, and 2020, respectively. Non-operated crude oil, natural gas, and NGL revenues – The Company’s proportionate share of production from non-operated properties is generally marketed at the discretion of the operators. For non-operated properties, the Company receives a net payment from the operator representing its proportionate share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds to be received by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within two to three months after the month in which production occurs. Revenues from derivative instruments – See Note 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 revenues The following table presents the disaggregation of the Company’s crude oil and natural gas revenues for the periods presented. Sales of natural gas and NGLs are combined, as a substantial majority of the Company’s natural gas sales contracts represent wellhead sales of unprocessed gas. Year ended December 31, 2022 2021 2020 In thousands Crude Oil Natural Gas and NGLs Total Crude Oil Natural Gas and NGLs Total Crude Oil Natural Gas and NGLs Total Bakken $ 3,899,749 $ 1,051,870 $ 4,951,619 $ 2,786,320 $ 562,695 $ 3,349,015 $ 1,523,348 $ 28,858 $ 1,552,206 Anadarko Basin 1,109,405 1,839,473 2,948,878 874,752 1,264,069 2,138,821 572,653 326,626 899,279 Powder River Basin 557,943 125,065 683,008 101,705 13,110 114,815 — — — Permian Basin 1,122,290 151,217 1,273,507 24,857 4,499 29,356 — — — All other 216,616 1,047 217,663 161,660 74 161,734 103,975 ( 26 ) 103,949 Crude oil, natural gas, and natural gas liquids sales $ 6,906,003 $ 3,168,672 $ 10,074,675 $ 3,949,294 $ 1,844,447 $ 5,793,741 $ 2,199,976 $ 355,458 $ 2,555,434 Performance obligations The Company satisfies the performance obligations under its commodity 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, 2022 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 substantial 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 commodity sales contracts, 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 commodity 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, natural gas, and natural gas liquids 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, natural gas, and natural gas liquids sales”. Revenues recognized during the years ended December 31, 2022, 2021, and 2020 related to performance obligations satisfied in prior reporting periods were not material.

Allowance for Credit Losses

Allowance for Credit Losses	12 Months Ended
	Dec. 31, 2022
Credit Loss [Abstract]
Allowance for Credit Losses	Note 10. Allowance for Credit Losses The Company’s principal exposure to credit risk is through the sale of its crude oil, natural gas, and NGL 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, natural gas, and natural gas liquids 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 $ 5.5 million and $ 2.8 million at December 31, 2022 and 2021 , respectively, which is reported as “Allowance for credit losses” in the consolidated balance sheets. Aggregate credit loss expenses totaled $ 3.3 million, $ 0.8 million, and $ 1.8 million for the years ended December 31, 2022, 2021, and 2020, respectively, which are included in “General and administrative expenses” in the consolidated statements of income (loss). Receivables—Crude oil, natural gas, and natural gas liquids sales The Company’s crude oil, natural gas, and NGL 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, natural gas, and NGL sales receivables. Receivables associated with crude oil, natural gas, and NGL sales are short term in nature. Receivables from the sale of crude oil, natural gas, and NGLs 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, natural gas, and NGL sales was negligible at both December 31, 2022 and December 31, 2021. 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, 2022, 2021, and 2020. 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. The Company’s allowance for credit losses on joint interest receivables totaled $ 5.5 million and $ 2.8 million at December 31, 2022 and 2021, respectively. 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, the ability to recoup amounts owed through netting of production proceeds, the balance of co-owner prepayments if any, and the co-owner’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, 2022, 2021, and 2020 .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Income Taxes	Note 11. 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 2022 2021 2020 Current income tax provision (benefit): United States federal $ 538,704 $ — $ ( 2,248 ) Various states 83,671 — 29 Total current income tax provision (benefit) 622,375 — ( 2,219 ) Deferred income tax provision (benefit): United States federal 374,802 467,051 ( 148,828 ) Various states 23,627 52,679 ( 18,143 ) Total deferred income tax provision (benefit) 398,429 519,730 ( 166,971 ) Provision (benefit) for income taxes $ 1,020,804 $ 519,730 $ ( 169,190 ) Effective tax rate 20.1 % 23.8 % 21.8 % 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, tax credits, changes in valuation allowances, and other tax items as reflected in the table below. Year ended December 31, In thousands, except tax rates 2022 2021 2020 Income (loss) before income taxes $ 5,068,413 $ 2,186,138 $ ( 774,751 ) 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 1,064,367 459,089 ( 162,698 ) Items impacting the effective tax rate: State and local income taxes, net of federal benefit 126,932 77,979 ( 24,808 ) Tax (benefit) deficiency from stock-based compensation ( 5,282 ) 5,869 4,927 Change in valuation allowance — ( 14,474 ) 14,474 Federal tax credit for increasing research activities (1) ( 151,913 ) — — Other, net ( 13,300 ) ( 8,733 ) ( 1,085 ) Provision (benefit) for income taxes $ 1,020,804 $ 519,730 $ ( 169,190 ) Effective tax rate 20.1 % 23.8 % 21.8 % (1) In 2022, the Company commenced a study to determine the amount of its qualified research activities performed during the tax years of 2018 to 2022 that qualify for a research and development income tax credit under the Internal Revenue Code. A $ 152 million decrease in the Company’s income tax provision was recognized in 2022 to account for eligible tax credits identified as a result of the study. 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 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. No valuation allowances were recognized during the year ended December 31, 2022. 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. The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2022 and 2021 are reflected in the table below. December 31, In thousands 2022 2021 Deferred tax assets United States net operating loss carryforwards $ 63,128 $ 365,602 Incentive/equity compensation 34,987 12,751 Net deferred hedge losses 42,898 — Other 31,324 29,421 Total deferred tax assets 172,337 407,774 Valuation allowance — — Total deferred tax assets, net of valuation allowance 172,337 407,774 Deferred tax liabilities Property and equipment ( 2,708,641 ) ( 2,536,938 ) Other ( 2,008 ) ( 10,720 ) Total deferred tax liabilities ( 2,710,649 ) ( 2,547,658 ) Deferred income tax liabilities, net $ ( 2,538,312 ) $ ( 2,139,884 ) As of December 31, 2022 , the Company had net operating loss (“NOL”) carryforwards in Oklahoma totaling $ 1.99 billion, of which $ 881 million expires between 2034 and 2037, and the remaining $ 1.11 billion has an indefinite life. In 2022, the Company utilized all of its previously generated federal NOL carryforwards to offset a portion of its 2022 federal taxable income and no federal NOL or tax credit carryforwards remain at December 31, 2022. Additionally, in 2022 the Company utilized all of its previously generated NOL carryforwards in North Dakota to offset a portion of its 2022 taxable income in that state and no North Dakota NOL carryforwards remain at December 31, 2022. 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 2019.

Leases

Leases	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Lessee, Operating Leases [Text Block]	Note 12. Leases The Company’s lease liabilities recognized on the balance sheet as a lessee totaled $ 24.1 million and $ 15.5 million as of December 31, 2022 and 2021, 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 2022 2021 Surface use agreements $ 18,136 $ 12,354 Field equipment 5,224 2,095 Other 781 1,025 Total $ 24,141 $ 15,474 Minimum future commitments by year for the Company’s operating leases as of December 31, 2022 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 2023 $ 5,180 2024 4,172 2025 1,885 2026 1,848 2027 1,827 Thereafter 18,351 Total operating lease liabilities, at undiscounted value $ 33,263 Less: Imputed interest ( 9,122 ) Total operating lease liabilities, at discounted present value $ 24,141 Less: Current portion of operating lease liabilities ( 4,086 ) Operating lease liabilities, net of current portion $ 20,055 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 2022 2021 2020 Lease costs: Operating lease costs $ 3,484 $ 6,653 $ 6,444 Variable lease costs 650 3,271 4,956 Short-term lease costs 124,535 77,551 107,984 Total lease costs $ 128,669 $ 87,475 $ 119,384 Other information: Right-of-use assets obtained in exchange for new operating lease liabilities $ 19,944 $ 10,481 $ 7,377 Operating cash flows from operating leases included in lease liabilities 4,370 1,731 890 Weighted average remaining lease term as of December 31 (in years) 12.0 14.4 13.2 Weighted average discount rate as of December 31 4.8 % 5.0 % 4.8 %

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 13. 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, 2022 under the arrangements amount to approximately $ 1.14 billion, of which $ 328 million is expected to be incurred in 2023, $ 291 million in 2024, $ 164 million in 2025, $ 139 million in 2026, $ 136 million in 2027, and $ 78 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. Strategic investment – See Note 18. Equity Investment for discussion of future spending commitments associated with a strategic investment announced by the Company in the first quarter of 2022. Litigation pertaining to the Company's routine operations In March 2022, the Company was named as a defendant in a case filed in the U.S. District Court for the Northern District of California by gasoline consumer plaintiffs alleging that, beginning in March 2020, the Company and the other named defendants conspired with Russia, OPEC and others to raise the price of oil and gasoline by reducing the supply of these products. The plaintiffs are seeking unspecified damages and injunctive relief. On July 1, 2022, the Company, together with other named defendants, filed motions to dismiss. On January 9, 2023, the court granted the defendants' respective motions to dismiss without leave to amend. The Company is involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material adverse effect on its financial condition, results of operations or cash flows. As of December 31, 2022 and 2021, the Company had recognized a liability within “Other noncurrent liabilities” of $ 20.2 million and $ 7.9 million, respectively, for various matters, none of which are believed to be individually significant. Litigation pertaining to take-private transaction Transactions such as the Hamm Family's take-private transaction described in Note 1. Organization and Summary of Significant Accounting Policies—Take-Private Transaction often attract litigation and demands from minority shareholders. On August 25, 2022, Walter T. Doggett, on behalf of himself and a class of all other similarly situated shareholders (“Doggett”), filed a class action petition in the District Court of Oklahoma County, Oklahoma, against Mr. Hamm, as the controlling shareholder of the Company, for alleged breaches of fiduciary duties in connection with the take-private transaction. On November 7, 2022, Doggett filed an amended class action petition adding as additional defendants the Company, certain trusts established for the benefit of Mr. Hamm and/or his family members (the “Hamm Family Trusts”), and the Company’s other directors. Doggett alleges that the defendants breached their fiduciary duties in the connection with the take-private transaction and seeks: (i) monetary damages; (ii) the costs and expenses associated with the lawsuit; and (iii) other equitable relief. On November 23, 2022, Ralph Donald Turlington, Alroc Real Estate Associates (Del.) LLC, and the Turlington Family Irrevocable Trust, on behalf of themselves and a class of all other similarly situated former shareholders (“Turlington”), filed a class action petition in the District Court of Oklahoma County, Oklahoma, against Mr. Hamm, the Hamm Family Trusts, and the Company’s other directors. Turlington alleges the defendants breached their fiduciary duties in connection with the take-private transaction and seeks: (i) monetary damages; (ii) the costs and expenses associated with the lawsuit; and (iii) other equitable relief. On November 30, 2022, Doggett and Turlington filed a motion to consolidate the Doggett and Turlington lawsuits and to appoint lead and liaison counsel. On August 11, 2022, Pembroke Pines Firefighters & Police Officers Pension Fund (“Pembroke”), a shareholder, delivered a letter (the “Pembroke Request”) to the Company requesting the inspection of certain books and records of the Company purportedly to investigate potential breaches of fiduciary duties by the Company’s directors and senior management in connection with the take-private transaction. On August 18, 2022, the Company responded to the Pembroke Request. On October 20, 2022, Pembroke updated the Pembroke Request, and the Company again responded to the Pembroke Request on October 27, 2022. The Company has subsequently produced certain information to Pembroke identified in the Pembroke Request. On November 17, 2022, Pembroke filed a verified petition in the District Court of Pottawatomie County, Oklahoma, against the Company seeking: (i) the production of certain Company books and records identified in the Pembroke Request; (ii) the costs and expenses associated with the lawsuit; and (iii) other equitable relief. On December 6, 2022, Pembroke filed a motion to intervene and stay the Doggett and Turlington lawsuits until Pembroke completes its inspection of the Company’s books and records and prepares its own lawsuit. On November 2, 2022, Kevin Barry (“Barry”), a shareholder, delivered a letter (the “Barry Request”) to the Company requesting the inspection of certain books and records of the Company purportedly to investigate potential breaches of fiduciary duties by the Company’s directors and senior management in connection with the take-private transaction. On November 9, 2022, the Company responded to the Barry Request. The Company has subsequently produced certain information to Barry identified in the Barry Request. On November 18, 2022, Barry filed a verified petition in the District Court of Oklahoma County, Oklahoma, against the Company seeking: (i) the production of certain Company books and records identified in the Barry Request; (ii) the costs and expenses associated with the lawsuit; and (iii) other equitable relief. On November 10, 2022, Kerry Panozzo (“Panozzo”), a shareholder, delivered a letter (the “Panozzo Request”) to the Company requesting the inspection of certain books and records of the Company purportedly to investigate potential breaches of fiduciary duties by the Company’s directors and senior management in connection with the take-private transaction. On November 17, 2022, the Company responded to the Panozzo Request. The Company has subsequently produced certain information to Panozzo identified in the Panozzo Request. On November 21, 2022, Panozzo filed a verified petition in the District Court of Oklahoma County, Oklahoma, against the Company seeking: (i) the production of certain Company books and records identified in the Panozzo Request; (ii) the costs and expenses associated the lawsuit; and (iii) other equitable relief. In November 2022, the Company received letters demanding appraisal of their respective shares of the Company’s common stock from FourWorld Deep Value Opportunities Fund I, LLC, FourWorld Event Opportunities, LP, FW Deep Value Opportunities I, LLC, FourWorld Global Opportunities Fund, Ltd., FourWorld Special Opportunities Fund, LLC, Corbin ERISA Opportunity Fund Ltd., and Quadre Investments, L.P. (collectively, “FourWorld”). On January 5, 2023, these parties filed a petition in the District Court of Oklahoma County, Oklahoma, seeking appraisal of their respective shares of the Company’s common stock in connection with the take-private transaction. On January 13, 2023, the Company, Mr. Hamm, the Hamm Family Trusts, and the Company’s other directors filed a motion to consolidate the Doggett, Turlington, and FourWorld lawsuits. On January 26, 2023, the Company filed a motion to stay the FourWorld appraisal lawsuit pending adjudication of the Company’s motion to consolidate the Doggett, Turlington, and FourWorld lawsuits. On February 14, 2023, Pembroke and Panozzo, on behalf of themselves and a class of all other similarly situated former shareholders, filed a class action petition in the District Court of Oklahoma County, Oklahoma, against Mr. Hamm, the Hamm Family Trusts, and the Company’s other directors. Pembroke and Panozzo allege the defendants breached their fiduciary duties in connection with the take-private transaction and seek: (i) monetary damages; (ii) the costs and expenses associated with the lawsuit; and (iii) other equitable relief. The Company, Mr. Hamm, the Hamm Family Trusts, and the Company’s other directors intend to vigorously defend themselves against the foregoing matters. Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2022
Related Party Transactions [Abstract]
Related Party Transactions	Note 14. Related Party Transactions Certain officers of the Company own or control entities that own working and royalty interests in wells operated by the Company. The Company paid revenues to these affiliates, including royalties, of $ 0.5 million, $ 0.4 million, and $ 0.2 million and received payments from these affiliates of $ 0.2 million, $ 0.1 million, and $ 0.3 million during the years ended December 31, 2022, 2021, and 2020, respectively, relating to the operations of the respective properties. At December 31, 2022 and 2021 , approximately $ 6,000 and $ 39,000 , 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, 2022 and 2021 , approximately $ 36,000 and $ 37,000 , 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 2022, 2021, and 2020 , the Company charged affiliates approximately $ 16,400 , $ 11,300 , and $ 8,100 , respectively, for use of its corporate aircraft crews, fuel, and reimbursement of expenses and received approximately $ 13,000 , $ 5,000 , and $ 9,500 from affiliates in 2022, 2021, and 2020 , respectively, in connection with such items. The Company was charged approximately $ 235,000 , $ 117,000 , and $ 120,000 , respectively, by affiliates for use of their aircraft and reimbursement of expenses during 2022, 2021, and 2020 and paid $ 219,000 , $ 84,000 , and $ 158,000 to the affiliates in 2022, 2021, and 2020, respectively. At December 31, 2022 and 2021 , approximately $ 9,800 and $ 6,300 , respectively, was due from an affiliate relating to these transactions, which is included in “Receivables — Joint interest and other” on the consolidated balance sheets. At December 31, 2022 and 2021 , approximately $ 49,000 and $ 33,000 , respectively, was due to an affiliate relating to these transactions, which is included in “Accounts payable trade” on the consolidated balance sheets.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2022
Share-based Payment Arrangement [Abstract]
Stock-Based Compensation	Note 15. Stock-Based Compensation Prior to the Hamm Family’s take-private transaction described in Note 1. Organization and Summary of Significant Accounting Policies—Take-Private Transaction , the Company granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2013 Long-Term Incentive Plan as amended (“2013 Plan”) and 2022 Long-Term Incentive Plan (“2022 Plan”). The Company’s compensation expense associated with such awards, which is included in the caption “General and administrative expenses” in the consolidated statements of income (loss), was $ 217.8 million, $ 63.2 million, and $ 64.6 million for the years ended December 31, 2022, 2021, and 2020, respectively. As of the November 22, 2022 effective time of the Hamm Family’s take-private transaction, each unvested restricted stock award previously issued under the Company’s 2013 Plan and 2022 Plan that was outstanding immediately prior to the effective time was replaced with a restricted stock unit award (the “Rollover Shares”) issued by the Company that provides the holder of such previous award with the right to receive, on the date that such restricted stock award otherwise would have been settled, and at the Company’s sole discretion, either a share of the Company, a cash award designed to provide substantially equivalent value, or any combination of the two. Upon this event, the Company remeasured the cumulative compensation expense recognized on the modified awards pursuant to ASC Topic 718, Compensation—Stock Compensation, which resulted in the recognition of additional non-cash compensation expense within “General and administrative expenses” totaling approximately $ 136 million, reflecting the increase in the value of the awards from the original grant date to the subsequent modification date. As of December 31, 2022 , the Company had 5.3 million Rollover Shares, of which the Company currently intends to settle all awards vesting in 2023, 2024, and 2025 in cash. Thus, the Rollover Shares are classified as a liability award under ASC 718 and, as of December 31, 2022 , the Company had recorded a current liability of $ 125.7 million and a non-current liability of $ 100.1 million in the captions “Current portion of incentive compensation liability” and “Incentive compensation liability, net of current portion,” respectively, in the consolidated balance sheets. Such amounts reflect the Company’s estimate of expected future cash payments multiplied by the percentage of requisite service periods that employees have completed as of December 31, 2022. The Company’s liability will be remeasured each reporting period to reflect additional services rendered by employees and to reflect changes in expected cash payments arising from underlying changes in the value of the Company. Changes in the liability will be recorded as increases or decreases to compensation expense. The Company has estimated the number of forfeitures expected to occur in determining the amount of liability and expense to recognize. A summary of changes in non-vested restricted shares from December 31, 2019 to December 31, 2022 is presented below. Number of Weighted 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 Granted 1,575,847 56.52 Vested ( 1,736,678 ) 36.04 Forfeited ( 384,536 ) 27.82 Canceled shares due to take-private transaction ( 5,349,141 ) 34.22 Non-vested restricted shares at December 31, 2022 — $ — The grant date fair value of restricted stock granted prior to the Hamm Family’s take-private transaction represented the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant was determined at the grant date fair value and was recognized over the vesting period as services were rendered by employees and directors. The Company estimated the number of forfeitures expected to occur in determining the amount of stock-based compensation expense to recognize. There were no post-vesting restrictions related to the Company’s restricted stock. The fair value at the vesting date of restricted stock that vested during 2022, 2021, and 2020 was approximately $ 98.4 million, $ 46.7 million, and $ 27.5 million, respectively.

Shareholders' Equity Attributab

Shareholders' Equity Attributable to Continental Resources	12 Months Ended
	Dec. 31, 2022
Shareholders' Equity Attributable to Continental Resources [Abstract]
Shareholders' Equity Attributable to Continental Resources	Note 16. Shareholders’ Equity Attributable to Continental Resources See the Consolidated Statements of Equity for the year ended December 31, 2022 for the impact on Shareholders’ Equity resulting from the Hamm Family’s take-private transaction consummated on November 22, 2022. Share Repurchases In May 2019 the Company’s Board of Directors approved the initiation of a share repurchase program. Share repurchases made under the program prior to the Hamm Family’s take-private transaction are reflected below for the years ended December 31, 2022, 2021, and 2020. Number of Aggregate cost (in thousands) 2020 Share Repurchases 8,122,104 $ 126,906 2021 Share Repurchases 3,198,571 123,924 2022 Share Repurchases 1,842,422 99,855 Total 13,163,097 $ 350,685 As discussed in Note 1. Organization and Summary of Significant Accounting Policies—Take-Private Transaction , on November 22, 2022 Merger Sub completed the acquisition of all outstanding shares of the Company, other than shares already owned by the Hamm Family and Rollover Shares, at an aggregate cost of approximately $ 4.31 billion, inclusive of payments issued to holders who demanded appraisal rights for their untendered shares in accordance with Oklahoma law. As of December 31, 2022, the Hamm Family holds approximately 299.6 million shares of capital stock, and such shares are the only remaining capital stock of the Company following the take-private transaction. Dividend Payments The following table summarizes the dividends paid by the Company on its then-outstanding common stock for the years ended December 31, 2022, 2021, and 2020. Amount (in thousands) Dividend per share Year Ended December 31, 2020 First quarter $ 18,367 $ 0.05 Total $ 18,367 Year Ended December 31, 2021 Second quarter $ 39,735 $ 0.11 Third quarter 54,141 $ 0.15 Fourth quarter 71,793 $ 0.20 Total $ 165,669 Year Ended December 31, 2022 First quarter $ 82,529 $ 0.23 Second quarter 100,123 $ 0.28 Third quarter 100,131 $ 0.28 Total $ 282,783

Noncontrolling Interests

Noncontrolling Interests	12 Months Ended
	Dec. 31, 2022
Noncontrolling Interest [Abstract]
Noncontrolling Interests	Note 17. 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 funds 20% of 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 $ 361.4 million and $ 369.8 million at December 31, 2022 and 2021, respectively. Joint ownership arrangement Continental maintains an arrangement with a third party to jointly own parking facilities adjacent to the companies’ corporate office buildings. The activities of the parking facilities, which are immaterial to Continental, are managed through an entity named SFPG, LLC (“SFPG”). Continental holds a controlling financial interest in SFPG and manages its operations. Accordingly, Continental consolidates the financial results of the entity and includes the results attributable to the third party within noncontrolling interests in Continental’s financial statements. The portion of Continental’s consolidated net assets attributable to the third party's ownership interest in SFPG totaled $ 11.0 million and $ 11.1 million at December 31, 2022 and 2021 , respectively.

Equity Investment

Equity Investment	12 Months Ended
	Dec. 31, 2022
Equity Method Investments and Joint Ventures [Abstract]
Equity Investment	Note 18. Equity Investment In March 2022 the Company began investing in an affiliate of Summit Carbon Solutions (“Summit”) to develop carbon capture and sequestration infrastructure. Summit was founded in 2020 with the goal of decarbonizing the biofuel and agriculture industries and seeks to lower greenhouse gas emissions by connecting industrial facilities via strategic infrastructure to capture, transport, and store carbon dioxide (“CO2”) safely and permanently in the Midwestern United States. The Company has committed to invest a total of $ 250 million with Summit over 2022 and 2023 to fund a portion of Summit’s development and construction of capture, transportation, and sequestration infrastructure, while also leveraging the Company’s operational and geologic expertise to facilitate the underground storage of CO2. Summit intends to primarily capture CO2 from ethanol plants and other industrial sources in Iowa, Nebraska, Minnesota, North Dakota, and South Dakota, and aggregate and transport the CO2 to North Dakota via pipeline, where it will be sequestered in subsurface geologic formations. The project is expected to become operational in 2024. During the year ended December 31, 2022 , the Company contributed approximately $ 210 million toward its $ 250 million commitment to Summit, which is included in the caption “Investment in unconsolidated affiliates” in the consolidated balance sheet. Upon completion of Summit’s ongoing equity raises, the Company expects to hold an approximate 22 % non-controlling ownership interest in the equity of Summit Carbon Holdings, the parent company of Summit Carbon Solutions. The Company is not the primary beneficiary of Summit and accounts for its investment under the equity method of accounting. The Company’s share of earnings/losses from its investment was immaterial for the year ended December 31, 2022 .

Crude Oil and Natural Gas Prope

Crude Oil and Natural Gas Property Information	12 Months Ended
	Dec. 31, 2022
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Crude Oil and Natural Gas Property Information	Note 19. Crude Oil and Natural Gas Property Information The tables reflected below represent consolidated figures for the Company and its subsidiaries. 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, 2022, 2021, and 2020. Year ended December 31, In thousands 2022 2021 2020 Crude oil, natural gas, and natural gas liquids sales $ 10,074,675 $ 5,793,741 $ 2,555,434 Production expenses ( 621,921 ) ( 406,906 ) ( 359,267 ) Production and ad valorem taxes ( 730,132 ) ( 404,362 ) ( 192,718 ) Transportation, gathering, processing, and compression ( 316,414 ) ( 224,989 ) ( 196,692 ) Exploration expenses ( 23,068 ) ( 21,047 ) ( 17,732 ) Depreciation, depletion, amortization and accretion ( 1,856,067 ) ( 1,872,075 ) ( 1,859,893 ) Property impairments ( 70,417 ) ( 38,370 ) ( 277,941 ) Income tax (provision) benefit (1) ( 1,512,132 ) ( 690,902 ) 83,427 Results from crude oil and natural gas producing activities $ 4,944,524 $ 2,135,090 $ ( 265,382 ) (1) Income taxes reflect the application of a combined federal and state tax rate of 23.5% for 2022 and 24.5% for both 2021 and 2020 on pre-tax income/loss generated by our operations. 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, 2022, 2021 and 2020 are presented below. See Note 2. Property Acquisitions for discussion of notable property acquisitions that gave rise to changes in acquisition costs incurred between periods. Year ended December 31, In thousands 2022 2021 2020 Property acquisition costs: Proved $ 458,762 $ 2,580,271 $ 60,494 Unproved 412,571 1,197,507 201,919 Total property acquisition costs 871,333 3,777,778 262,413 Exploration Costs 343,117 171,549 48,282 Development Costs 2,185,645 1,174,828 1,053,532 Total $ 3,400,095 $ 5,124,155 $ 1,364,227 Costs incurred above include asset retirement costs and revisions thereto of $ 30.8 million, $ 31.1 million and $ 18.1 million for the years ended December 31, 2022, 2021 and 2020, 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, 2022 and 2021 are as follows: December 31, In thousands 2022 2021 Proved crude oil and natural gas properties $ 34,741,054 $ 31,613,656 Unproved crude oil and natural gas properties 1,513,627 1,358,673 Total 36,254,681 32,972,329 Less accumulated depreciation, depletion and amortization ( 18,134,473 ) ( 16,310,054 ) Net capitalized costs $ 18,120,208 $ 16,662,275 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 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 2022 2021 2020 Balance at January 1 $ 37,673 $ 32,737 $ 6,257 Additions to capitalized exploratory well costs pending determination of proved reserves 286,059 122,068 32,880 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves ( 229,348 ) ( 117,131 ) ( 72 ) Capitalized exploratory well costs charged to expense ( 9,562 ) ( 1 ) ( 6,328 ) Balance at December 31 $ 84,822 $ 37,673 $ 32,737 Number of gross wells 36 17 16 As of December 31, 2022 , 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, 2022
Supplemental Crude Oil and Natural Gas Information [Abstract]
Supplemental Crude Oil and Natural Gas Information (Unaudited)	Note 20. 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 %, 98 %, and 95 % of the Company’s total proved reserves as of December 31, 2022, 2021, and 2020, respectively. Remaining reserve estimates were prepared by the Company’s internal technical staff. All proved reserves stated herein are located in the United States. 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, 2022, 2021, and 2020 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, 2022, 2021, and 2020 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, 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 ( 85,604 ) ( 284,738 ) ( 133,061 ) Extensions, discoveries and other additions 194,848 1,203,850 395,490 Production ( 72,827 ) ( 442,980 ) ( 146,657 ) Sales of minerals in place ( 25 ) ( 712 ) ( 144 ) Purchases of minerals in place 59,617 259,253 102,826 Proved reserves as of December 31, 2022 889,539 5,845,352 1,863,764 Revisions of previous estimates. Revisions for 2022 are comprised of (i) upward price revisions of 29 MMBo and 105 Bcf (totaling 46 MMBoe) due to an increase in average crude oil and natural gas prices in 2022 compared to 2021, (ii) the removal of 35 MMBo and 225 Bcf (totaling 72 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to 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 71 MMBo and 401 Bcf (totaling 137 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 9 MMBo and upward revisions for natural gas reserves of 236 Bcf (netting to 31 MMBoe of upward revisions) due to changes in ownership interests, operating costs, anticipated production, and other factors. 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 to 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, (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. 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 2022 , proved reserve additions totaled 69 MMBo and 241 Bcf (totaling 109 MMBoe) in the Bakken, 29 MMBo and 751 Bcf (totaling 154 MMBoe) in the Anadarko Basin, 13 MMBo and 32 Bcf (totaling 18 MMBoe) in the Powder River Basin, and 84 MMBo and 178 Bcf (totaling 114 MMBoe) in the Permian Basin. 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. See Note 2. Property Acquisitions for discussion of notable property acquisitions for the years ended December 31, 2022, 2021, and 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, 2022, 2021, and 2020: December 31, 2022 2021 2020 Proved Developed Reserves Crude oil (MBbl) 454,299 424,153 281,906 Natural Gas (MMcf) 3,486,774 2,901,147 2,073,011 Total (MBoe) 1,035,428 907,678 627,407 Proved Undeveloped Reserves Crude oil (MBbl) 435,240 369,377 215,069 Natural Gas (MMcf) 2,358,578 2,209,532 1,567,713 Total (MBoe) 828,336 737,632 476,355 Total Proved Reserves Crude oil (MBbl) 889,539 793,530 496,975 Natural Gas (MMcf) 5,845,352 5,110,679 3,640,724 Total (MBoe) 1,863,764 1,645,310 1,103,762 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, 2022, 2021, and 2020. 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 2022 2021 2020 Future cash inflows $ 115,338,240 $ 67,034,046 $ 21,334,235 Future production costs ( 26,570,673 ) ( 18,837,000 ) ( 7,750,834 ) Future development and abandonment costs ( 9,651,656 ) ( 7,751,678 ) ( 3,950,752 ) Future income taxes (1) ( 16,158,309 ) ( 7,862,849 ) ( 724,569 ) Future net cash flows 62,957,602 32,582,519 8,908,080 10% annual discount for estimated timing of cash flows ( 31,050,041 ) ( 15,946,126 ) ( 4,254,515 ) Standardized measure of discounted future net cash flows $ 31,907,561 $ 16,636,393 $ 4,653,565 (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, 2022, 2021, and 2020 . The weighted average crude oil price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $ 89.47 , $ 62.19 , and $ 34.34 per barrel at December 31, 2022, 2021, and 2020, respectively. The weighted average natural gas price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $ 6.12 , $ 3.46 , and $ 1.17 per Mcf at December 31, 2022, 2021, and 2020, 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 2022 2021 2020 Standardized measure of discounted future net cash flows at January 1 $ 16,636,393 $ 4,653,565 $ 10,461,641 Extensions, discoveries and improved recoveries, less related costs 7,331,375 2,985,056 187,981 Revisions of previous quantity estimates ( 3,096,189 ) 816,674 ( 2,952,489 ) Changes in estimated future development and abandonment costs 1,283,405 706,168 4,760,286 Purchases (sales) of minerals in place, net 1,852,313 3,408,365 53,742 Net change in prices and production costs 15,251,976 9,396,945 ( 6,912,031 ) Accretion of discount 2,049,284 489,273 1,183,993 Sales of crude oil and natural gas produced, net of production costs ( 8,406,208 ) ( 4,757,483 ) ( 1,806,758 ) Development costs incurred during the period 1,302,693 683,212 863,101 Change in timing of estimated future production and other 1,899,889 1,871,903 ( 2,325,024 ) Change in income taxes ( 4,197,370 ) ( 3,617,285 ) 1,139,123 Net change 15,271,168 11,982,828 ( 5,808,076 ) Standardized measure of discounted future net cash flows at December 31 $ 31,907,561 $ 16,636,393 $ 4,653,565

Organization and Summary of S_2

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2022
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 the exploration, development, management, and production of crude oil and natural gas and associated products with properties primarily located in four leading basins in the United States – the Bakken field of North Dakota and Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. Additionally, the Company pursues the acquisition and management of perpetually owned minerals located in certain of its key operating areas.
Take-Private Transaction	Take-Private Transaction On October 16, 2022 , the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Omega Acquisition, Inc. (“Merger Sub”), an entity owned by the Company’s founder, Harold G. Hamm. Pursuant to the Merger Agreement, on October 24, 2022 Merger Sub commenced a tender offer (the “Offer”) to purchase any and all of the outstanding shares of the Company’s common stock for $ 74.28 per share in cash (the “Offer Price”), other than: (i) shares of common stock owned by Mr. Hamm, certain of his family members and their affiliated entities (collectively, the “Hamm Family”) and (ii) shares of common stock underlying unvested equity awards issued pursuant to the Company’s long-term incentive plans (collectively, the “Rollover Shares”). The Offer expired at one minute after 11:59 p.m., New York City time, on November 21, 2022. As of the expiration of the Offer, a total of approximately 36.3 million shares were validly tendered and not validly withdrawn pursuant to the Offer. In addition, notices of guaranteed delivery were delivered for approximately 3.4 million shares. Each condition to the Offer was satisfied and, on November 22, 2022, Merger Sub irrevocably accepted for payment all shares that were validly tendered and not withdrawn. On November 22, 2022, immediately prior to the acceptance of shares for payment, Mr. Hamm contributed 100 % of the capital stock of Merger Sub to the Company. In addition, following consummation of the Offer, Merger Sub merged with and into the Company, with the Company continuing as the surviving corporation wholly-owned by the Hamm Family (the “Merger”). At the effective time of the Merger, each remaining share of the Company not purchased in the Offer (other than (i) the Rollover Shares; (ii) shares owned by the Company as treasury stock or owned by any wholly owned subsidiary of the Company, including shares irrevocably accepted by Merger Sub pursuant to the Offer; and (iii) shares held by a holder who properly demanded appraisal rights for such shares in accordance with Oklahoma law), was converted into the right to receive an amount in cash equal to the Offer Price, without interest and subject to any required tax withholding. At the effective time of the Merger: (i) each share of the Company held by a member of the Hamm Family was converted into an identical number of newly issued shares of the Company, as the surviving corporation, having identical rights to the previously existing shares held by such holder, and such converted shares of the surviving corporation are the only capital stock of the surviving corporation outstanding following the Merger; and (ii) the Rollover Shares underlying each unvested restricted stock award issued under the Company’s long-term incentive plans that was outstanding immediately prior to the effective time were replaced with a restricted stock unit award issued by the Company that provides the holder of such previous award with the right to receive, on the date that such restricted stock award otherwise would have been settled, and at the Company’s sole discretion, either a share of the Company, a cash award designed to provide substantially equivalent value, or any combination of the two, in each case, together with any unpaid dividends accrued on such restricted stock award. A total of approximately 58.1 million shares of Continental’s common stock were purchased pursuant to the take-private transaction for total cash consideration of approximately $ 4.31 billion, inclusive of payments issued to holders who demanded appraisal rights for their untendered shares in accordance with Oklahoma law. The purchase of outstanding shares was funded by Continental through the use of approximately $ 2.2 billion of cash on hand, $ 1.3 billion of credit facility borrowings, and the execution of a $ 750 million three-year term loan as further described in Note 8. Long-Term Debt . See the Consolidated Statements of Equity for the year ended December 31, 2022 for the impact on the components of Shareholders’ Equity resulting from the take-private transaction. As of December 31, 2022, the Hamm Family holds approximately 299.6 million shares of capital stock of the Company, as the surviving corporation, and there remains approximately 5.3 million Rollover Shares. See Note 15. Stock-Based Compensation for a discussion of the Company’s accounting for the Rollover Shares. The Company incurred $ 32 million of legal and advisory fees in connection with the take-private transaction which are included in the caption “Transaction costs” in the consolidated statements of income (loss) for the year ended December 31, 2022. Following the completion of the take-private transaction: (i) our common stock ceased to be listed on the New York Stock Exchange effective November 23, 2022, (ii) our common stock was deregistered under Section 12(b) of the Securities Exchange Act of 1934 as amended (the “Exchange Act”), and (iii) we suspended our reporting obligations under Section 15(d) of the Exchange Act. As a result, certain of the corporate governance, disclosure, and other provisions applicable to a company with listed equity securities and reporting obligations under the Exchange Act no longer apply to us. We will continue to furnish Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K with the SEC as required by our senior note indentures.
Basis of presentation of consolidated financial statements	Basis of presentation of consolidated financial statements The consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, and entities in which the Company has a controlling financial interest. Intercompany accounts and transactions have been eliminated upon consolidation. Noncontrolling interests reflected herein represent third party ownership in the net assets of consolidated subsidiaries. The portions of consolidated net income (loss) and equity attributable to the noncontrolling interests are presented separately in the Company’s financial statements. 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, natural gas, and natural gas liquids in the United States. Investments in entities in which the Company has the ability to exercise significant influence, but does not control, are accounted for using the equity method of accounting. In applying the equity method, the investments are initially recognized at cost and are subsequently adjusted for the Company’s proportionate share of earnings, losses, contributions, and distributions as applicable. See Note 18. Equity Investment for discussion of a strategic investment made by the Company in 2022 that is accounted for under the equity method. The Company evaluated its December 31, 2022 financial statements for subsequent events through February 22, 2023, the date the financial statements were available to be issued.
Use of Estimates	Use of estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from those estimates. The most significant estimates and assumptions impacting reported results are estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties.
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, 2022 , the Company had cash deposits in excess of federally insured amounts of approximately $ 136.4 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 $ 5.5 million and $ 2.8 million as of December 31, 2022 and 2021, respectively. See Note 10. Allowance for Credit Losses for additional information.
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, 2022 , no purchaser accounted for more than 10 % of the Company’s total crude oil, natural gas, and natural gas liquids sales for 2022 . 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, 2022 and 2021 consisted of the following: December 31, In thousands 2022 2021 Tubular goods and equipment $ 38,636 $ 12,506 Crude oil 130,192 93,062 Natural gas 4,436 — Total $ 173,264 $ 105,568
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. Production expenses are those costs incurred by the Company to operate and maintain its crude oil and natural gas properties and associated equipment and facilities. Production expenses include but are not limited to labor costs to operate the Company’s properties, repairs and maintenance, certain waste water disposal costs, utility costs, certain workover-related costs, and materials and supplies utilized in the Company’s operations.
Service Property and Equipment	Service property and equipment Service property and equipment consist primarily of automobiles and aircraft; machinery and equipment; gathering and recycling systems; storage tanks; office and computer equipment, software, furniture and fixtures; and buildings and improvements. Major renewals and replacements are capitalized and stated at cost, while maintenance and repairs are expensed as incurred. Depreciation and amortization of service property and equipment are provided in amounts sufficient to expense the cost of depreciable assets to operations over their estimated useful lives using the straight-line method. The estimated useful lives of service property and equipment are as follows: Service property and equipment Useful Lives Automobiles and aircraft 5 - 10 Machinery and equipment 6 - 30 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. The Company’s primary asset retirement obligations relate to future plugging and abandonment costs and related disposal of facilities on its crude oil and natural gas properties.
Asset Impairment	Asset impairment Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Impairment losses for unproved properties are generally recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The Company’s impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management.
Debt Issuance Costs	Debt issuance costs Costs incurred in connection with the execution of the Company’s notes payable, revolving credit facility, term loan 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 $ 56.3 million and $ 60.6 million (net of accumulated amortization of $ 46.3 million and $ 36.9 million) relating to its long-term debt at December 31, 2022 and 2021, respectively. Unamortized capitalized costs associated with the Company’s Notes, note payable, and term loan totaled $ 46.8 million and $ 50.9 million at December 31, 2022 and 2021, 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 $ 9.4 million and $ 9.7 million at December 31, 2022 and 2021, respectively, and are reflected in “Other noncurrent assets” on the consolidated balance sheets. For the years ended December 31, 2022, 2021 and 2020 , the Company recognized amortization expense associated with capitalized debt issuance costs of $ 9.3 million, $ 7.2 million, and $ 7.8 million, respectively, which are reflected in “Interest expense” on the consolidated statements of income (loss).
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 income (loss) under the caption “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, 2022 and 2021 .
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 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. Prior to the Hamm Family's take-private transaction, in periods where the Company had net income, diluted earnings per share reflected the potential dilution of non-vested restricted stock awards, which was calculated using the treasury stock method.
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 $ 254.0 million , $ 185.1 million , and $ 159.0 million for the years ended December 31, 2022, 2021, and 2020, respectively. Operated natural gas revenues – The Company sells a substantial 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 inclusive of natural gas liquids (“NGLs”) 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 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 and NGL sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Under certain arrangements, the Company may elect 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 production. When the Company elects to take volumes in kind, it takes possession of the processed products at the tailgate of the processing facility and either sells them at the tailgate or pays third parties to transport the products 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 $ 62.4 million , $ 39.9 million , and $ 37.7 million for the years ended December 31, 2022, 2021, and 2020, respectively. Non-operated crude oil, natural gas, and NGL revenues – The Company’s proportionate share of production from non-operated properties is generally marketed at the discretion of the operators. For non-operated properties, the Company receives a net payment from the operator representing its proportionate share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds to be received by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within two to three months after the month in which production occurs. Revenues from derivative instruments – See Note 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.

Revenue from Contract with Cust

Revenue from Contract with Customer (Policies)	12 Months Ended
	Dec. 31, 2022
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 $ 254.0 million , $ 185.1 million , and $ 159.0 million for the years ended December 31, 2022, 2021, and 2020, respectively. Operated natural gas revenues – The Company sells a substantial 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 inclusive of natural gas liquids (“NGLs”) 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 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 and NGL sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Under certain arrangements, the Company may elect 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 production. When the Company elects to take volumes in kind, it takes possession of the processed products at the tailgate of the processing facility and either sells them at the tailgate or pays third parties to transport the products 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 $ 62.4 million , $ 39.9 million , and $ 37.7 million for the years ended December 31, 2022, 2021, and 2020, respectively. Non-operated crude oil, natural gas, and NGL revenues – The Company’s proportionate share of production from non-operated properties is generally marketed at the discretion of the operators. For non-operated properties, the Company receives a net payment from the operator representing its proportionate share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds to be received by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within two to three months after the month in which production occurs. Revenues from derivative instruments – See Note 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.

Organization and Summary of S_3

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Components of Inventories	The components of inventory as of December 31, 2022 and 2021 consisted of the following: December 31, In thousands 2022 2021 Tubular goods and equipment $ 38,636 $ 12,506 Crude oil 130,192 93,062 Natural gas 4,436 — Total $ 173,264 $ 105,568
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 - 30 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, 2020 through December 31, 2022: In thousands 2022 2021 2020 Asset retirement obligations at January 1 $ 219,824 $ 179,676 $ 153,673 Accretion expense 12,857 11,125 9,393 Revisions (1) ( 6,672 ) ( 1,291 ) 10,743 Plus: Additions for new assets 37,413 32,351 7,048 Less: Plugging costs and sold assets ( 2,335 ) ( 2,037 ) ( 1,181 ) Total asset retirement obligations at December 31 $ 261,087 $ 219,824 $ 179,676 Less: Current portion of asset retirement obligations at December 31 (2) 3,935 4,123 2,482 Non-current portion of asset retirement obligations at December 31 $ 257,152 $ 215,701 $ 177,194 (1) Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties. Balance is included in the caption “Accrued liabilities and other” in the consolidated balance sheets.
Calculation of Basic and Diluted Weighted Average Shares and Net Income per Share	The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share attributable to the Company for the years ended December 31, 2022, 2021, and 2020. Year ended December 31, In thousands, except per share data 2022 2021 2020 Net income (loss) attributable to Continental Resources (numerator) $ 4,024,558 $ 1,660,968 $ ( 596,869 ) Weighted average shares (denominator): Weighted average shares - basic 351,392 360,434 361,538 Non-vested restricted stock and restricted stock units (1) — 4,019 — Weighted average shares - diluted 351,392 364,453 361,538 Net income (loss) per share attributable to Continental Resources: Basic $ 11.45 $ 4.61 $ ( 1.65 ) Diluted $ 11.45 $ 4.56 $ ( 1.65 ) (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. At December 31, 2022, the Company's outstanding Rollover Shares are expected to be paid in cash, not common stock, upon vesting and are classified as liability awards pursuant to ASC Topic 718, Compensation—Stock Compensation. As a result, no potential dilutive effect for the Rollover Shares is presented for the year ended December 31, 2022.

Property Acquisitions (Tables)

Property Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2022
Business Combination and Asset Acquisition [Abstract]
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 )

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2022
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 2022 2021 2020 Supplemental cash flow information: Cash paid for interest $ 279,571 $ 214,727 $ 256,633 Cash paid for income taxes (1) 470,147 3 4 Cash received for income tax refunds 16 58 9,600 Non-cash investing activities: Asset retirement obligation additions and revisions, net 30,741 31,060 17,791 (1) Amount for 2022 represents estimated quarterly payments for 2022 U.S. federal income taxes based on an estimate of federal taxable income for the year.

Net Property and Equipment (Tab

Net Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment, Net [Abstract]
Schedule of Net Property and Equipment	Net property and equipment includes the following at December 31, 2022 and 2021. December 31, In thousands 2022 2021 Proved crude oil and natural gas properties $ 34,741,054 $ 31,613,656 Unproved crude oil and natural gas properties 1,513,627 1,358,673 Service properties, equipment and other 549,528 484,989 Total property and equipment 36,804,209 33,457,318 Accumulated depreciation, depletion and amortization ( 18,332,295 ) ( 16,481,853 ) Net property and equipment $ 18,471,914 $ 16,975,465

Accrued Liabilities and Other (

Accrued Liabilities and Other (Tables)	12 Months Ended
	Dec. 31, 2022
Accrued Liabilities and Other Liabilities [Abstract]
Schedule of Accrued Liabilities and Other	Accrued liabilities and other includes the following at December 31, 2022 and 2021: December 31, In thousands 2022 2021 Prepaid advances from joint interest owners $ 15,575 $ 18,964 Accrued compensation 81,646 82,844 Accrued production taxes, ad valorem taxes and other non-income taxes 145,436 90,597 Accrued interest 83,724 75,983 Current portion of asset retirement obligations 3,935 4,123 Other 13,461 13,229 Accrued liabilities and other $ 343,777 $ 285,740

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2022
Derivative [Line Items]
Summary of Outstanding Contracts with Respect to Natural Gas	At December 31, 2022 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 Sold Floor Ceiling January 2023 - December 2023 Basis Swaps - NGPL TXOK 75,000 MMBtus/day $ ( 0.17 ) January 2023 - March 2023 Collars - Henry Hub 360,000 MMBtus/day $ 3.91 $ 5.45 Three-way collars - Henry Hub 50,000 MMBtus/day $ 3.00 $ 4.32 $ 5.00 Swaps - Henry Hub 210,000 MMBtus/day $ 4.26 Swaps - WAHA 55,000 MMBtus/day $ 2.81 April 2023 - September 2023 Swaps - Henry Hub 405,000 MMBtus/day $ 3.28 Swaps - WAHA 55,000 MMBtus/day $ 2.81 October 2023 - December 2023 Collars - Henry Hub 200,000 MMBtus/day $ 3.12 $ 4.09 Swaps - Henry Hub 210,000 MMBtus/day $ 3.51 Swaps - WAHA 55,000 MMBtus/day $ 2.81 January 2024 - December 2024 Collars - Henry Hub 50,000 MMBtus/day $ 3.12 $ 4.09 Swaps - Henry Hub 325,000 MMBtus/day $ 3.31 Swaps - WAHA 25,000 MMBtus/day $ 3.43 January 2025 - December 2025 Swaps - Henry Hub 60,000 MMBtus/day $ 3.75 January 2026 - December 2026 Swaps - Henry Hub 50,000 MMBtus/day $ 4.42 Crude oil derivatives Weighted Average Period and Type of Contract Average Volumes Hedged Roll Swaps Fixed Swaps January 2023 - December 2023 Roll Swaps - NYMEX 12,000 Bbls/day $ 1.07 Fixed Swaps - WTI 8,000 Bbls/day $ 83.19
Realized and Unrealized Gains and Losses on Derivative Instruments	Year ended December 31, In thousands 2022 2021 2020 Cash received (paid) on derivatives: Crude oil fixed price swaps $ — $ ( 44,463 ) $ ( 31,179 ) Crude oil collars — ( 9,365 ) — Crude oil NYMEX roll swaps ( 9,234 ) ( 163 ) — Natural gas basis swaps 9,674 — — Natural gas WAHA swaps ( 16,350 ) — — Natural gas fixed price swaps ( 353,326 ) ( 84,141 ) 1,071 Natural gas collars ( 66,596 ) ( 11,546 ) 1,958 Natural gas three-way collars ( 22,287 ) — — Cash received (paid) on derivatives, net ( 458,119 ) ( 149,678 ) ( 28,150 ) Non-cash gain (loss) on derivatives: Crude oil collars — 227 ( 227 ) Crude oil fixed price swaps 11,696 — — Crude oil NYMEX roll swaps 1,879 957 — Natural gas basis swaps 9,088 ( 177 ) — Natural gas WAHA swaps 19,386 — — Natural gas fixed price swaps ( 219,388 ) 25,565 2,043 Natural gas collars ( 34,303 ) ( 7,690 ) 11,676 Natural gas three-way collars ( 1,334 ) 1,932 — Non-cash gain (loss) on derivatives, net ( 212,976 ) 20,814 13,492 Loss on derivative instruments, net $ ( 671,095 ) $ ( 128,864 ) $ ( 14,658 )
Gross Amounts of Recognized 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, 2022, all at fair value. December 31, In thousands 2022 2021 Commodity derivative assets: Gross amounts of recognized assets $ 50,559 $ 42,903 Gross amounts offset on balance sheet ( 7,731 ) ( 7,381 ) Net amounts of assets on balance sheet 42,828 35,522 Commodity derivative liabilities: Gross amounts of recognized liabilities ( 229,230 ) ( 8,598 ) Gross amounts offset on balance sheet 7,731 7,381 Net amounts of liabilities on balance sheet $ ( 221,499 ) $ ( 1,217 )
Derivatives Not Designated as Hedging Instruments	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 2022 2021 Derivative assets $ 39,280 $ 22,334 Derivative assets, noncurrent 3,548 13,188 Net amounts of assets on balance sheet 42,828 35,522 Derivative liabilities ( 88,136 ) ( 899 ) Derivative liabilities, noncurrent ( 133,363 ) ( 318 ) Net amounts of liabilities on balance sheet ( 221,499 ) ( 1,217 ) Total derivative assets (liabilities), net $ ( 178,671 ) $ 34,305

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 and 2021. Fair value measurements at December 31, 2022 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Crude oil fixed price swaps $ — $ 11,696 $ — $ 11,696 Crude oil NYMEX roll swaps — 2,836 — 2,836 Natural gas basis swaps — 8,910 — 8,910 Natural gas WAHA swaps — 19,386 — 19,386 Natural gas fixed price swaps — ( 191,779 ) — ( 191,779 ) Natural gas collars — ( 30,318 ) — ( 30,318 ) Natural gas three-way collars — 598 — 598 Total $ — $ ( 178,671 ) $ — $ ( 178,671 ) Fair value measurements at December 31, 2021 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Natural gas fixed price swaps $ — $ 27,608 $ — $ 27,608 Natural gas basis swaps — ( 177 ) — ( 177 ) Natural gas collars — 3,986 — 3,986 Natural gas three-way collars — 1,931 — 1,931 Crude oil NYMEX roll swaps — 957 — 957 Total $ — $ 34,305 $ — $ 34,305
Property Impairments	The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the consolidated statements of income (loss). Year ended December 31, In thousands 2022 2021 2020 Proved property and inventory impairments $ 17,520 $ — $ 207,119 Unproved property impairments 52,897 38,370 70,822 Total $ 70,417 $ 38,370 $ 277,941
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 in 2022 and 2021. December 31, 2022 December 31, 2021 In thousands Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Debt: Credit facility $ 1,160,000 $ 1,160,000 $ 500,000 $ 500,000 Term Loan 747,073 747,073 — — Notes payable 20,041 18,300 22,356 22,000 4.5 % Senior Notes due 2023 635,648 633,600 648,078 670,200 3.8 % Senior Notes due 2024 891,404 867,400 908,061 950,000 2.268 % Senior Notes due 2026 794,062 693,100 792,621 795,200 4.375 % Senior Notes due 2028 993,076 917,200 991,880 1,082,100 5.75 % Senior Notes due 2031 1,483,843 1,412,300 1,482,319 1,769,600 2.875 % Senior Notes due 2032 792,238 600,900 791,521 780,500 4.9 % Senior Notes due 2044 692,255 527,900 692,056 781,500 Total debt $ 8,209,640 $ 7,577,773 $ 6,828,892 $ 7,351,100

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Long-Term Debt	Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $ 49.6 million and $ 54.2 million at December 31, 2022 and 2021, respectively, consists of the following. December 31, In thousands 2022 2021 Credit facility $ 1,160,000 $ 500,000 Term loan 747,073 — Notes payable 20,041 22,356 4.5 % Senior Notes due 2023 (1) 635,648 648,078 3.8 % Senior Notes due 2024 891,404 908,061 2.268 % Senior Notes due 2026 794,062 792,621 4.375 % Senior Notes due 2028 993,076 991,880 5.75 % Senior Notes due 2031 1,483,843 1,482,319 2.875 % Senior Notes due 2032 792,238 791,521 4.9 % Senior Notes due 2044 692,255 692,056 Total debt 8,209,640 6,828,892 Less: Current portion of long-term debt 638,058 2,326 Long-term debt, net of current portion $ 7,571,582 $ 6,826,566 (1) The Company's 2023 Notes, which have a face value of $ 636.0 million at December 31, 2022, are scheduled to mature on April 15, 2023 and, accordingly, are included as a current liability in the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, 2022 along with the current portion of the Company's notes payable.
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, 2022. 2023 Notes 2024 Notes 2026 Notes 2028 Notes 2031 Notes 2032 Notes 2044 Notes Face value (in thousands) $ 636,000 $ 893,126 $ 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, Jul 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
	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following table presents the disaggregation of the Company’s crude oil and natural gas revenues for the periods presented. Sales of natural gas and NGLs are combined, as a substantial majority of the Company’s natural gas sales contracts represent wellhead sales of unprocessed gas. Year ended December 31, 2022 2021 2020 In thousands Crude Oil Natural Gas and NGLs Total Crude Oil Natural Gas and NGLs Total Crude Oil Natural Gas and NGLs Total Bakken $ 3,899,749 $ 1,051,870 $ 4,951,619 $ 2,786,320 $ 562,695 $ 3,349,015 $ 1,523,348 $ 28,858 $ 1,552,206 Anadarko Basin 1,109,405 1,839,473 2,948,878 874,752 1,264,069 2,138,821 572,653 326,626 899,279 Powder River Basin 557,943 125,065 683,008 101,705 13,110 114,815 — — — Permian Basin 1,122,290 151,217 1,273,507 24,857 4,499 29,356 — — — All other 216,616 1,047 217,663 161,660 74 161,734 103,975 ( 26 ) 103,949 Crude oil, natural gas, and natural gas liquids sales $ 6,906,003 $ 3,168,672 $ 10,074,675 $ 3,949,294 $ 1,844,447 $ 5,793,741 $ 2,199,976 $ 355,458 $ 2,555,434

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
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 2022 2021 2020 Current income tax provision (benefit): United States federal $ 538,704 $ — $ ( 2,248 ) Various states 83,671 — 29 Total current income tax provision (benefit) 622,375 — ( 2,219 ) Deferred income tax provision (benefit): United States federal 374,802 467,051 ( 148,828 ) Various states 23,627 52,679 ( 18,143 ) Total deferred income tax provision (benefit) 398,429 519,730 ( 166,971 ) Provision (benefit) for income taxes $ 1,020,804 $ 519,730 $ ( 169,190 ) Effective tax rate 20.1 % 23.8 % 21.8 %
Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate	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, tax credits, changes in valuation allowances, and other tax items as reflected in the table below. Year ended December 31, In thousands, except tax rates 2022 2021 2020 Income (loss) before income taxes $ 5,068,413 $ 2,186,138 $ ( 774,751 ) 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 1,064,367 459,089 ( 162,698 ) Items impacting the effective tax rate: State and local income taxes, net of federal benefit 126,932 77,979 ( 24,808 ) Tax (benefit) deficiency from stock-based compensation ( 5,282 ) 5,869 4,927 Change in valuation allowance — ( 14,474 ) 14,474 Federal tax credit for increasing research activities (1) ( 151,913 ) — — Other, net ( 13,300 ) ( 8,733 ) ( 1,085 ) Provision (benefit) for income taxes $ 1,020,804 $ 519,730 $ ( 169,190 ) Effective tax rate 20.1 % 23.8 % 21.8 % (1) In 2022, the Company commenced a study to determine the amount of its qualified research activities performed during the tax years of 2018 to 2022 that qualify for a research and development income tax credit under the Internal Revenue Code. A $ 152 million decrease in the Company’s income tax provision was recognized in 2022 to account for eligible tax credits identified as a result of the study.
Components of Deferred Tax Assets and Liabilities	The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2022 and 2021 are reflected in the table below. December 31, In thousands 2022 2021 Deferred tax assets United States net operating loss carryforwards $ 63,128 $ 365,602 Incentive/equity compensation 34,987 12,751 Net deferred hedge losses 42,898 — Other 31,324 29,421 Total deferred tax assets 172,337 407,774 Valuation allowance — — Total deferred tax assets, net of valuation allowance 172,337 407,774 Deferred tax liabilities Property and equipment ( 2,708,641 ) ( 2,536,938 ) Other ( 2,008 ) ( 10,720 ) Total deferred tax liabilities ( 2,710,649 ) ( 2,547,658 ) Deferred income tax liabilities, net $ ( 2,538,312 ) $ ( 2,139,884 )

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Summary of Leasing Activities	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 2022 2021 Surface use agreements $ 18,136 $ 12,354 Field equipment 5,224 2,095 Other 781 1,025 Total $ 24,141 $ 15,474
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	Minimum future commitments by year for the Company’s operating leases as of December 31, 2022 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 2023 $ 5,180 2024 4,172 2025 1,885 2026 1,848 2027 1,827 Thereafter 18,351 Total operating lease liabilities, at undiscounted value $ 33,263 Less: Imputed interest ( 9,122 ) Total operating lease liabilities, at discounted present value $ 24,141 Less: Current portion of operating lease liabilities ( 4,086 ) Operating lease liabilities, net of current portion $ 20,055
Lease, Cost [Table Text Block]	Year ended December 31, In thousands, except weighted average data 2022 2021 2020 Lease costs: Operating lease costs $ 3,484 $ 6,653 $ 6,444 Variable lease costs 650 3,271 4,956 Short-term lease costs 124,535 77,551 107,984 Total lease costs $ 128,669 $ 87,475 $ 119,384 Other information: Right-of-use assets obtained in exchange for new operating lease liabilities $ 19,944 $ 10,481 $ 7,377 Operating cash flows from operating leases included in lease liabilities 4,370 1,731 890 Weighted average remaining lease term as of December 31 (in years) 12.0 14.4 13.2 Weighted average discount rate as of December 31 4.8 % 5.0 % 4.8 %

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2019 to December 31, 2022 is presented below. Number of Weighted 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 Granted 1,575,847 56.52 Vested ( 1,736,678 ) 36.04 Forfeited ( 384,536 ) 27.82 Canceled shares due to take-private transaction ( 5,349,141 ) 34.22 Non-vested restricted shares at December 31, 2022 — $ —

Shareholders' Equity Attribut_2

Shareholders' Equity Attributable to Continental Resources (Tables)	12 Months Ended
	Dec. 31, 2022
Shareholders' Equity Attributable to Continental Resources [Abstract]
Share Repurchase Program	Number of Aggregate cost (in thousands) 2020 Share Repurchases 8,122,104 $ 126,906 2021 Share Repurchases 3,198,571 123,924 2022 Share Repurchases 1,842,422 99,855 Total 13,163,097 $ 350,685
Summary of Dividend Payments	The following table summarizes the dividends paid by the Company on its then-outstanding common stock for the years ended December 31, 2022, 2021, and 2020. Amount (in thousands) Dividend per share Year Ended December 31, 2020 First quarter $ 18,367 $ 0.05 Total $ 18,367 Year Ended December 31, 2021 Second quarter $ 39,735 $ 0.11 Third quarter 54,141 $ 0.15 Fourth quarter 71,793 $ 0.20 Total $ 165,669 Year Ended December 31, 2022 First quarter $ 82,529 $ 0.23 Second quarter 100,123 $ 0.28 Third quarter 100,131 $ 0.28 Total $ 282,783

Crude Oil and Natural Gas Pro_2

Crude Oil and Natural Gas Property Information (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022, 2021, and 2020. Year ended December 31, In thousands 2022 2021 2020 Crude oil, natural gas, and natural gas liquids sales $ 10,074,675 $ 5,793,741 $ 2,555,434 Production expenses ( 621,921 ) ( 406,906 ) ( 359,267 ) Production and ad valorem taxes ( 730,132 ) ( 404,362 ) ( 192,718 ) Transportation, gathering, processing, and compression ( 316,414 ) ( 224,989 ) ( 196,692 ) Exploration expenses ( 23,068 ) ( 21,047 ) ( 17,732 ) Depreciation, depletion, amortization and accretion ( 1,856,067 ) ( 1,872,075 ) ( 1,859,893 ) Property impairments ( 70,417 ) ( 38,370 ) ( 277,941 ) Income tax (provision) benefit (1) ( 1,512,132 ) ( 690,902 ) 83,427 Results from crude oil and natural gas producing activities $ 4,944,524 $ 2,135,090 $ ( 265,382 ) (1) Income taxes reflect the application of a combined federal and state tax rate of 23.5% for 2022 and 24.5% for both 2021 and 2020 on pre-tax income/loss generated by our operations.
Schedule of Acquisition 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, 2022, 2021 and 2020 are presented below. See Note 2. Property Acquisitions for discussion of notable property acquisitions that gave rise to changes in acquisition costs incurred between periods. Year ended December 31, In thousands 2022 2021 2020 Property acquisition costs: Proved $ 458,762 $ 2,580,271 $ 60,494 Unproved 412,571 1,197,507 201,919 Total property acquisition costs 871,333 3,777,778 262,413 Exploration Costs 343,117 171,549 48,282 Development Costs 2,185,645 1,174,828 1,053,532 Total $ 3,400,095 $ 5,124,155 $ 1,364,227
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, 2022 and 2021 are as follows: December 31, In thousands 2022 2021 Proved crude oil and natural gas properties $ 34,741,054 $ 31,613,656 Unproved crude oil and natural gas properties 1,513,627 1,358,673 Total 36,254,681 32,972,329 Less accumulated depreciation, depletion and amortization ( 18,134,473 ) ( 16,310,054 ) Net capitalized costs $ 18,120,208 $ 16,662,275
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 2022 2021 2020 Balance at January 1 $ 37,673 $ 32,737 $ 6,257 Additions to capitalized exploratory well costs pending determination of proved reserves 286,059 122,068 32,880 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves ( 229,348 ) ( 117,131 ) ( 72 ) Capitalized exploratory well costs charged to expense ( 9,562 ) ( 1 ) ( 6,328 ) Balance at December 31 $ 84,822 $ 37,673 $ 32,737 Number of gross wells 36 17 16

Supplemental Crude Oil and Na_2

Supplemental Crude Oil and Natural Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2022
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, 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 ( 85,604 ) ( 284,738 ) ( 133,061 ) Extensions, discoveries and other additions 194,848 1,203,850 395,490 Production ( 72,827 ) ( 442,980 ) ( 146,657 ) Sales of minerals in place ( 25 ) ( 712 ) ( 144 ) Purchases of minerals in place 59,617 259,253 102,826 Proved reserves as of December 31, 2022 889,539 5,845,352 1,863,764
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, 2022, 2021, and 2020: December 31, 2022 2021 2020 Proved Developed Reserves Crude oil (MBbl) 454,299 424,153 281,906 Natural Gas (MMcf) 3,486,774 2,901,147 2,073,011 Total (MBoe) 1,035,428 907,678 627,407 Proved Undeveloped Reserves Crude oil (MBbl) 435,240 369,377 215,069 Natural Gas (MMcf) 2,358,578 2,209,532 1,567,713 Total (MBoe) 828,336 737,632 476,355 Total Proved Reserves Crude oil (MBbl) 889,539 793,530 496,975 Natural Gas (MMcf) 5,845,352 5,110,679 3,640,724 Total (MBoe) 1,863,764 1,645,310 1,103,762
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, 2022, 2021, and 2020. 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 2022 2021 2020 Future cash inflows $ 115,338,240 $ 67,034,046 $ 21,334,235 Future production costs ( 26,570,673 ) ( 18,837,000 ) ( 7,750,834 ) Future development and abandonment costs ( 9,651,656 ) ( 7,751,678 ) ( 3,950,752 ) Future income taxes (1) ( 16,158,309 ) ( 7,862,849 ) ( 724,569 ) Future net cash flows 62,957,602 32,582,519 8,908,080 10% annual discount for estimated timing of cash flows ( 31,050,041 ) ( 15,946,126 ) ( 4,254,515 ) Standardized measure of discounted future net cash flows $ 31,907,561 $ 16,636,393 $ 4,653,565 (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, 2022, 2021, and 2020 .
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 2022 2021 2020 Standardized measure of discounted future net cash flows at January 1 $ 16,636,393 $ 4,653,565 $ 10,461,641 Extensions, discoveries and improved recoveries, less related costs 7,331,375 2,985,056 187,981 Revisions of previous quantity estimates ( 3,096,189 ) 816,674 ( 2,952,489 ) Changes in estimated future development and abandonment costs 1,283,405 706,168 4,760,286 Purchases (sales) of minerals in place, net 1,852,313 3,408,365 53,742 Net change in prices and production costs 15,251,976 9,396,945 ( 6,912,031 ) Accretion of discount 2,049,284 489,273 1,183,993 Sales of crude oil and natural gas produced, net of production costs ( 8,406,208 ) ( 4,757,483 ) ( 1,806,758 ) Development costs incurred during the period 1,302,693 683,212 863,101 Change in timing of estimated future production and other 1,899,889 1,871,903 ( 2,325,024 ) Change in income taxes ( 4,197,370 ) ( 3,617,285 ) 1,139,123 Net change 15,271,168 11,982,828 ( 5,808,076 ) Standardized measure of discounted future net cash flows at December 31 $ 31,907,561 $ 16,636,393 $ 4,653,565

Organization and Summary of S_4

Organization and Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) shares in Millions				12 Months Ended
	Nov. 22, 2022	Nov. 21, 2022	Oct. 16, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Oct. 24, 2022
Organization And Summary Of Significant Accounting Policies [Line Items]
Tender offer share price, offer price							$ 74.28
Outstanding shares funded by credit facility borrowings				$ 3,886,000,000	$ 1,663,000,000	$ 2,052,000,000
Number of rollover shares				5.3
Transaction costs					13,900,000
Allowance for credit losses				$ 5,500,000	2,800,000
Unamortized Debt Issuance Expense				46,800,000	50,900,000
Cash deposits in excess of federally insured amounts				136,400,000
Net asset retirement costs				96,500,000	72,800,000
Capitalized debt issue costs, relating to long-term debt				56,300,000	60,600,000
Accumulated amortization, relating to capitalized debt issue costs				46,300,000	36,900,000
Amortization expense related to capitalized debt issuance costs				$ 9,300,000	7,200,000	$ 7,800,000
Concentration Risk, Customer				10
Revolving Credit Facility
Organization And Summary Of Significant Accounting Policies [Line Items]
Unamortized Debt Issuance Expense				$ 9,400,000	$ 9,700,000
Omega Acquisition, Inc. [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Merger agreement date			Oct. 16, 2022
Name of the acquired entity			Omega Acquisition, Inc.
Number of shares validly tendered		36.3
Guaranteed delivery number of shares delivered		3.4
Number of common stock purchased	58.1
Total cash consideration	$ 4,310,000,000
Outstanding shares funded by cash	2,200,000,000
Outstanding shares funded by credit facility borrowings	1,300,000,000
Execution of three-year term loan	$ 750,000,000
Transaction costs				$ 32,000,000
Mr. Hamm
Organization And Summary Of Significant Accounting Policies [Line Items]
Percentage of contribution in capital stock	100%
Hamm Family | Omega Acquisition, Inc. [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Number of shares held in capital stock				299.6
Number of rollover shares				5.3

Organization and Summary of S_5

Organization and Summary of Significant Accounting Policies - Components of Inventories (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Tubular goods and equipment	$ 38,636	$ 12,506
Crude oil	130,192	93,062
Natural gas	4,436	0
Total	$ 173,264	$ 105,568

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, 2022
Minimum | Automobiles and Aircraft
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	5 years
Minimum | Machinery and Equipment
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	6 years
Minimum | Gathering Systems
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	15 years
Minimum | Storage Tanks
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	10 years
Minimum | Office Equipment, Computer Equipment and Software
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	3 years
Minimum | Buildings and Improvements
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	4 years
Maximum | Automobiles and Aircraft
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	10 years
Maximum | Machinery and Equipment
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	30 years
Maximum | Gathering Systems
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	30 years
Maximum | Storage Tanks
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	30 years
Maximum | Office Equipment, Computer Equipment and Software
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	25 years
Maximum | Buildings and Improvements
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at January 1		$ 219,824	$ 179,676	$ 153,673
Accretion expense		12,857	11,125	9,393
Revisions	[1]	(6,672)	(1,291)	10,743
Plus: Additions for new assets		37,413	32,351	7,048
Less: Plugging costs and sold assets		(2,335)	(2,037)	(1,181)
Total asset retirement obligations at December 31		261,087	219,824	179,676
Less: Current portion of asset retirement obligations at December 31	[2]	3,935	4,123	2,482
Non-current portion of asset retirement obligations at December 31		$ 257,152	$ 215,701	$ 177,194
[1] Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties. Balance is included in the caption “Accrued liabilities and other” in the consolidated balance sheets.

Organization and Summary of S_8

Organization and Summary of Significant Accounting Policies - Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income (numerator):
Net income (loss) attributable to Continental Resources		$ 4,024,558	$ 1,660,968	$ (596,869)
Weighted average shares - basic		351,392,000	360,434,000	361,538,000
Non-vested restricted stock and restricted stock units	[1]	0	4,019,000	0
Weighted average shares - diluted		351,392,000	364,453,000	361,538,000
Net income per share:
Basic (in dollars per share)		$ 11.45	$ 4.61	$ (1.65)
Diluted (in dollars per share)		$ 11.45	$ 4.56	$ (1.65)
Weighted Average Number Diluted Shares Outstanding Adjustment		0		934,000
[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. At December 31, 2022, the Company's outstanding Rollover Shares are expected to be paid in cash, not common stock, upon vesting and are classified as liability awards pursuant to ASC Topic 718, Compensation—Stock Compensation. As a result, no potential dilutive effect for the Rollover Shares is presented for the year ended December 31, 2022.

Property Acquisitions - Additio

Property Acquisitions - Additional Information (Details)		1 Months Ended					3 Months Ended	12 Months Ended
	Dec. 31, 2021 USD ($) a Boe	Apr. 30, 2022 USD ($)	Mar. 31, 2022 USD ($) a Boe	Dec. 31, 2021 USD ($) a Boe	Nov. 30, 2021 USD ($) a	Oct. 31, 2020 USD ($) a	Mar. 31, 2021 USD ($) a Boe	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($) a Boe	Dec. 31, 2020 USD ($)
Asset Acquisition [Line Items]
Costs Incurred, Acquisition of Oil and Gas Properties								$ 871,333,000	$ 3,777,778,000	$ 262,413,000
Asset acquisition recognition of proved crude oil and natural gas properties				$ 2,400,000,000
Asset acquisition recognition of unproved crude oil and natural gas properties				700,000,000
Asset acquisition recognition of asset retirement obligation				16,000,000
Asset acquisition recognition of right of use assets				2,000,000
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
Powder River Basin
Asset Acquisition [Line Items]
Costs Incurred, Acquisition of Oil and Gas Properties			$ 403,000,000		$ 246,800,000		$ 206,600,000
Asset acquisition total purchase price			$ 450,000,000
Asset acquisition net leasehold acres acquired | a					72,000		130,000
Oil and Gas, Undeveloped Acreage, Net | a			172,000
Daily production of acquired producing properties | Boe			18,000
Remaining payment made at asset acquisition closing							$ 185,100,000
Asset acquisition net production BOE per day | Boe							7,200
Amount of Asset Retirement Obligations associated with acquired properties			$ 15,300,000
Asset acquisition recognition of proved crude oil and natural gas properties			381,300,000		$ 27,000,000		$ 183,000,000
Asset acquisition recognition of unproved crude oil and natural gas properties			21,700,000		220,000,000		24,000,000
Asset acquisition amount of assumed production and ad valorem tax payment obligations			31,300,000
Amount of right of use assets acquired in property acquisition			$ 10,100,000
Asset acquisition recognition of asset retirement obligation					$ 500,000		4,900,000
Asset acquisition recognition of right of use assets							$ 8,200,000
Escrow deposit per PSA										$ 21,500,000
Permian Basin
Asset Acquisition [Line Items]
Costs Incurred, Acquisition of Oil and Gas Properties		$ 197,000,000
Business combination net leasehold acres acquired | a	92,000			92,000					92,000
Asset acquisition total purchase price		$ 200,000,000
Business combination net royalty acres acquired | a	50,000			50,000					50,000
Business combination net production BOE per day | Boe	42,000			42,000					42,000
Payments to Acquire Businesses, Gross				$ 3,060,000,000
Business combination purchase price prior to closing adjustments				$ 3,250,000,000
SCOOP [Member]
Asset Acquisition [Line Items]
Costs Incurred, Acquisition of Oil and Gas Properties						$ 162,800,000
Asset acquisition net leasehold acres acquired | a						19,500
Asset acquisition recognition of proved crude oil and natural gas properties						$ 15,300,000
Asset acquisition recognition of unproved crude oil and natural gas properties						$ 147,500,000

Property Acquisitions - Busines

Property Acquisitions - Business Acquisition, Pro Forma Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Business Acquisition, Pro Forma Information [Abstract]
Pro forma combined total revenues	$ 6,657	$ 3,174
Pro forma combined net income (loss) attributable to Continental	$ 2,097	$ (481)

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information About Cash Paid For Interest And Income Tax payments And Refunds (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Supplemental Cash Flow Elements [Abstract]
Cash paid for interest		$ 279,571	$ 214,727	$ 256,633
Cash paid for income taxes	[1]	470,147	3	4
Cash received for income tax refunds (1)		16	58	9,600
Non-cash investing activities:
Asset retirement obligation additions and revisions, net		$ 30,741	$ 31,060	$ 17,791
[1] Amount for 2022 represents estimated quarterly payments for 2022 U.S. federal income taxes based on an estimate of federal taxable income for the year.

Supplemental Cash Flow Inform_4

Supplemental Cash Flow Information - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Supplemental Cash Flow Elements [Abstract]
Accrued capital expenditures	$ 344.9	$ 242.9
Accrued contributions from noncontrolling interests	0.5	1.7
Accrued distributions to noncontrolling interests	$ 4.3	$ 2.5

Net Property and Equipment - Sc

Net Property and Equipment - Schedule of Net Property and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment, Net [Abstract]
Proved crude oil and natural gas properties	$ 34,741,054	$ 31,613,656
Unproved crude oil and natural gas properties	1,513,627	1,358,673
Service properties, equipment and other	549,528	484,989
Total property and equipment	36,804,209	33,457,318
Accumulated depreciation, depletion and amortization	(18,332,295)	(16,481,853)
Net property and equipment	$ 18,471,914	$ 16,975,465

Accrued Liabilities and Other -

Accrued Liabilities and Other - Schedule of Accrued Liabilities and Other (Detail) - USD ($) $ in Thousands		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Accrued Liabilities and Other Liabilities [Abstract]
Prepaid advances from joint interest owners		$ 15,575	$ 18,964
Accrued compensation		81,646	82,844
Accrued production taxes, ad valorem taxes and other non-income taxes		145,436	90,597
Accrued interest		83,724	75,983
Current portion of asset retirement obligations	[1]	3,935	4,123	$ 2,482
Other		13,461	13,229
Accrued liabilities and other		$ 343,777	$ 285,740
[1] Balance is included in the caption “Accrued liabilities and other” in the consolidated balance sheets.

Derivative Instruments - Summar

Derivative Instruments - Summary of Outstanding Contracts with Respect to Natural Gas and Crude Oil (Detail)	12 Months Ended
	Dec. 31, 2022 MMBTU $ / MMBTU $ / bbl bbl
Jan 2023 to Dec 2023 NGPL Basis Swaps | Natural Gas [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume | MMBTU	75,000
Swaps Weighted Average Price	(0.17)
Jan 2023 to Mar 2023 Collars | Natural Gas [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume | MMBTU	360,000
Derivative, Average Floor Price	3.91
Derivative, Average Cap Price	5.45
Jan 2023 to Mar 2023 Three-way Collars | Natural Gas [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume | MMBTU	50,000
Derivative, Floor Price	3
Derivative, Average Floor Price	4.32
Derivative, Average Cap Price	5
Jan 2023 to Mar 2023 Swaps | Natural Gas [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume | MMBTU	210,000
Swaps Weighted Average Price	4.26
Jan 2023 to Mar 2023 Swaps WAHA | Natural Gas [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume | MMBTU	55,000
Swaps Weighted Average Price	2.81
Apr 2023 to Sept 2023 Swaps | Natural Gas [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume | MMBTU	405,000
Swaps Weighted Average Price	3.28
Apr 2023 to Sept 2023 Swaps WAHA | Natural Gas [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume | MMBTU	55,000
Swaps Weighted Average Price	2.81
Oct 2023 to Dec 2023 Collar | Natural Gas [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume | MMBTU	200,000
Derivative, Average Floor Price	3.12
Derivative, Average Cap Price	4.09
Oct 2023 to Dec 2023 Swaps | Natural Gas [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume | MMBTU	210,000
Swaps Weighted Average Price	3.51
Oct 2023 to Dec 2023 Swaps WAHA | Natural Gas [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume | MMBTU	55,000
Swaps Weighted Average Price	2.81
Jan24 to Dec24 Collar | Natural Gas [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume | MMBTU	50,000
Derivative, Average Floor Price	3.12
Derivative, Average Cap Price	4.09
Jan24 to Dec 24 Swaps | Natural Gas [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume | MMBTU	325,000
Swaps Weighted Average Price	3.31
Jan 24 to Dec 24 Swaps WAHA | Natural Gas [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume | MMBTU	25,000
Swaps Weighted Average Price	3.43
Jan25 to Dec 25 Swaps | Natural Gas [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume | MMBTU	60,000
Swaps Weighted Average Price	3.75
Jan 26 to Dec 26 Swaps | Natural Gas [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume | MMBTU	50,000
Swaps Weighted Average Price	4.42
Jan 23 to Dec 23 NYMEX Roll Swaps | Crude Oil [Member]
Derivative [Line Items]
Swaps Weighted Average Price | $ / bbl	1.07
Crude oil production volume hedged | bbl	12,000
Jan 23 to Dec 23 WTI Fixed Swaps | Crude Oil [Member]
Derivative [Line Items]
Swaps Weighted Average Price | $ / bbl	83.19
Crude oil production volume hedged | bbl	8,000

Derivative Instruments - Realiz

Derivative Instruments - Realized and Unrealized Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	$ (212,976)	$ 20,814	$ 13,492
Loss on derivative instruments, net	(671,095)	(128,864)	(14,658)
Swap [Member] | Crude Oil [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net		(44,463)	(31,179)
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	11,696
Swap [Member] | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	(353,326)	(84,141)	1,071
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	(219,388)	25,565	2,043
Collars [Member] | Crude Oil [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net		(9,365)
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net		227	(227)
Collars [Member] | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	(66,596)	(11,546)	1,958
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	(34,303)	(7,690)	11,676
NYMEX roll swaps | Crude Oil [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	(9,234)	(163)
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	1,879	957
Basis swaps | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	9,674
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	9,088	(177)
WAHA swaps | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	(16,350)
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	19,386
Three-way collars | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	(22,287)
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	(1,334)	1,932
Crude Oil and Natural Gas
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net	(458,119)	(149,678)	(28,150)
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net	(212,976)	20,814	13,492
Loss on derivative instruments, net	$ (671,095)	$ (128,864)	$ (14,658)

Derivative Instruments - Gross

Derivative Instruments - Gross Amounts of Recognized Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Gross amounts of recognized assets	$ 50,559	$ 42,903
Gross amounts offset on balance sheet	(7,731)	(7,381)
Net amounts of assets on balance sheet	42,828	35,522
Gross amounts of recognized liabilities	(229,230)	(8,598)
Gross amounts offset on balance sheet	7,731	7,381
Net amounts of liabilities on balance sheet	$ (221,499)	$ (1,217)

Derivative Instruments - Reconc

Derivative Instruments - Reconciles Net Amounts Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets	$ 39,280	$ 22,334
Noncurrent derivative assets	3,548	13,188
Net amounts of assets on balance sheet	42,828	35,522
Derivative liabilities	(88,136)	(899)
Derivative liabilities, noncurrent	(133,363)	(318)
Net amounts of liabilities on balance sheet	(221,499)	(1,217)
Total derivative assets (liabilities), net	$ (178,671)	$ 34,305

Fair Value Measurements - Valua

Fair Value Measurements - Valuation of Financial Instruments by Pricing Levels (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Derivative assets (liabilities):
Derivative assets (liabilities)	$ (178,671)	$ 34,305
Crude Oil Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	11,696
Crude oil NYMEX roll swaps
Derivative assets (liabilities):
Derivative assets (liabilities)	2,836	957
Natural Gas Basis Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	8,910	(177)
Natural Gas WAHA Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	19,386
Natural Gas Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	(191,779)	27,608
Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	(30,318)	3,986
Natural Gas Three-way Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	598	1,931
Fair Value, Inputs, Level 1 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 1 [Member] | Crude Oil Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0
Fair Value, Inputs, Level 1 [Member] | Crude oil NYMEX roll swaps
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 1 [Member] | Natural Gas Basis Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0
Fair Value, Inputs, Level 1 [Member] | Natural Gas WAHA Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0
Fair Value, Inputs, Level 1 [Member] | Natural Gas Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 1 [Member] | Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0
Fair Value, Inputs, Level 1 [Member] | Natural Gas Three-way Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0
Fair Value, Inputs, Level 2 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	(178,671)	34,305
Fair Value, Inputs, Level 2 [Member] | Crude Oil Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	11,696
Fair Value, Inputs, Level 2 [Member] | Crude oil NYMEX roll swaps
Derivative assets (liabilities):
Derivative assets (liabilities)	2,836	957
Fair Value, Inputs, Level 2 [Member] | Natural Gas Basis Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	8,910	(177)
Fair Value, Inputs, Level 2 [Member] | Natural Gas WAHA Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	19,386
Fair Value, Inputs, Level 2 [Member] | Natural Gas Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	(191,779)	27,608
Fair Value, Inputs, Level 2 [Member] | Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	(30,318)	3,986
Fair Value, Inputs, Level 2 [Member] | Natural Gas Three-way Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	598	1,931
Fair Value, Inputs, Level 3 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 3 [Member] | Crude Oil Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0
Fair Value, Inputs, Level 3 [Member] | Crude oil NYMEX roll swaps
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 3 [Member] | Natural Gas Basis Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0
Fair Value, Inputs, Level 3 [Member] | Natural Gas WAHA Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0
Fair Value, Inputs, Level 3 [Member] | Natural Gas Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	$ 0
Fair Value, Inputs, Level 3 [Member] | Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0
Fair Value, Inputs, Level 3 [Member] | Natural Gas Three-way Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	$ 0

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Fair Value Measurements [Line Items]
Discount factor utilized as standardized measure for future net cash flows	10%
Forward commodity price assumption for proved crude oil and natural gas property impairment	3%
Forward operating price assumption for proved crude oil and natural gas impairment	3%
Proved property impairments	$ 17,520	$ 0	$ 207,119
Estimated fair value of proved properties	$ 2,100		145,700
Inventory Valuation and Obsolescence [Member]
Fair Value Measurements [Line Items]
Inventory Write-down			24,500
Non-core [Member]
Fair Value Measurements [Line Items]
Proved property impairments			14,500
Red River Units [Member]
Fair Value Measurements [Line Items]
Proved property impairments			$ 168,100

Fair Value Measurements - Prope

Fair Value Measurements - Property Impairments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments	$ 17,520	$ 0	$ 207,119
Unproved property impairments	52,897	38,370	70,822
Total	$ 70,417	$ 38,370	$ 277,941

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Term Loan
Fair Value Measurements [Line Items]
Debt instrument, stated interest rate		6.10%
4.5% Senior Notes due 2023
Fair Value Measurements [Line Items]
Debt Instrument, Maturity Date, Description		2023
Debt instrument, stated interest rate		4.50%
3.8% Senior Notes due 2024
Fair Value Measurements [Line Items]
Debt Instrument, Maturity Date, Description		2024
Debt instrument, stated interest rate		3.80%
2.268% Senior Notes due 2026
Fair Value Measurements [Line Items]
Debt Instrument, Maturity Date, Description		2026
Debt instrument, stated interest rate		2.268%
Senior notes			$ 800,000
4.375% Senior Notes due 2028
Fair Value Measurements [Line Items]
Debt Instrument, Maturity Date, Description		2028
Debt instrument, stated interest rate		4.375%
5.75% Senior Notes due 2031
Fair Value Measurements [Line Items]
Debt Instrument, Maturity Date, Description		2031
Debt instrument, stated interest rate		5.75%
Senior notes				$ 1,500,000
2.875% Senior Notes due 2032
Fair Value Measurements [Line Items]
Debt Instrument, Maturity Date, Description		2032
Debt instrument, stated interest rate		2.875%
Senior notes			800,000
4.9% Senior Notes due 2044
Fair Value Measurements [Line Items]
Debt Instrument, Maturity Date, Description		2044
Debt instrument, stated interest rate		4.90%
Carrying Amount
Fair Value Measurements [Line Items]
Credit facility		$ 1,160,000	500,000
Notes payable		20,041	22,356
Total debt		8,209,640	6,828,892
Carrying Amount | Term Loan
Fair Value Measurements [Line Items]
Term Loan		747,073	0
Carrying Amount | 4.5% Senior Notes due 2023
Fair Value Measurements [Line Items]
Senior notes	[1]	635,648	648,078
Carrying Amount | 3.8% Senior Notes due 2024
Fair Value Measurements [Line Items]
Senior notes		891,404	908,061
Carrying Amount | 2.268% Senior Notes due 2026
Fair Value Measurements [Line Items]
Senior notes		794,062	792,621
Carrying Amount | 4.375% Senior Notes due 2028
Fair Value Measurements [Line Items]
Senior notes		993,076	991,880
Carrying Amount | 5.75% Senior Notes due 2031
Fair Value Measurements [Line Items]
Senior notes		1,483,843	1,482,319
Carrying Amount | 2.875% Senior Notes due 2032
Fair Value Measurements [Line Items]
Senior notes		792,238	791,521
Carrying Amount | 4.9% Senior Notes due 2044
Fair Value Measurements [Line Items]
Senior notes		692,255	692,056
Estimated Fair Value
Fair Value Measurements [Line Items]
Credit facility		1,160,000	500,000
Notes payable		18,300	22,000
Total debt		7,577,773	7,351,100
Estimated Fair Value | Term Loan
Fair Value Measurements [Line Items]
Term Loan		747,073	0
Estimated Fair Value | 4.5% Senior Notes due 2023
Fair Value Measurements [Line Items]
Senior notes		633,600	670,200
Estimated Fair Value | 3.8% Senior Notes due 2024
Fair Value Measurements [Line Items]
Senior notes		867,400	950,000
Estimated Fair Value | 2.268% Senior Notes due 2026
Fair Value Measurements [Line Items]
Senior notes		693,100	795,200
Estimated Fair Value | 4.375% Senior Notes due 2028
Fair Value Measurements [Line Items]
Senior notes		917,200	1,082,100
Estimated Fair Value | 5.75% Senior Notes due 2031
Fair Value Measurements [Line Items]
Senior notes		1,412,300	1,769,600
Estimated Fair Value | 2.875% Senior Notes due 2032
Fair Value Measurements [Line Items]
Senior notes		600,900	780,500
Estimated Fair Value | 4.9% Senior Notes due 2044
Fair Value Measurements [Line Items]
Senior notes		$ 527,900	$ 781,500
[1] The Company's 2023 Notes, which have a face value of $ 636.0 million at December 31, 2022, are scheduled to mature on April 15, 2023 and, accordingly, are included as a current liability in the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, 2022 along with the current portion of the Company's notes payable.

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands			3 Months Ended		6 Months Ended	12 Months Ended
		Aug. 24, 2022	Jun. 30, 2022	Dec. 31, 2020	Jun. 30, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Aug. 04, 2022	Apr. 30, 2021	Jan. 31, 2021	Nov. 25, 2020	Jun. 30, 2020	Mar. 31, 2020
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net						$ 49,600	$ 54,200
Proceeds from sale of assets						5,740	8,041	$ 2,779
(Gain) loss on extinguishment of debt					$ (300)	$ 403	290	(35,719)
Increase in aggregate amount of lender commitments on credit facility		$ 255,000
Aggregate amount of lender commitments on credit facility							2,000,000		$ 2,255,000
Line of credit facility, commitment fee percentage, per annum						0.20%
Line of Credit Facility, Covenant Terms						0.65
Proceeds from issuance of Senior Notes						$ 0	1,587,776	1,485,000
Repayments of Lines of Credit						3,226,000	1,323,000	1,947,000
Current portion of long-term debt						638,058	2,326
Senior Notes due 2022
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount										$ 230,800	$ 400,000	$ 469,200		$ 89,000
Debt Instrument, Face Amount						$ 636,000
(Gain) loss on extinguishment of debt			$ (400)	$ (64,600)				$ (28,900)
Debt instrument, maturity date						Apr. 15, 2023
Debt Instrument, Repurchase Amount														46,900
Note Payable
Debt Instrument [Line Items]
Notes Payable													$ 26,000
Debt instrument, stated interest rate						3.50%
Current portion of long-term debt						$ 2,400
Debt Instrument, Term								10 years
Term Loan
Debt Instrument [Line Items]
Term loan						$ 750,000
Debt instrument, stated interest rate						6.10%
5% Senior Notes due 2022
Debt Instrument [Line Items]
TotalRedemptionAmount												475,000
Senior Notes Due 2023
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount			13,600									800,000		50,400
Debt Instrument, Face Amount						$ 636,000
Debt Instrument, Repurchase Amount			13,900									$ 828,000		$ 29,300
4.5% Senior Notes due 2023
Debt Instrument [Line Items]
Debt instrument, stated interest rate						4.50%
3.8% Senior Notes due 2024
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount			17,900
Debt instrument, stated interest rate						3.80%
Debt Instrument, Repurchase Amount			$ 18,300
4.9% Senior Notes due 2044
Debt Instrument [Line Items]
Debt instrument, stated interest rate						4.90%
Senior Notes due 2031
Debt Instrument [Line Items]
Debt Instrument, Face Amount						$ 1,500,000
Debt instrument, maturity date						Jan. 15, 2031
2.268% Senior Notes due 2026
Debt Instrument [Line Items]
Senior notes							800,000
Debt instrument, stated interest rate						2.268%
2.875% Senior Notes due 2032
Debt Instrument [Line Items]
Senior notes							800,000
Debt instrument, stated interest rate						2.875%
5.75% Senior Notes due 2031
Debt Instrument [Line Items]
Senior notes				$ 1,500,000				$ 1,500,000
Debt instrument, stated interest rate						5.75%
Senior Notes
Debt Instrument [Line Items]
Proceeds from issuance of Senior Notes							1,590,000	$ 1,490,000
Revolving Credit Facility
Debt Instrument [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity						$ 1,090,000
Carrying Amount
Debt Instrument [Line Items]
Term loan						747,073	0
Line of credit facility, amount outstanding						$ 1,160,000	500,000
Debt, Weighted Average Interest Rate						5.90%
Notes Payable						$ 20,041	22,356
Carrying Amount | Hamm Family
Debt Instrument [Line Items]
Line of credit facility, amount outstanding						1,160,000
Carrying Amount | 4.5% Senior Notes due 2023
Debt Instrument [Line Items]
Senior notes	[1]					635,648	648,078
Carrying Amount | 3.8% Senior Notes due 2024
Debt Instrument [Line Items]
Senior notes						891,404	908,061
Carrying Amount | 4.9% Senior Notes due 2044
Debt Instrument [Line Items]
Senior notes						692,255	692,056
Carrying Amount | Senior Notes due 2031
Debt Instrument [Line Items]
Senior notes						1,483,843	1,482,319
Carrying Amount | 2.268% Senior Notes due 2026
Debt Instrument [Line Items]
Senior notes						794,062	792,621
Carrying Amount | 2.875% Senior Notes due 2032
Debt Instrument [Line Items]
Senior notes						792,238	791,521
Carrying Amount | 5.75% Senior Notes due 2031
Debt Instrument [Line Items]
Senior notes						$ 1,483,843	$ 1,482,319
[1] The Company's 2023 Notes, which have a face value of $ 636.0 million at December 31, 2022, are scheduled to mature on April 15, 2023 and, accordingly, are included as a current liability in the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, 2022 along with the current portion of the Company's notes payable.

Long-Term Debt - Long-Term Debt

Long-Term Debt - Long-Term Debt (Detail) - USD ($) $ in Thousands		6 Months Ended	12 Months Ended
		Jun. 30, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net			$ 49,600	$ 54,200
Less: Current portion of long-term debt			638,058	2,326
Long-term debt, net of current portion			7,571,582	6,826,566
Gain (loss) on extinguishment of debt		$ 300	$ (403)	(290)	$ 35,719
4.5% Senior Notes due 2023
Debt Instrument [Line Items]
Debt instrument, stated interest rate			4.50%
3.8% Senior Notes due 2024
Debt Instrument [Line Items]
Debt instrument, stated interest rate			3.80%
4.375% Senior Notes due 2028
Debt Instrument [Line Items]
Debt instrument, stated interest rate			4.375%
5.75% Senior Notes due 2031
Debt Instrument [Line Items]
Senior notes					$ 1,500,000
Debt instrument, stated interest rate			5.75%
4.9% Senior Notes due 2044
Debt Instrument [Line Items]
Debt instrument, stated interest rate			4.90%
2.268% Senior Notes due 2026
Debt Instrument [Line Items]
Senior notes				800,000
Debt instrument, stated interest rate			2.268%
2.875% Senior Notes due 2032
Debt Instrument [Line Items]
Senior notes				800,000
Debt instrument, stated interest rate			2.875%
Carrying Amount
Debt Instrument [Line Items]
Credit facility			$ 1,160,000	500,000
Term loan			747,073	0
Notes payable			20,041	22,356
Total debt			8,209,640	6,828,892
Carrying Amount | 4.5% Senior Notes due 2023
Debt Instrument [Line Items]
Senior notes	[1]		635,648	648,078
Carrying Amount | 3.8% Senior Notes due 2024
Debt Instrument [Line Items]
Senior notes			891,404	908,061
Carrying Amount | 4.375% Senior Notes due 2028
Debt Instrument [Line Items]
Senior notes			993,076	991,880
Carrying Amount | 5.75% Senior Notes due 2031
Debt Instrument [Line Items]
Senior notes			1,483,843	1,482,319
Carrying Amount | 4.9% Senior Notes due 2044
Debt Instrument [Line Items]
Senior notes			692,255	692,056
Carrying Amount | Senior Notes due 2031
Debt Instrument [Line Items]
Senior notes			1,483,843	1,482,319
Carrying Amount | 2.268% Senior Notes due 2026
Debt Instrument [Line Items]
Senior notes			794,062	792,621
Carrying Amount | 2.875% Senior Notes due 2032
Debt Instrument [Line Items]
Senior notes			$ 792,238	$ 791,521
[1] The Company's 2023 Notes, which have a face value of $ 636.0 million at December 31, 2022, are scheduled to mature on April 15, 2023 and, accordingly, are included as a current liability in the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, 2022 along with the current portion of the Company's notes payable.

Long-Term Debt - Long-Term De_2

Long-Term Debt - Long-Term Debt (Parenthetical) (Details) $ in Millions	Dec. 31, 2022 USD ($)
Senior Notes Due 2023
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 636

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, 2022 USD ($)
Senior Notes due 2022
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 636,000
Maturity date	Apr. 15, 2023
Interest Payment Dates	April 15, Oct 15
Senior Notes Due 2023
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 636,000
Debt Instrument, Redemption Period, Start Date	Jan. 15, 2023	[1]
Senior Notes Due 2024
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 893,126
Maturity date	Jun. 01, 2024
Interest Payment Dates	June 1, Dec 1
Debt Instrument, Redemption Period, Start Date	Mar. 01, 2024	[1]
Senior Notes Due 2026
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	[1]
Senior Notes Due 2028
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	[1]
Senior Notes Due 2032
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 800,000
Maturity date	Apr. 01, 2032
Interest Payment Dates	April 1, Oct 1
Debt Instrument, Redemption Period, Start Date	Jan. 01, 2032	[1]
Senior Notes due 2044
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 700,000
Maturity date	Jun. 01, 2044
Interest Payment Dates	June 1, Dec 1
Debt Instrument, Redemption Period, Start Date	Dec. 01, 2043	[1]
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	[1]
[1] At any time prior to the indicated dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series at the “make-whole” redemption amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after the indicated dates, the Company may redeem all or a portion of its senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption.

Revenues (Details)

Revenues (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Transportation expenses	$ 316,414	$ 224,989	$ 196,692
Natural Gas Sales
Disaggregation of Revenue [Line Items]
Transportation expenses	62,400	39,900	37,700
Crude Oil Sales
Disaggregation of Revenue [Line Items]
Transportation expenses	$ 254,000	$ 185,100	$ 159,000

Revenues - Disaggregation of Re

Revenues - Disaggregation of Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	$ 10,074,675	$ 5,793,741	$ 2,555,434
Bakken
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	4,951,619	3,349,015	1,552,206
Anadarko Basin
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	2,948,878	2,138,821	899,279
Powder River Basin
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	683,008	114,815	0
Permian Basin
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	1,273,507	29,356	0
All Other
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	217,663	161,734	103,949
Crude Oil Sales
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	6,906,003	3,949,294	2,199,976
Crude Oil Sales | Bakken
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	3,899,749	2,786,320	1,523,348
Crude Oil Sales | Anadarko Basin
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	1,109,405	874,752	572,653
Crude Oil Sales | Powder River Basin
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	557,943	101,705	0
Crude Oil Sales | Permian Basin
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	1,122,290	24,857	0
Crude Oil Sales | All Other
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	216,616	161,660	103,975
Natural gas sales
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	3,168,672	1,844,447	355,458
Natural gas sales | Bakken
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	1,051,870	562,695	28,858
Natural gas sales | Anadarko Basin
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	1,839,473	1,264,069	326,626
Natural gas sales | Powder River Basin
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	125,065	13,110	0
Natural gas sales | Permian Basin
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	151,217	4,499	0
Natural gas sales | All Other
Disaggregation of Revenue [Line Items]
Crude oil, natural gas, and natural gas liquids sales	$ 1,047	$ 74	$ (26)

Allowance for Credit Losses (De

Allowance for Credit Losses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Financing Receivable, Allowance for Credit Loss [Line Items]
Allowance for credit losses	$ 5.5	$ 2.8
Accounts Receivable, Credit Loss Expense (Reversal)	3.3	0.8	$ 1.8
Allowance for credit losses on joint interest receivables [Member]
Financing Receivable, Allowance for Credit Loss [Line Items]
Allowance for credit losses	$ 5.5	$ 2.8

Income Taxes - Provision for In

Income Taxes - Provision for Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Current federal income tax (provision) benefit	$ 538,704	$ 0	$ (2,248)
Current tax (provision), various states	83,671	0	29
Total current income tax provision (benefit)	622,375	0	(2,219)
Deferred federal income tax (provision) benefit	374,802	467,051	(148,828)
Deferred tax (provision) benefit, various states	23,627	52,679	(18,143)
Total deferred income tax provision (benefit)	398,429	519,730	(166,971)
Provision (benefit) for income taxes	$ 1,020,804	$ 519,730	$ (169,190)
Effective tax rate	20.10%	23.80%	21.80%

Income Taxes - Schedule of Prov

Income Taxes - Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income (loss) before income taxes		$ 5,068,413	$ 2,186,138	$ (774,751)
Expected income tax provision (benefit) based on U.S. federal statutory tax rate		1,064,367	459,089	(162,698)
State and local income taxes, net of federal benefit		126,932	77,979	(24,808)
Tax benefit (deficiency) from stock-based compensation		(5,282)	5,869	4,927
Federal tax credit for increasing research activities	[1]	(151,913)	0	0
Other, net		(13,300)	(8,733)	(1,085)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount		0	(14,474)	14,474
Provision (benefit) for income taxes		$ 1,020,804	$ 519,730	$ (169,190)
Federal statutory income tax rate		21%	21%	21%
Effective tax rate		20.10%	23.80%	21.80%
[1] In 2022, the Company commenced a study to determine the amount of its qualified research activities performed during the tax years of 2018 to 2022 that qualify for a research and development income tax credit under the Internal Revenue Code. A $ 152 million decrease in the Company’s income tax provision was recognized in 2022 to account for eligible tax credits identified as a result of the study.

Income Taxes - Schedule of Pr_2

Income Taxes - Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate (Parenthetical) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Income Tax Disclosure [Abstract]
Tax years	2018 2019 2020 2021 2022
Decrease in the income tax provision	$ 152

Income Taxes - Components of De

Income Taxes - Components of Deferred Tax Assets and Liabilities (Detail) - USD ($)	Dec. 31, 2022	Dec. 31, 2021	Sep. 30, 2020
Income Tax Disclosure [Abstract]
Deferred tax assets, Net operating loss carryforwards	$ 63,128,000	$ 365,602,000
Incentive/equity compensation	34,987,000	12,751,000
Net deferred hedge losses	42,898,000	0
Deferred Tax Assets, Other	31,324,000	29,421,000
Total deferred tax assets	172,337,000	407,774,000
Deferred Tax Assets, Valuation Allowance	0	0	$ 14,500,000
Total deferred tax assets, net of valuation allowance	172,337,000	407,774,000
Deferred tax liabilities, Property and equipment	(2,708,641,000)	(2,536,938,000)
Deferred Tax Liabilities, Other	(2,008,000)	(10,720,000)
Total deferred tax liabilities	2,710,649,000	2,547,658,000
Deferred income tax liabilities, net	$ 2,538,312,000	$ 2,139,884,000

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2022 USD ($)
UNITED STATES
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$ 0
Tax credit carry forward	0
OKLAHOMA
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	1,990,000,000
Operating loss carryforward with indefinite life	1,110,000,000
Operating loss carryforward subject to expiration	881,000,000
NORTH DAKOTA
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	0
Tax credit carry forward	$ 0

Income Taxes Income Taxes - (De

Income Taxes Income Taxes - (Details) - USD ($)	Dec. 31, 2022	Dec. 31, 2021	Sep. 30, 2020
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Valuation Allowance	$ 0	$ 0	$ 14,500,000

Leases Description of leases (D

Leases Description of leases (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Lessee, Lease, Description [Line Items]
Operating Lease, Liability	$ 24,141	$ 15,474
Surface use agreements [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Liability	18,136	12,354
Field equipment [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Liability	5,224	2,095
Other [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Liability	$ 781	$ 1,025

Leases additional information (

Leases additional information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Operating Lease, Liability	$ 24,141	$ 15,474
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	19,944	10,481	$ 7,377
Short-term Lease, Cost	124,535	77,551	107,984
Lease, Cost	128,669	87,475	119,384
Operating Lease, Cost	3,484	6,653	6,444
Variable Lease, Cost	650	3,271	4,956
Operating cash flows from operating leases	$ 4,370	$ 1,731	$ 890
Operating Lease, Weighted Average Remaining Lease Term	12 years	14 years 4 months 24 days	13 years 2 months 12 days
Weighted average discount rate	4.80%	5%	4.80%

Leases, maturities of operating

Leases, maturities of operating leases (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	$ 5,180
Lessee, Operating Lease, Liability, Payments, Due Year Two	4,172
Lessee, Operating Lease, Liability, Payments, Due Year Three	1,885
Lessee, Operating Lease, Liability, Payments, Due Year Four	1,848
Lessee, Operating Lease, Liability, Payments, Due Year Five	1,827
Lessee, Operating Lease, Liability, Payments, Due after Year Five	18,351
Lessee, Operating Lease, Liability, to be Paid, Total	33,263
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(9,122)
Operating Lease, Liability, Total	24,141	$ 15,474
Current portion of operating lease liabilities	(4,086)	(1,674)
Operating lease liabilities, net of current portion	$ 20,055	$ 13,800

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Long-term Purchase Commitment [Line Items]
Purchase Obligation Agreement Expiration Date	2031
Purchase Obligation	$ 1,140
Purchase Obligation, Due in Next Twelve Months	328
Purchase Obligation, Due in Second Year	291
Purchase Obligation, Due in Third Year	164
Purchase Obligation, Due in Fourth Year	139
Purchase Obligation, Due in Fifth Year	136
Purchase Obligation, Due after Fifth Year	$ 78

Commitments and Contingencies L

Commitments and Contingencies Loss Contingencies (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Loss Contingencies [Line Items]
Legal proceedings recorded as a liability under other noncurrent liabilities	$ 20.2	$ 7.9

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Related Party Transaction [Line Items]
Amount charged to affiliate for aircraft use	$ 16,400	$ 11,300	$ 8,100
Amount charged to company by affiliate for aircraft use	235,000	117,000	120,000
Officers And Other Key Employees [Member]
Related Party Transaction [Line Items]
Revenues from transactions with related party	200,000	100,000	300,000
Due to affiliates	36,000	37,000
Revenues paid to related party	500,000	400,000	200,000
Due from affiliates	6,000	39,000
Other Affiliates [Member]
Related Party Transaction [Line Items]
Total amount paid to related party	219,000	84,000	158,000
Due to affiliates	49,000	33,000
Due from affiliates	9,800	6,300
Total amount received from related party	$ 13,000	$ 5,000	$ 9,500

Stock Based Compensation - Asso

Stock Based Compensation - Associated Compensation Expense (Detail) - USD ($) $ in Millions		12 Months Ended
	Nov. 22, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-based Payment Arrangement [Abstract]
Non-cash compensation expense	$ 136	$ 217.8	$ 63.2	$ 64.6

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Detail) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of rollover shares	5.3
Current Portion of Incentive Compensation Liability [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Liability related to rollover shares	$ 125.7
Incentive Compensation Liability, Net of Current Portion [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Liability related to rollover shares	100.1
Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value at vesting date	$ 98.4	$ 46.7	$ 27.5

Stock Based Compensation - Summ

Stock Based Compensation - Summary of Changes in Non Vested Shares of Restricted Stock (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
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	5,894,508	4,890,638	3,461,908
Granted shares	1,575,847	3,050,491	2,738,625
Vested shares	(1,736,678)	(1,750,483)	(1,146,618)
Forfeited shares	(384,536)	(296,138)	(163,277)
Cancelled shares due to take-private transaction	(5,349,141)
Non-vested shares, ending balance	0	5,894,508	4,890,638
Non-vested, weighted average grant-date fair value, beginning of period	$ 28.38	$ 36.26	$ 46.82
Granted, weighted average grant-date fair value	56.52	24.73	26.93
Vested, weighted average grant-date fair value	36.04	44.36	45.78
Forfeited, weighted average grant-date fair value	27.82	26.61	36.69
Cancelled shares due to take-private transaction, weighted average grant-date fair value	34.22
Non-vested, weighted average grant-date fair value, end of period	$ 0	$ 28.38	$ 36.26

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, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2022
Share Repurchase Program [Abstract]
Stock Repurchased and Retired During Period, Shares	1,842,422	3,198,571	8,122,104	13,163,097
Treasury Stock, Retired, Cost Method, Amount	$ 99,855	$ 123,924	$ 126,906	$ 350,685

Shareholders' Equity Attribut_4

Shareholders' Equity Attributable to Continental Resources - (Additional Information) (Details) - Omega Acquisition, Inc. [Member] - USD ($) shares in Millions, $ in Millions		12 Months Ended
	Nov. 22, 2022	Dec. 31, 2022
Class of Stock [Line Items]
Merger Sub acquisition cost	$ 4,310
Hamm Family
Class of Stock [Line Items]
Number of shares held in capital stock		299.6

Shareholders' Equity Attribut_5

Shareholders' Equity Attributable to Continental Resources - Summary of Dividend Payments (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended							12 Months Ended
	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Dividend [Abstract]
Payments of Dividends	$ 100,131	$ 100,123	$ 82,529	$ 71,793	$ 54,141	$ 39,735	$ 18,367	$ 282,783	$ 165,669	$ 18,367
Common Stock, Dividends, Per Share, Declared	$ 0.28	$ 0.28	$ 0.23	$ 0.20	$ 0.15	$ 0.11	$ 0.05

Noncontrolling Interests - Addi

Noncontrolling Interests - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2019	Dec. 31, 2022	Dec. 31, 2021
TMRC II [Member]
Noncontrolling Interest [Line Items]
Proceeds from formation of new mineral relationship	$ 214.8
Other Noncontrolling Interests		$ 361.4	$ 369.8
SFPG, LLC [Member]
Noncontrolling Interest [Line Items]
Other Noncontrolling Interests		$ 11	$ 11.1
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%

Equity Investment (Additional I

Equity Investment (Additional Information) (Details) $ in Millions	Dec. 31, 2022 USD ($)
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Aggregate Cost	$ 210
Total commitment to invest with equity method affiliate	$ 250
Investment in equity affiliate - Summit Carbon Solutions
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	22%

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Crude oil, natural gas, and natural gas liquids sales		$ 10,074,675	$ 5,793,741	$ 2,555,434
Production expenses		(621,921)	(406,906)	(359,267)
Production and ad valorem taxes		(730,132)	(404,362)	(192,718)
Transportation, gathering, processing, and compression		(316,414)	(224,989)	(196,692)
Exploration Expense		(23,068)	(21,047)	(17,732)
Depreciation, depletion, amortization and accretion		(1,856,067)	(1,872,075)	(1,859,893)
Property impairments		(70,417)	(38,370)	(277,941)
Income tax (provision) benefit (1)	[1]	(1,512,132)	(690,902)	83,427
Results from crude oil and natural gas producing activities		$ 4,944,524	$ 2,135,090	$ (265,382)
[1] Income taxes reflect the application of a combined federal and state tax rate of 23.5% for 2022 and 24.5% for both 2021 and 2020 on pre-tax income/loss generated by our operations.

Crude Oil and Natural Gas Pro_4

Crude Oil and Natural Gas Property Information - Schedule of Acquisition Costs Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Property Acquisition Costs - Proved	$ 458,762	$ 2,580,271	$ 60,494
Property Acquisition Costs - Unproved	412,571	1,197,507	201,919
Total property acquisition costs	871,333	3,777,778	262,413
Exploration Costs	343,117	171,549	48,282
Development Costs	2,185,645	1,174,828	1,053,532
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities	$ 3,400,095	$ 5,124,155	$ 1,364,227

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Development costs included in asset retirement costs	$ 30.8	$ 31.1	$ 18.1

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, 2022	Dec. 31, 2021
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved crude oil and natural gas properties	$ 34,741,054	$ 31,613,656
Unproved crude oil and natural gas properties	1,513,627	1,358,673
Total	36,254,681	32,972,329
Less accumulated depreciation, depletion and amortization	(18,134,473)	(16,310,054)
Net capitalized costs	$ 18,120,208	$ 16,662,275

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, 2022 USD ($) Well	Dec. 31, 2021 USD ($) Well	Dec. 31, 2020 USD ($) Well
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Balance at January 1	$ 37,673	$ 32,737	$ 6,257
Additions to capitalized exploratory well costs pending determination of proved reserves	286,059	122,068	32,880
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves	(229,348)	(117,131)	(72)
Capitalized exploratory well costs charged to expense	(9,562)	(1)	(6,328)
Balance at December 31	$ 84,822	$ 37,673	$ 32,737
Number of wells | Well	36	17	16

Supplemental Crude Oil and Na_3

Supplemental Crude Oil and Natural Gas Information - Additional Information (Detail) MBbls in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2022 MBoe	Dec. 31, 2022 MMBbls	Dec. 31, 2022 Bcf	Dec. 31, 2022 MMBoe	Dec. 31, 2022 $ / bbl	Dec. 31, 2022 $ / Mcf	Dec. 31, 2021 MBoe MMBoe $ / bbl $ / Mcf MMBbls Bcf	Dec. 31, 2020	Dec. 31, 2020 MBbls	Dec. 31, 2020 MBoe	Dec. 31, 2020 MMBbls	Dec. 31, 2020 Bcf	Dec. 31, 2020 MMBoe	Dec. 31, 2020 $ / bbl	Dec. 31, 2020 $ / Mcf
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy) | MBoe		133,061						(53,569)			504,874
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) | MBoe		(395,490)						(371,105)			(91,387)
Discount factor utilized as standardized measure for future net cash flows	10%
Purchases of minerals in place, Total | MBoe		102,826						237,343			7,817
Percent of proved crude oil reserve estimates prepared by external reserve engineers	98%							98%	95%
Natural Gas [Member]
Reserve Quantities [Line Items]
Weighted average price utilized in computation of future cash inflows | $ / Mcf							6.12	3.46								1.17
Crude Oil [Member]
Reserve Quantities [Line Items]
Weighted average price utilized in computation of future cash inflows | $ / bbl						89.47		62.19							34.34
Bakken [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)					(109)
Extensions, discoveries and other additions			69	241
Anadarko Basin [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)					(154)
Extensions, discoveries and other additions			29	751
Permian Basin
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)					(114)
Extensions, discoveries and other additions			84	178
Powder River Basin
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)					(18)
Extensions, discoveries and other additions			13	32
Change in development plans | Proved Undeveloped Reserves [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)					(72)			(57)			(107,000)
Change in development plans | Proved Undeveloped Reserves [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates				225				155		50			345,000
Change in development plans | Proved Undeveloped Reserves [Member] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMBbls			35					31
Price Driven | Proved Reserves [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)					(46)			(168)						(388)
Price Driven | Proved Reserves [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | Bcf				105				458					1,043
Price Driven | Proved Reserves [Member] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMBbls			29					92				214
Economics Performance and Other [Member] | Proved Reserves [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | Bcf				401				263					172
Economics Performance and Other [Member] | Proved Reserves [Member] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMBbls			(71)					12				29
Energy | Proved Reserves [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)					(137)			(56)						(58)
Other [Member] | Proved Reserves [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		(31,000)						(2)						(48)
Other [Member] | Proved Reserves [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | Bcf				236				195					31
Other [Member] | Proved Reserves [Member] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMBbls			9					35				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, 2022 MBoe MBbls MMcf	Dec. 31, 2021 MBoe MBbls MMcf	Dec. 31, 2020 MBoe MMcf MBbls	Dec. 31, 2019 MBoe
Changes in Proved Reserves [Roll Forward]
Proved Developed and Undeveloped Reserve, Net (Energy) | MBoe	1,863,764	1,645,310	1,103,762	1,619,265
Revisions of previous estimates | MBoe	(133,061)	53,569	(504,874)
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease) | MBoe	395,490	371,105	91,387
Proved Developed and Undeveloped Reserve, Production (Energy) | MBoe	146,657	120,321	109,833
Proved Developed and Undeveloped Reserves, Sale of Mineral in Place (Energy) | MBoe	144	148	0
Purchases of minerals in place, Total | MBoe	102,826	237,343	7,817
Percent of proved crude oil reserve estimates prepared by external reserve engineers	98%	98%	95%
Natural Gas [Member]
Changes in Proved Reserves [Roll Forward]
Proved reserves at beginning of period | MMcf	5,110,679	3,640,724	5,154,471
Revisions of previous estimates | MMcf	(284,738)	233,966	(1,530,174)
Extensions, discoveries and other additions | MMcf	1,203,850	1,235,022	295,686
Proved Developed and Undeveloped Reserves, Production | MMcf	(442,980)	(370,110)	(306,528)
Sales of minerals in place | MMcf	(712)	(469)	0
Purchases of minerals in place | MMcf	259,253	371,546	27,269
Proved reserves at end of period | MMcf	5,845,352	5,110,679	3,640,724
Crude Oil [Member]
Changes in Proved Reserves [Roll Forward]
Proved reserves at beginning of period | MBbls	793,530	496,975	760,187
Revisions of previous estimates | MBbls	(85,604)	14,574	(249,845)
Extensions, discoveries and other additions | MBbls	194,848	165,268	42,106
Proved Developed and Undeveloped Reserves, Production | MBbls	(72,827)	(58,636)	(58,745)
Sales of minerals in place | MBbls	(25)	(70)	0
Purchases of minerals in place | MBbls	59,617	175,419	3,272
Proved reserves at end of period | MBbls	889,539	793,530	496,975

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, 2022 MBoe MMcf MBbls	Dec. 31, 2021 MBoe MMcf MBbls	Dec. 31, 2020 MBoe MMcf MBbls	Dec. 31, 2019 MBoe MMcf MBbls
Reserve Quantities [Line Items]
Proved Developed Reserves (MBOE) | MBoe	1,035,428	907,678	627,407
Proved Undeveloped Reserve (MBOE) | MBoe	828,336	737,632	476,355
Proved Developed and Undeveloped Reserve, Net (MBOE) | MBoe	1,863,764	1,645,310	1,103,762	1,619,265
Crude Oil [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume) | MBbls	454,299	424,153	281,906
Proved Undeveloped Reserve (Volume) | MBbls	435,240	369,377	215,069
Proved Developed and Undeveloped Reserves, Net | MBbls	889,539	793,530	496,975	760,187
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume) | MMcf	3,486,774	2,901,147	2,073,011
Proved Undeveloped Reserve (Volume) | MMcf	2,358,578	2,209,532	1,567,713
Proved Developed and Undeveloped Reserves, Net | MMcf	5,845,352	5,110,679	3,640,724	5,154,471

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, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Supplemental Crude Oil and Natural Gas Information [Abstract]
Discount factor utilized as standardized measure for future net cash flows	10%
Future cash inflows	$ 115,338,240	$ 67,034,046	$ 21,334,235
Future production costs	(26,570,673)	(18,837,000)	(7,750,834)
Future development and abandonment costs	(9,651,656)	(7,751,678)	(3,950,752)
Future income taxes	(16,158,309)	(7,862,849)	(724,569)
Future net cash flows	62,957,602	32,582,519	8,908,080
10% annual discount for estimated timing of cash flows	(31,050,041)	(15,946,126)	(4,254,515)
Standardized measure of discounted future net cash flows	$ 31,907,561	$ 16,636,393	$ 4,653,565	$ 10,461,641

Supplemental Crude Oil and Na_7

Supplemental Crude Oil and Natural Gas Information - Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Supplemental Crude Oil and Natural Gas Information [Abstract]
Federal statutory income tax rate	21%	21%	21%

Supplemental Crude Oil and Na_8

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, 2022	Dec. 31, 2021	Dec. 31, 2020
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	$ 16,636,393	$ 4,653,565	$ 10,461,641
Extensions, discoveries and improved recoveries, less related costs	7,331,375	2,985,056	187,981
Revisions of previous quantity estimates	(3,096,189)	816,674	(2,952,489)
Changes in estimated future development and abandonment costs	1,283,405	706,168	4,760,286
Increase Due to Purchases of Minerals in Place	1,852,313	3,408,365	53,742
Net change in prices and production costs	15,251,976	9,396,945	(6,912,031)
Accretion of discount	2,049,284	489,273	1,183,993
Sales of crude oil and natural gas produced, net of production costs	(8,406,208)	(4,757,483)	(1,806,758)
Development costs incurred during the period	1,302,693	683,212	863,101
Change in timing of estimated future production and other	1,899,889	1,871,903	(2,325,024)
Change in income taxes	(4,197,370)	(3,617,285)	1,139,123
Net change	15,271,168	11,982,828	(5,808,076)
Standardized measure of discounted future net cash flows at end of year	$ 31,907,561	$ 16,636,393	$ 4,653,565