Document and Entity Information
Document and Entity Information Document | 12 Months Ended |
Dec. 31, 2023 shares | |
Entity Information [Line Items] | |
Document Type | 10-K |
Document Annual Report | true |
Document Period End Date | Dec. 31, 2023 |
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 | 2023 |
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 |
Document Financial Statement Error Correction [Flag] | false |
Entity Shell Company | false |
Entity Common Stock, Shares Outstanding | 0 |
Documents Incorporated by Reference | DOCUMENTS INCORPORATED BY REFERENCE None. |
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, 2023 | Dec. 31, 2022 | Dec. 31, 2020 |
Current assets: | |||
Cash and cash equivalents | $ 26,397 | $ 137,788 | |
Crude oil, natural gas, and natural gas liquids sales | 1,196,262 | 1,313,538 | |
Joint interest and other | 350,907 | 458,391 | |
Allowance for credit losses | (3,172) | (5,514) | |
Receivables, net | 1,543,997 | 1,766,415 | |
Derivative assets | 353,261 | 39,280 | |
Inventories | 190,762 | 173,264 | |
Prepaid expenses and other | 33,450 | 27,508 | |
Total current assets | 2,147,867 | 2,144,255 | |
Net property and equipment, based on successful efforts method of accounting | 19,786,889 | 18,471,914 | |
Investment in unconsolidated affiliates | 240,484 | 210,805 | |
Operating lease right-of-use assets | 38,656 | 25,158 | |
Derivative assets, noncurrent | 155,252 | 3,548 | |
Other noncurrent assets | 18,293 | 22,670 | |
Total assets | 22,387,441 | 20,878,350 | |
Current liabilities: | |||
Accounts payable trade | 835,012 | 850,547 | |
Revenues and royalties payable | 768,381 | 882,256 | |
Accrued liabilities and other | 354,537 | 343,777 | |
Current portion of incentive compensation liability | 130,583 | 125,653 | |
Current portion of income tax liabilities | 84,556 | 152,149 | |
Derivative liabilities | 0 | 88,136 | |
Current portion of operating lease liabilities | 18,112 | 4,086 | |
Current portion of long-term debt | 895,105 | 638,058 | |
Total current liabilities | 3,086,286 | 3,084,662 | |
Long-term debt, net of current portion | 5,734,007 | 7,571,582 | |
Other noncurrent liabilities: | |||
Deferred income tax liabilities, net | 2,867,283 | 2,538,312 | |
Incentive compensation liability, noncurrent | 41,707 | 100,066 | |
Asset retirement obligations, noncurrent | 391,957 | 257,152 | |
Derivative liabilities, noncurrent | 586 | 133,363 | |
Operating lease liabilities, noncurrent | 19,482 | 20,055 | |
Other noncurrent liabilities | 36,346 | 43,550 | |
Total other noncurrent liabilities | 3,357,361 | 3,092,498 | |
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, 2023 and 2022; | 2,996 | 2,996 | |
Retained earnings | 9,850,687 | 6,754,174 | |
Total shareholders’ equity attributable to Continental Resources | 9,853,683 | 6,757,170 | |
Noncontrolling interests | 356,104 | 372,438 | |
Total equity | 10,209,787 | 7,129,608 | $ 6,422,725 |
Total liabilities and equity | $ 22,387,441 | $ 20,878,350 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2023 | Dec. 31, 2022 |
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 | 299,610,267 |
Common stock, outstanding | 299,610,267 | 299,610,267 |
Consolidated Statements of Inco
Consolidated Statements of Income - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Revenues: | |||
Crude oil, natural gas, and natural gas liquids sales | $ 7,684,263 | $ 10,074,675 | $ 5,793,741 |
Gain (loss) on derivative instruments, net | 943,768 | (671,095) | (128,864) |
Crude oil and natural gas service operations | 103,710 | 70,128 | 54,441 |
Total revenues | 8,731,741 | 9,473,708 | 5,719,318 |
Operating costs and expenses: | |||
Production expenses | 717,478 | 621,921 | 406,906 |
Production and ad valorem taxes | 603,534 | 730,132 | 404,362 |
Transportation, gathering, processing, and compression | 338,217 | 316,414 | 224,989 |
Exploration expenses | 16,368 | 23,068 | 21,047 |
Crude oil and natural gas service operations | 82,392 | 37,002 | 21,480 |
Depreciation, depletion, amortization and accretion | 2,264,334 | 1,885,465 | 1,898,082 |
Property impairments | 66,798 | 70,417 | 38,370 |
Transaction costs | 0 | 33,796 | 13,920 |
General and administrative expenses | 279,306 | 401,551 | 233,628 |
Net (gain) loss on sale of assets and other | 50,581 | 262 | (5,146) |
Total operating costs and expenses | 4,419,008 | 4,120,028 | 3,257,638 |
Income from operations | 4,312,733 | 5,353,680 | 2,461,680 |
Other income (expense): | |||
Interest expense | (395,765) | (300,662) | (251,598) |
Loss on extinguishment of debt | 0 | (403) | (290) |
Other | 11,979 | 15,798 | (23,654) |
Total other income (expense) | (383,786) | (285,267) | (275,542) |
Income before income taxes | 3,928,947 | 5,068,413 | 2,186,138 |
Provision for income taxes | (827,630) | (1,020,804) | (519,730) |
Income before equity in net loss of affiliate | 3,101,317 | 4,047,609 | 1,666,408 |
Equity in net loss of affiliate | (3,129) | (1,489) | 0 |
Net income | 3,098,188 | 4,046,120 | 1,666,408 |
Net income attributable to noncontrolling interests | 2,361 | 21,562 | 5,440 |
Net income attributable to Continental Resources | $ 3,095,827 | $ 4,024,558 | $ 1,660,968 |
Basic net income per share attributable to Continental Resources | $ 10.33 | $ 11.45 | $ 4.61 |
Diluted net income per share attributable to Continental Resources | $ 10.33 | $ 11.45 | $ 4.56 |
Consolidated Statements of Equi
Consolidated Statements of Equity - USD ($) $ in Thousands | Total | Common stock | Additional paid-in capital | Treasury stock | Retained earnings | Continental Resources Shareholders' Equity | Noncontrolling Interests |
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 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 | $ 3,643 | 1,131,602 | 6,340,211 | 7,475,456 | |||
Balance, shares at Dec. 31, 2021 | 364,297,520 | ||||||
Noncontrolling interests at Dec. 31, 2021 | 380,869 | ||||||
Total equity at Dec. 31, 2021 | 7,856,325 | ||||||
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] | |||||||
Treasury Stock, Retired, Cost Method, Amount | $ (223,779) | ||||||
Restricted stock: | |||||||
Repurchased and canceled, shares | (5,040,993) | ||||||
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, 2021 | $ 3,643 | 1,131,602 | 6,340,211 | 7,475,456 | |||
Balance, shares at Dec. 31, 2021 | 364,297,520 | ||||||
Noncontrolling interests at Dec. 31, 2021 | 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 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 | ||||||
Increase (Decrease) in Equity [Roll Forward] | |||||||
Net income (loss) attributable to Continental Resources | 3,095,827 | 3,095,827 | 3,095,827 | ||||
Net income attributable to noncontrolling interests | 2,361 | 2,361 | |||||
Net income (loss) | 3,098,188 | ||||||
Change in dividends payable | 686 | 686 | 686 | ||||
Restricted stock: | |||||||
Contributions from noncontrolling interests | 10,188 | 10,188 | |||||
Distributions to noncontrolling interests | (28,883) | (28,883) | |||||
Balance at Dec. 31, 2023 | $ 9,853,683 | $ 2,996 | $ 9,850,687 | $ 9,853,683 | |||
Balance, shares at Dec. 31, 2023 | 299,610,267 | 299,610,267 | |||||
Noncontrolling interests at Dec. 31, 2023 | $ 356,104 | $ 356,104 | |||||
Total equity at Dec. 31, 2023 | $ 10,209,787 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Cash flows from operating activities: | |||
Net income | $ 3,098,188 | $ 4,046,120 | $ 1,666,408 |
Adjustments to reconcile net income to cash provided by operating activities: | |||
Depreciation, depletion, amortization and accretion | 2,265,948 | 1,886,491 | 1,893,106 |
Property impairments | 66,798 | 70,417 | 38,370 |
Non-cash (gain) loss on derivatives, net | (686,598) | 212,976 | (20,814) |
Stock-based compensation | 0 | 217,650 | 63,173 |
Provision for deferred income taxes | 328,970 | 398,429 | 519,730 |
Equity in net loss of affiliate | 3,129 | 1,489 | 0 |
Dry hole costs | 0 | 12,305 | 0 |
Net (gain) loss on sale of assets and other | 50,581 | 262 | (5,146) |
Loss on extinguishment of debt | 0 | 403 | 290 |
Other, net | 21,594 | 27,294 | 35,614 |
Changes in assets and liabilities: | |||
Accounts receivable | 222,091 | (372,529) | (694,981) |
Inventories | (17,600) | (67,478) | (33,411) |
Other current assets | (6,118) | (10,242) | (2,144) |
Accounts payable trade | (38,740) | 164,071 | 106,367 |
Revenues and royalties payable | (111,738) | 253,286 | 298,552 |
Accrued liabilities and other | 2,940 | 51,222 | 109,540 |
Incentive compensation liability | (53,429) | 0 | 0 |
Current income taxes liability | (67,593) | 152,149 | 0 |
Other noncurrent assets and liabilities | (17,436) | (4,625) | (803) |
Net cash provided by operating activities | 5,060,987 | 7,039,690 | 3,973,851 |
Cash flows from investing activities: | |||
Exploration and development | (3,550,502) | (2,838,075) | (2,382,413) |
Purchase of producing crude oil and natural gas properties | (161,408) | (421,850) | (2,548,575) |
Purchase of other property and equipment | (205,356) | (68,189) | (66,598) |
Proceeds from sale of assets | 390,034 | 5,740 | 8,041 |
Contributions to unconsolidated affiliates | (33,862) | (212,294) | 0 |
Net cash used in investing activities | (3,561,094) | (3,534,668) | (4,989,545) |
Cash flows from financing activities: | |||
Credit facility borrowings | 4,792,000 | 3,886,000 | 1,663,000 |
Repayment of credit facility | (5,742,000) | (3,226,000) | (1,323,000) |
Proceeds from issuance of Senior Notes | 0 | 0 | 1,587,776 |
Redemption and repurchase of Senior Notes | (636,000) | (31,829) | (630,782) |
Proceeds from other debt | 0 | 750,000 | 0 |
Repayment of other debt | (2,410) | (2,326) | (2,243) |
Debt issuance costs | (242) | (5,148) | (12,082) |
Contributions from noncontrolling interests | 10,580 | 13,665 | 31,493 |
Distributions to noncontrolling interests | (31,156) | (40,685) | (22,447) |
Repurchase of common stock prior to take-private transaction | 0 | (99,855) | (123,924) |
Take-private transaction (see Note 1) | 0 | (4,312,642) | 0 |
Repurchase of restricted stock for tax withholdings | 0 | (35,444) | (12,804) |
Dividends paid on common stock | (2,056) | (283,838) | (165,895) |
Net cash provided by (used in) financing activities | (1,611,284) | (3,388,102) | 989,092 |
Net change in cash and cash equivalents | (111,391) | 116,920 | (26,602) |
Cash and cash equivalents at beginning of period | 137,788 | 20,868 | 47,470 |
Cash and cash equivalents at end of period | $ 26,397 | $ 137,788 | $ 20,868 |
Organization and Summary of Sig
Organization and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2023 | |
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. 2022 Take-Private Transaction On November 22, 2022 , the Company completed a series of take-private transactions with Omega Acquisition, Inc, an entity owned by the Company’s founder, Harold G. Hamm, pursuant to which the Company became wholly owned by Mr. Hamm, certain members of his family and their affiliated entities (the “Hamm Family”). 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. The 2022 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. 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. The Company incurred $ 32 million of legal and advisory fees in 2022 in connection with the take-private transaction which are included in the caption “Transaction costs” in the Consolidated Statements of Income for the year ended December 31, 2022. Following the consummation of the transactions in November 2022: (i) our common stock ceased to be listed on the New York Stock Exchange, (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 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. The Company evaluated its December 31, 2023 financial statements for subsequent events through February 22, 2024, 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, 2023 , the Company had cash deposits in excess of federally insured amounts of approximately $ 24.7 million. The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area. Accounts receivable Receivables arising from crude oil and natural gas sales and joint interest receivables are generally unsecured. Accounts receivable are due within 30 days and are considered delinquent after 60 days. The Company 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 $ 3.2 million and $ 5.5 million as of December 31, 2023 and 2022, 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, 2023 , no purchaser accounted for more than 10 % of the Company’s total crude oil, natural gas, and natural gas liquids sales for 2023 . 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, 2023 and 2022 consisted of the following: December 31, In thousands 2023 2022 Tubular goods and equipment $ 65,205 $ 38,636 Crude oil 125,557 130,192 Natural gas — 4,436 Total $ 190,762 $ 173,264 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, 2021 through December 31, 2023: In thousands 2023 2022 2021 Asset retirement obligations at January 1 $ 261,087 $ 219,824 $ 179,676 Accretion expense 14,818 12,857 11,125 Revisions (1) 112,803 ( 6,672 ) ( 1,291 ) Plus: Additions for new assets 18,929 37,413 32,351 Less: Plugging costs and sold assets ( 5,709 ) ( 2,335 ) ( 2,037 ) Total asset retirement obligations at December 31 $ 401,928 $ 261,087 $ 219,824 Less: Current portion of asset retirement obligations at December 31 (2) 9,971 3,935 4,123 Non-current portion of asset retirement obligations at December 31 $ 391,957 $ 257,152 $ 215,701 (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, 2023 and 2022 , net property and equipment on the consolidated balance sheets included $ 204.2 million and $ 96.5 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 $ 46.5 million and $ 56.3 million (net of accumulated amortization of $ 37.3 million and $ 46.3 million) relating to its long-term debt at December 31, 2023 and 2022, respectively. Unamortized capitalized costs associated with the Company’s Notes, note payable, and term loan totaled $ 39.4 million and $ 46.8 million at December 31, 2023 and 2022, 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 $ 7.1 million and $ 9.4 million at December 31, 2023 and 2022, respectively, and are reflected in “Other noncurrent assets” on the consolidated balance sheets. For the years ended December 31, 2023, 2022 and 2021 , the Company recognized amortization expense associated with capitalized debt issuance costs of $ 10.0 million, $ 9.3 million, and $ 7.2 million, respectively, which are reflected in “Interest expense” on the consolidated statements of income. 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 under the caption “Gain (loss) on derivative instruments, net.” See Note 6. Derivative Instruments for additional information. Fair value of financial instruments The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. See Note 7. Fair Value Measurements for a discussion of the methods used to determine fair value for the Company’s financial instruments and the quantification of fair value for its derivatives and long-term debt obligations at December 31, 2023 and 2022 . 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 per share is computed by dividing net income 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 per share attributable to the Company for the years ended December 31, 2023, 2022, and 2021. Year ended December 31, In thousands, except per share data 2023 2022 2021 Net income attributable to Continental Resources (numerator) $ 3,095,827 $ 4,024,558 $ 1,660,968 Weighted average shares (denominator): Weighted average shares - basic 299,610 351,392 360,434 Non-vested restricted stock and restricted stock units (1) — — 4,019 Weighted average shares - diluted 299,610 351,392 364,453 Net income per share attributable to Continental Resources: Basic $ 10.33 $ 11.45 $ 4.61 Diluted $ 10.33 $ 11.45 $ 4.56 (1) For the years ended December 31, 2023 and 2022, the Company’s outstanding long-term incentive awards 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 awards is presented for the years ended December 31, 2023 and 2022. |
Property Acquisitions
Property Acquisitions | 12 Months Ended |
Dec. 31, 2023 | |
Business Combination and Asset Acquisition [Abstract] | |
Property Acquisitions and Dispositions | Note 2. Property Acquisitions and Dispositions 2023 During the year ended December 31, 2023, the Company executed acquisitions of oil and gas properties in various areas for cash consideration totaling $ 681 million. The Company accounted for each acquisition as an asset acquisition under ASC Topic 805—Business Combinations. Of the purchase prices, a total of $ 161 million was allocated to proved properties and a total of $ 520 million was allocated to unproved properties. During the year ended December 31, 2023, the Company executed sales of oil and gas properties in various areas for cash proceeds totaling $ 390 million and recognized pre-tax net losses on the transactions totaling $ 51 million. The disposed properties represented an immaterial portion of the Company's production and proved reserves. 2022 During the year ended December 31, 2022, the Company executed acquisitions of oil and gas properties in various areas for cash consideration totaling $ 714 million. The Company accounted for each acquisition as an asset acquisition under ASC Topic 805—Business Combinations. Of the purchase prices, a total of $ 422 million was allocated to proved properties and a total of $ 292 million 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 for $ 3.06 billion in cash. The acquisition method under ASC Topic 805 was used to record the transaction, 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 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 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. 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 Pro forma combined total revenues $ 6,657 Pro forma combined net income attributable to Continental $ 2,097 Powder River Basin Acquisitions During the year ended December 31, 2021 , the Company completed acquisitions of oil and gas properties in the Powder River Basin for cash consideration totaling $ 453 million. The Company accounted for each acquisition as an asset acquisition under ASC Topic 805—Business Combinations. Of the purchase prices, a total of $ 210 million was allocated to proved properties and a total of $ 243 million was allocated to unproved properties. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2023 | |
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 2023 2022 2021 Supplemental cash flow information: Cash paid for interest $ 387,686 $ 279,571 $ 214,727 Cash paid for income taxes (1) 566,253 470,147 3 Cash received for income tax refunds 2 16 58 Non-cash investing activities: Asset retirement obligation additions and revisions, net 131,732 30,741 31,060 (1) Amounts for 2023 and 2022 represent estimated quarterly payments for 2023 and 2022 federal and state income taxes based on an estimate of taxable income for each respective year. As of December 31, 2023 and 2022 , the Company had $ 367.2 million and $ 344.9 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. |
Net Property and Equipment
Net Property and Equipment | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 and 2022. December 31, In thousands 2023 2022 Proved crude oil and natural gas properties $ 37,400,304 $ 34,741,054 Unproved crude oil and natural gas properties 1,775,662 1,513,627 Service properties, equipment and other 1,014,093 549,528 Total property and equipment 40,190,059 36,804,209 Accumulated depreciation, depletion and amortization ( 20,403,170 ) ( 18,332,295 ) Net property and equipment $ 19,786,889 $ 18,471,914 |
Accrued Liabilities and Other
Accrued Liabilities and Other | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 and 2022: December 31, In thousands 2023 2022 Prepaid advances from joint interest owners $ 36,923 $ 15,575 Accrued compensation 88,644 81,646 Accrued production taxes, ad valorem taxes and other non-income taxes 133,456 145,436 Accrued interest 79,640 83,724 Current portion of asset retirement obligations 9,971 3,935 Other 5,903 13,461 Accrued liabilities and other $ 354,537 $ 343,777 |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 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 Swaps Floor Ceiling January 2024 - December 2024 Swaps - Henry Hub 618,000 MMBtus/day $ 3.44 Collars - Henry Hub 50,000 MMBtus/day $ 3.12 $ 4.09 Swaps - WAHA 42,000 MMBtus/day $ 3.08 January 2025 - December 2025 Swaps - Henry Hub 575,000 MMBtus/day $ 3.93 January 2026 - December 2026 Swaps - Henry Hub 635,000 MMBtus/day $ 4.11 January 2027 - December 2027 Swaps - Henry Hub 123,000 MMBtus/day $ 4.01 Crude oil derivatives Weighted Average Period and Type of Contract Average Volumes Hedged Roll Swaps Fixed Swaps January 2024 - December 2024 Fixed Swaps - WTI 76,000 Bbls/day $ 76.84 January 2024 - December 2024 Roll Swaps - NYMEX 36,000 Bbls/day $ 0.71 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 2023 2022 2021 Cash received (paid) on derivatives: Crude oil fixed price swaps $ 17,989 $ — $ ( 44,463 ) Crude oil collars — — ( 9,365 ) Crude oil NYMEX roll swaps 3,519 ( 9,234 ) ( 163 ) Natural gas basis swaps 4,818 9,674 — Natural gas WAHA swaps 19,435 ( 16,350 ) — Natural gas fixed price swaps 178,529 ( 353,326 ) ( 84,141 ) Natural gas collars 29,139 ( 66,596 ) ( 11,546 ) Natural gas three-way collars 3,741 ( 22,287 ) — Cash received (paid) on derivatives, net 257,170 ( 458,119 ) ( 149,678 ) Non-cash gain (loss) on derivatives: Crude oil collars — — 227 Crude oil fixed price swaps 134,548 11,696 — Crude oil NYMEX roll swaps 4,051 1,879 957 Natural gas basis swaps ( 8,910 ) 9,088 ( 177 ) Natural gas WAHA swaps 2,138 19,386 — Natural gas fixed price swaps 513,129 ( 219,388 ) 25,565 Natural gas collars 42,240 ( 34,303 ) ( 7,690 ) Natural gas three-way collars ( 598 ) ( 1,334 ) 1,932 Non-cash gain (loss) on derivatives, net 686,598 ( 212,976 ) 20,814 Gain (loss) on derivative instruments, net $ 943,768 $ ( 671,095 ) $ ( 128,864 ) 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, 2023 and 2022, all at fair value. December 31, In thousands 2023 2022 Commodity derivative assets: Gross amounts of recognized assets $ 510,375 $ 50,559 Gross amounts offset on balance sheet ( 1,862 ) ( 7,731 ) Net amounts of assets on balance sheet 508,513 42,828 Commodity derivative liabilities: Gross amounts of recognized liabilities ( 2,448 ) ( 229,230 ) Gross amounts offset on balance sheet 1,862 7,731 Net amounts of liabilities on balance sheet $ ( 586 ) $ ( 221,499 ) 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 2023 2022 Derivative assets $ 353,261 $ 39,280 Derivative assets, noncurrent 155,252 3,548 Net amounts of assets on balance sheet 508,513 42,828 Derivative liabilities — ( 88,136 ) Derivative liabilities, noncurrent ( 586 ) ( 133,363 ) Net amounts of liabilities on balance sheet ( 586 ) ( 221,499 ) Total derivative assets (liabilities), net $ 507,927 $ ( 178,671 ) |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 and 2022. Fair value measurements at December 31, 2023 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Crude oil fixed price swaps $ — $ 146,243 $ — $ 146,243 Crude oil NYMEX roll swaps — 6,888 — 6,888 Natural gas WAHA swaps — 21,523 — 21,523 Natural gas fixed price swaps — 321,350 — 321,350 Natural gas collars — 11,923 — 11,923 Total $ — $ 507,927 $ — $ 507,927 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 ) 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, 2023 , the Company’s commodity price assumptions were based on forward NYMEX strip prices through year-end 2028 and were then escalated at 3 % per year thereafter. Operating cost assumptions were based on current costs escalated at 3 % per year beginning in 2025. 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 years ended December 31, 2023 and 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 $ 15.5 million and $ 17.5 million for 2023 and 2022, respectively. For the year ended December 31, 2021, estimated future net cash flows were determined to be in excess of cost basis, and therefore no impairments were recorded for the Company's proved crude oil and natural gas properties in 2021. Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2023, 2022, and 2021, 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. Year ended December 31, In thousands 2023 2022 2021 Proved property impairments $ 15,455 $ 17,520 $ — Unproved property impairments 51,343 52,897 38,370 Total $ 66,798 $ 70,417 $ 38,370 Financial Instruments Not Recorded at Fair Value The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the consolidated financial statements. See Note 8. Debt for discussion of the changes in the Company’s outstanding debt in 2023 and 2022. December 31, 2023 December 31, 2022 In thousands Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Debt: Credit facility $ 210,000 $ 210,000 $ 1,160,000 $ 1,160,000 Term Loan 748,092 748,092 747,073 747,073 Notes payable 17,642 16,300 20,041 18,300 4.5 % Senior Notes due 2023 — — 635,648 633,600 3.8 % Senior Notes due 2024 892,610 886,400 891,404 867,400 2.268 % Senior Notes due 2026 795,541 736,400 794,062 693,100 4.375 % Senior Notes due 2028 994,327 968,000 993,076 917,200 5.75 % Senior Notes due 2031 1,485,460 1,490,900 1,483,843 1,412,300 2.875 % Senior Notes due 2032 792,977 647,100 792,238 600,900 4.9 % Senior Notes due 2044 692,463 556,400 692,255 527,900 Total debt $ 6,629,112 $ 6,259,592 $ 8,209,640 $ 7,577,773 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. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2023 | |
Debt Disclosure [Abstract] | |
Debt | Note 8. Debt The Company's debt, net of unamortized discounts, premiums, and debt issuance costs totaling $ 41.7 million and $ 49.6 million at December 31, 2023 and 2022, respectively, consists of the following. December 31, In thousands 2023 2022 Credit facility $ 210,000 $ 1,160,000 Term loan 748,092 747,073 Notes payable 17,642 20,041 4.5 % Senior Notes due 2023 — 635,648 3.8 % Senior Notes due 2024 (1) 892,610 891,404 2.268 % Senior Notes due 2026 795,541 794,062 4.375 % Senior Notes due 2028 994,327 993,076 5.75 % Senior Notes due 2031 1,485,460 1,483,843 2.875 % Senior Notes due 2032 792,977 792,238 4.9 % Senior Notes due 2044 692,463 692,255 Total debt 6,629,112 8,209,640 Less: Current portion of long-term debt 895,105 638,058 Long-term debt, net of current portion $ 5,734,007 $ 7,571,582 (1) The Company’s 2024 Notes, which have a face value of $ 893.1 million at December 31, 2023 , are scheduled to mature on June 1, 2024 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, 2023 along with the current portion of the Company's notes payable. Credit Facility The Company has a credit facility, maturing in October 2026, with aggregate lender commitments totaling $ 2.255 billion. The credit facility is unsecured and has no borrowing base requirement subject to redetermination. The Company had $ 210 million of outstanding borrowings on its credit facility at December 31, 2023 . 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, 2023 wa s 6.95 %. The Company had approximately $ 2.04 billion of borrowing availability on its credit facility at December 31, 2023 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, 2023. 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, 2023. 2024 Notes 2026 Notes 2028 Notes 2031 Notes 2032 Notes 2044 Notes Face value (in thousands) $ 893,126 $ 800,000 $ 1,000,000 $ 1,500,000 $ 800,000 $ 700,000 Maturity date June 1, 2024 November 15, 2026 January 15, 2028 January 15, 2031 April 1, 2032 June 1, 2044 Interest payment dates 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) 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, 2023. 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 and Dispositions. Retirement of Senior Notes 2023 In April 2023, the Company fully repaid its outstanding $ 636 million of 2023 Notes that were scheduled to mature on April 15, 2023. The redemption price was equal to 100 % of the principal amount plus accrued and unpaid interest to the redemption date. The aggregate of the principal amount and accrued interest paid upon redemption was $ 650.3 million. 2022 In 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 “Loss on extinguishment of debt” in the consolidated statements of income. 2021 In 2021, the Company fully repaid the $ 630.8 million principal amount of its outstanding 2022 Notes and recognized a pre-tax loss on extinguishment of debt totaling $ 0.3 million related to the redemption. 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 6.98 % at December 31, 2023. 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, 2023. 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, $ 2.5 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, 2023 associated with the loans. |
Revenues
Revenues | 12 Months Ended |
Dec. 31, 2023 | |
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 $ 284.2 million , $ 254.0 million , and $ 185.1 million for the years ended December 31, 2023, 2022, and 2021, 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 $ 54.0 million , $ 62.4 million , and $ 39.9 million for the years ended December 31, 2023, 2022, and 2021, 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, delivery, and disposal activities. 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, 2023 2022 2021 In thousands Crude Oil Natural Gas and NGLs Total Crude Oil Natural Gas and NGLs Total Crude Oil Natural Gas and NGLs Total Bakken $ 3,777,412 $ 380,359 $ 4,157,771 $ 3,899,749 $ 1,051,870 $ 4,951,619 $ 2,786,320 $ 562,695 $ 3,349,015 Anadarko Basin 999,009 687,687 1,686,696 1,109,405 1,839,473 2,948,878 874,752 1,264,069 2,138,821 Powder River Basin 410,963 43,968 454,931 557,943 125,065 683,008 101,705 13,110 114,815 Permian Basin 1,135,421 74,133 1,209,554 1,122,290 151,217 1,273,507 24,857 4,499 29,356 All other 175,118 193 175,311 216,616 1,047 217,663 161,660 74 161,734 Crude oil, natural gas, and natural gas liquids sales $ 6,497,923 $ 1,186,340 $ 7,684,263 $ 6,906,003 $ 3,168,672 $ 10,074,675 $ 3,949,294 $ 1,844,447 $ 5,793,741 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, 2023 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, 2023, 2022, and 2021 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, 2023 | |
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 $ 3.2 million and $ 5.5 million at December 31, 2023 and 2022 , respectively, which is reported as “Allowance for credit losses” in the consolidated balance sheets. Aggregate credit loss expenses totaled $ 0.1 million, $ 3.3 million, and $ 0.8 million for the years ended December 31, 2023, 2022, and 2021, respectively, which are included in “General and administrative expenses” in the consolidated statements of income. 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, 2023 and December 31, 2022. 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, 2023, 2022, and 2021. 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 $ 3.2 million and $ 5.5 million at December 31, 2023 and 2022, 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, 2023, 2022, and 2021 . |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Note 11. Income Taxes The items comprising the Company’s provision for income taxes are as follows for the periods presented: Year ended December 31, In thousands 2023 2022 2021 Current income tax provision: United States federal $ 461,487 $ 538,704 $ — Various states 37,173 83,671 — Total current income tax provision 498,660 622,375 — Deferred income tax provision: United States federal 318,484 374,802 467,051 Various states 10,486 23,627 52,679 Total deferred income tax provision 328,970 398,429 519,730 Provision for income taxes $ 827,630 $ 1,020,804 $ 519,730 Effective tax rate 21.1 % 20.1 % 23.8 % The Company’s effective tax rate differs from the United States federal statutory tax rate due to the effect of state income taxes, equity/incentive 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 2023 2022 2021 Income before income taxes $ 3,928,947 $ 5,068,413 $ 2,186,138 U.S. federal statutory tax rate 21.0 % 21.0 % 21.0 % Expected income tax provision based on U.S. federal statutory tax rate 825,079 1,064,367 459,089 Items impacting the effective tax rate: State and local income taxes, net of federal benefit 98,257 126,932 77,979 Tax (benefit) deficiency from stock-based compensation — ( 5,282 ) 5,869 Change in valuation allowance — — ( 14,474 ) Tax credits for increasing research activities ( 67,039 ) ( 151,913 ) — Other, net ( 28,667 ) ( 13,300 ) ( 8,733 ) Provision for income taxes $ 827,630 $ 1,020,804 $ 519,730 Effective tax rate 21.1 % 20.1 % 23.8 % 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. 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 and the remaining valuation allowance was released. No valuation allowances were recognized during the years ended December 31, 2023 and 2022. The Company will continue to evaluate both the positive and negative evidence on a periodic 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, 2023 and 2022 are reflected in the table below. December 31, In thousands 2023 2022 Deferred tax assets United States net operating loss carryforwards $ 56,377 $ 63,128 Incentive/equity compensation 40,929 34,987 Net deferred hedge losses — 42,898 Other 28,080 31,324 Total deferred tax assets 125,386 172,337 Valuation allowance — — Total deferred tax assets, net of valuation allowance 125,386 172,337 Deferred tax liabilities Property and equipment ( 2,870,259 ) ( 2,708,641 ) Net deferred hedge gains ( 120,662 ) — Other ( 1,748 ) ( 2,008 ) Total deferred tax liabilities ( 2,992,669 ) ( 2,710,649 ) Deferred income tax liabilities, net $ ( 2,867,283 ) $ ( 2,538,312 ) As of December 31, 2023 , the Company had net operating loss (“NOL”) carryforwards in Oklahoma totaling $ 1.8 billion, of which $ 673 million expires between 2035 and 2037, and the remaining $ 1.1 billion has an indefinite life. Any available statutory depletion carryforwards will be recognized when realized. The Company files income tax returns in U.S. federal and state jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal or state income tax examinations by tax authorities for years prior to 2020. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2023 | |
Leases [Abstract] | |
Leases | Note 12. Leases The Company’s lease liabilities recognized on the balance sheet as a lessee totaled $ 37.6 million and $ 24.1 million as of December 31, 2023 and 2022, 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 2023 2022 Surface use agreements $ 17,263 $ 18,136 Field equipment 19,713 5,224 Other 618 781 Total $ 37,594 $ 24,141 Minimum future commitments by year for the Company’s operating leases as of December 31, 2023 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 2024 $ 19,603 2025 4,571 2026 1,848 2027 1,827 2028 1,765 Thereafter 16,586 Total operating lease liabilities, at undiscounted value $ 46,200 Less: Imputed interest ( 8,606 ) Total operating lease liabilities, at discounted present value $ 37,594 Less: Current portion of operating lease liabilities ( 18,112 ) Operating lease liabilities, noncurrent $ 19,482 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 2023 2022 2021 Lease costs: Operating lease costs $ 13,121 $ 3,484 $ 6,653 Variable lease costs 896 650 3,271 Short-term lease costs 168,680 124,535 77,551 Total lease costs $ 182,697 $ 128,669 $ 87,475 Other information: Right-of-use assets obtained in exchange for new operating lease liabilities $ 24,949 $ 19,944 $ 10,481 Operating cash flows from operating leases included in lease liabilities 13,166 4,370 1,731 Weighted average remaining lease term as of December 31 (in years) 6.9 12.0 14.4 Weighted average discount rate as of December 31 4.7 % 4.8 % 5.0 % |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 under the arrangements amount to approximately $ 824 million, of which $ 307 million is expected to be incurred in 2024, $ 164 million in 2025, $ 139 million in 2026, $ 136 million in 2027, $ 70 million in 2028, and $ 8 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. Litigation pertaining to the Company's routine operations The Company is involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material adverse effect on its financial condition, results of operations or cash flows. As of December 31, 2023 and 2022, the Company had recognized a liability within “Other noncurrent liabilities” of $ 13.8 million and $ 20.2 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 Nature of Business—2022 Take-Private Transaction often attract litigation and demands from minority shareholders. In April 2023, three separate putative class action lawsuits were consolidated under the caption In re Continental Resources, Inc. Shareholder Litigation , Case No. CJ-2022-4162, in the District Court of Oklahoma County, Oklahoma (the “Consolidated Action”). In the Consolidated Action, the plaintiffs, on behalf of themselves and all other similarly situated former shareholders of the Company, allege that Mr. Hamm, certain trusts established for the benefit of Mr. Hamm and/or his family members, and the Company’s other directors breached their fiduciary duties in connection with the take-private transaction and seek: (i) monetary damages; (ii) the costs and expenses associated with the lawsuits; and (iii) other equitable relief. The defendants continue to vigorously defend themselves against these claims. In January 2023, 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”), all former shareholders of the Company, 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. The Company continues to vigorously defend itself against these claims. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2023 | |
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 $ 0.4 million, $ 0.5 million, and $ 0.4 million and received payments from these affiliates of $ 0.1 million, $ 0.2 million, and $ 0.1 million during the years ended December 31, 2023, 2022, and 2021, respectively, relating to the operations of the respective properties. At December 31, 2023 and 2022 , approximately $ 35,000 and $ 6,000 , 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, 2023 and 2022 , approximately $ 31,000 and $ 36,000 , 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 2023, 2022, and 2021 , the Company charged affiliates approximately $ 28,100 , $ 16,400 , and $ 11,300 , respectively, for use of its corporate aircraft crews, fuel, and reimbursement of expenses and received approximately $ 31,000 , $ 13,000 , and $ 5,000 from affiliates in 2023, 2022, and 2021 , respectively, in connection with such items. The Company was charged approximately $ 312,000 , $ 235,000 , and $ 117,000 , respectively, by affiliates for use of their aircraft and reimbursement of expenses during 2023, 2022, and 2021 and paid $ 299,000 , $ 219,000 , and $ 84,000 to the affiliates in 2023, 2022, and 2021, respectively. At December 31, 2023 and 2022 , approximately $ 7,000 and $ 9,800 , 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, 2023 and 2022 , approximately $ 63,000 and $ 49,000 , respectively, was due to an affiliate relating to these transactions, which is included in “Accounts payable trade” on the consolidated balance sheets. |
Incentive Compensation
Incentive Compensation | 12 Months Ended |
Dec. 31, 2023 | |
Share-Based Payment Arrangement [Abstract] | |
Incentive Compensation | Note 15. Incentive Compensation Long-term Incentive Compensation The Company has granted long-term incentive compensation awards to employees pursuant to the Continental Resources, Inc. 2022 Long-Term Incentive Plan (“2022 Plan”). Such awards generally vest after three years of employee service. The Company intends to settle all outstanding awards vesting in the future in cash and, thus, the awards are classified as liability awards pursuant to ASC Topic 718, Compensation—Stock Compensation. At December 31, 2023 , the Company had recorded a current liability of $ 130.6 million and a non-current liability of $ 41.7 million in the captions “Current portion of incentive compensation liability” and “Incentive compensation liability, noncurrent,” respectively, in the consolidated balance sheets associated with the awards. 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, 2023 . 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, was $ 91.3 million for the year ended December 31, 2023. As of December 31, 2023 , there was approximately $ 90.4 million of unrecognized liabilities and compensation expense related to unvested awards, which are expected to be recognized over a weighted average period of 1.5 years. The current liability at December 31, 2023 was paid in cash to employees in February 2024 upon the scheduled vesting of awards. The Company’s incentive compensation liability will be remeasured each reporting period leading up to the applicable award vesting dates to reflect additional service rendered by employees and to reflect changes in expected cash payments arising from underlying changes in the value of the Company based on independent third party appraisals. 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. Stock-based Compensation Prior to the Hamm Family’s take-private transaction described in Note 1. Organization and Summary of Significant Accounting Policies—2022 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 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, was $ 217.8 million and $ 63.2 million for the years ended December 31, 2022, and 2021, 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 in 2022 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 which are classified as liability awards under ASC 718. 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 consolidated balance sheets associated with the Rollover Shares. The current liability at December 31, 2022 was paid in cash to employees in the first quarter of 2023 upon the scheduled vesting of awards. A summary of changes in non-vested restricted shares outstanding prior to the take-private transaction from December 31, 2020 to December 31, 2022 is presented below. Number of Weighted 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 and 2021 was $ 98.4 million and $ 46.7 million, respectively. |
Shareholders' Equity Attributab
Shareholders' Equity Attributable to Continental Resources | 12 Months Ended |
Dec. 31, 2023 | |
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 Share repurchases made under the Company's share repurchase program prior to the Hamm Family’s take-private transaction are reflected below for the years ended December 31, 2022, and 2021. Number of Aggregate cost (in thousands) 2021 Share Repurchases 3,198,571 $ 123,924 2022 Share Repurchases 1,842,422 99,855 Total 5,040,993 $ 223,779 As of December 31, 2023 and 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 During the years ended December 31, 2022 and 2021, the Company paid dividends of $ 283.8 million and $ 165.9 million, respectively, on its then-outstanding common stock. Additionally, for the year ended December 31, 2023 the Company paid $ 2.1 million of dividends to employees upon vesting of long-term incentive units which had accumulated dividends declared in periods prior to the take-private transaction. |
Noncontrolling Interests
Noncontrolling Interests | 12 Months Ended |
Dec. 31, 2023 | |
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”). 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 $ 345.1 million and $ 361.4 million at December 31, 2023 and 2022, 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 $ 11.0 million at December 31, 2023 and 2022 , respectively. |
Equity Investment
Equity Investment | 12 Months Ended |
Dec. 31, 2023 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Equity Investment | Note 18. Equity Investment In 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 in the Midwestern United States. The Company committed to invest a total of $ 250 million with Summit to fund a portion of its development and construction activities. During the years ended December 31, 2023 and 2022, the Company contributed $ 33 million and $ 210 million, respectively, toward its $ 250 million commitment to Summit, which is included in the caption “Investment in unconsolidated affiliates” in the consolidated balance sheets. Upon completion of Summit’s 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 years ended December 31, 2023 and 2022. |
Capitalized Exploratory Well Co
Capitalized Exploratory Well Costs | 12 Months Ended |
Dec. 31, 2023 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Capitalized Exploratory Well Costs | Note 19. Capitalized Exploratory Well Costs 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 as dry hole costs, a component of “Exploration expenses.” Where sufficient hydrocarbons have been discovered to justify further exploration or appraisal activities, exploratory drilling costs are deferred under the caption “Net property and equipment” on the consolidated balance sheets pending the outcome of those activities. On a periodic 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 2023 2022 2021 Balance at January 1 $ 84,822 $ 37,673 $ 32,737 Additions to capitalized exploratory well costs pending determination of proved reserves 345,434 286,059 122,068 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves ( 270,490 ) ( 229,348 ) ( 117,131 ) Capitalized exploratory well costs charged to expense ( 32 ) ( 9,562 ) ( 1 ) Balance at December 31 $ 159,734 $ 84,822 $ 37,673 Number of gross wells 34 36 17 As of December 31, 2023 , 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, 2023 | |
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 provides 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 99 %, 98 %, and 98 % of the Company’s total proved reserves as of December 31, 2023, 2022, and 2021, respectively. Remaining reserve estimates were prepared by the Company’s internal technical staff. 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, 2023, 2022, and 2021 were computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by SEC rules. 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. Natural gas imbalance receivables and payables for each of the three years ended December 31, 2023, 2022, and 2021 were not material and have not been included in the reserve estimates. Proved crude oil and natural gas reserves The following 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, 2023, 2022, and 2021 . 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 reserves are 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. December 31, 2023 2022 2021 Proved Developed Reserves Crude oil (MBbl) 401,851 454,299 424,153 Natural Gas (MMcf) 3,221,566 3,486,774 2,901,147 Total (MBoe) 938,779 1,035,428 907,678 Proved Undeveloped Reserves Crude oil (MBbl) 512,183 435,240 369,377 Natural Gas (MMcf) 2,376,765 2,358,578 2,209,532 Total (MBoe) 908,310 828,336 737,632 Total Proved Reserves Crude oil (MBbl) 914,034 889,539 793,530 Natural Gas (MMcf) 5,598,331 5,845,352 5,110,679 Total (MBoe) 1,847,089 1,863,764 1,645,310 |
Organization and Summary of S_2
Organization and Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
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 November 22, 2022 , the Company completed a series of take-private transactions with Omega Acquisition, Inc, an entity owned by the Company’s founder, Harold G. Hamm, pursuant to which the Company became wholly owned by Mr. Hamm, certain members of his family and their affiliated entities (the “Hamm Family”). 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. The 2022 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. 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. The Company incurred $ 32 million of legal and advisory fees in 2022 in connection with the take-private transaction which are included in the caption “Transaction costs” in the Consolidated Statements of Income for the year ended December 31, 2022. Following the consummation of the transactions in November 2022: (i) our common stock ceased to be listed on the New York Stock Exchange, (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 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. The Company evaluated its December 31, 2023 financial statements for subsequent events through February 22, 2024, 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, 2023 , the Company had cash deposits in excess of federally insured amounts of approximately $ 24.7 million. The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area. |
Accounts Receivable | Accounts receivable Receivables arising from crude oil and natural gas sales and joint interest receivables are generally unsecured. Accounts receivable are due within 30 days and are considered delinquent after 60 days. The Company 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 $ 3.2 million and $ 5.5 million as of December 31, 2023 and 2022, 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, 2023 , no purchaser accounted for more than 10 % of the Company’s total crude oil, natural gas, and natural gas liquids sales for 2023 . 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, 2023 and 2022 consisted of the following: December 31, In thousands 2023 2022 Tubular goods and equipment $ 65,205 $ 38,636 Crude oil 125,557 130,192 Natural gas — 4,436 Total $ 190,762 $ 173,264 |
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 $ 46.5 million and $ 56.3 million (net of accumulated amortization of $ 37.3 million and $ 46.3 million) relating to its long-term debt at December 31, 2023 and 2022, respectively. Unamortized capitalized costs associated with the Company’s Notes, note payable, and term loan totaled $ 39.4 million and $ 46.8 million at December 31, 2023 and 2022, 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 $ 7.1 million and $ 9.4 million at December 31, 2023 and 2022, respectively, and are reflected in “Other noncurrent assets” on the consolidated balance sheets. For the years ended December 31, 2023, 2022 and 2021 , the Company recognized amortization expense associated with capitalized debt issuance costs of $ 10.0 million, $ 9.3 million, and $ 7.2 million, respectively, which are reflected in “Interest expense” on the consolidated statements of income. |
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 under the caption “Gain (loss) on derivative instruments, net.” See Note 6. Derivative Instruments for additional information. |
Fair Value of Financial Instruments | Fair value of financial instruments The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. See Note 7. Fair Value Measurements for a discussion of the methods used to determine fair value for the Company’s financial instruments and the quantification of fair value for its derivatives and long-term debt obligations at December 31, 2023 and 2022 . |
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 per share is computed by dividing net income 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 $ 284.2 million , $ 254.0 million , and $ 185.1 million for the years ended December 31, 2023, 2022, and 2021, 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 $ 54.0 million , $ 62.4 million , and $ 39.9 million for the years ended December 31, 2023, 2022, and 2021, 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, delivery, and disposal activities. 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, 2023 | |
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 $ 284.2 million , $ 254.0 million , and $ 185.1 million for the years ended December 31, 2023, 2022, and 2021, 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 $ 54.0 million , $ 62.4 million , and $ 39.9 million for the years ended December 31, 2023, 2022, and 2021, 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, delivery, and disposal activities. 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, 2023 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Components of Inventories | The components of inventory as of December 31, 2023 and 2022 consisted of the following: December 31, In thousands 2023 2022 Tubular goods and equipment $ 65,205 $ 38,636 Crude oil 125,557 130,192 Natural gas — 4,436 Total $ 190,762 $ 173,264 |
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, 2021 through December 31, 2023: In thousands 2023 2022 2021 Asset retirement obligations at January 1 $ 261,087 $ 219,824 $ 179,676 Accretion expense 14,818 12,857 11,125 Revisions (1) 112,803 ( 6,672 ) ( 1,291 ) Plus: Additions for new assets 18,929 37,413 32,351 Less: Plugging costs and sold assets ( 5,709 ) ( 2,335 ) ( 2,037 ) Total asset retirement obligations at December 31 $ 401,928 $ 261,087 $ 219,824 Less: Current portion of asset retirement obligations at December 31 (2) 9,971 3,935 4,123 Non-current portion of asset retirement obligations at December 31 $ 391,957 $ 257,152 $ 215,701 (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 per share attributable to the Company for the years ended December 31, 2023, 2022, and 2021. Year ended December 31, In thousands, except per share data 2023 2022 2021 Net income attributable to Continental Resources (numerator) $ 3,095,827 $ 4,024,558 $ 1,660,968 Weighted average shares (denominator): Weighted average shares - basic 299,610 351,392 360,434 Non-vested restricted stock and restricted stock units (1) — — 4,019 Weighted average shares - diluted 299,610 351,392 364,453 Net income per share attributable to Continental Resources: Basic $ 10.33 $ 11.45 $ 4.61 Diluted $ 10.33 $ 11.45 $ 4.56 (1) For the years ended December 31, 2023 and 2022, the Company’s outstanding long-term incentive awards 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 awards is presented for the years ended December 31, 2023 and 2022. |
Property Acquisitions and Dispo
Property Acquisitions and Dispositions (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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. 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 Pro forma combined total revenues $ 6,657 Pro forma combined net income attributable to Continental $ 2,097 |
Supplemental Cash Flow Inform_2
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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 2023 2022 2021 Supplemental cash flow information: Cash paid for interest $ 387,686 $ 279,571 $ 214,727 Cash paid for income taxes (1) 566,253 470,147 3 Cash received for income tax refunds 2 16 58 Non-cash investing activities: Asset retirement obligation additions and revisions, net 131,732 30,741 31,060 (1) Amounts for 2023 and 2022 represent estimated quarterly payments for 2023 and 2022 federal and state income taxes based on an estimate of taxable income for each respective year. |
Net Property and Equipment (Tab
Net Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Property, Plant and Equipment, Net [Abstract] | |
Schedule of Net Property and Equipment | Net property and equipment includes the following at December 31, 2023 and 2022. December 31, In thousands 2023 2022 Proved crude oil and natural gas properties $ 37,400,304 $ 34,741,054 Unproved crude oil and natural gas properties 1,775,662 1,513,627 Service properties, equipment and other 1,014,093 549,528 Total property and equipment 40,190,059 36,804,209 Accumulated depreciation, depletion and amortization ( 20,403,170 ) ( 18,332,295 ) Net property and equipment $ 19,786,889 $ 18,471,914 |
Accrued Liabilities and Other (
Accrued Liabilities and Other (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Accrued Liabilities and Other Liabilities [Abstract] | |
Schedule of Accrued Liabilities and Other | Accrued liabilities and other includes the following at December 31, 2023 and 2022: December 31, In thousands 2023 2022 Prepaid advances from joint interest owners $ 36,923 $ 15,575 Accrued compensation 88,644 81,646 Accrued production taxes, ad valorem taxes and other non-income taxes 133,456 145,436 Accrued interest 79,640 83,724 Current portion of asset retirement obligations 9,971 3,935 Other 5,903 13,461 Accrued liabilities and other $ 354,537 $ 343,777 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Derivative [Line Items] | |
Summary of Outstanding Contracts with Respect to Natural Gas | At December 31, 2023 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 Swaps Floor Ceiling January 2024 - December 2024 Swaps - Henry Hub 618,000 MMBtus/day $ 3.44 Collars - Henry Hub 50,000 MMBtus/day $ 3.12 $ 4.09 Swaps - WAHA 42,000 MMBtus/day $ 3.08 January 2025 - December 2025 Swaps - Henry Hub 575,000 MMBtus/day $ 3.93 January 2026 - December 2026 Swaps - Henry Hub 635,000 MMBtus/day $ 4.11 January 2027 - December 2027 Swaps - Henry Hub 123,000 MMBtus/day $ 4.01 Crude oil derivatives Weighted Average Period and Type of Contract Average Volumes Hedged Roll Swaps Fixed Swaps January 2024 - December 2024 Fixed Swaps - WTI 76,000 Bbls/day $ 76.84 January 2024 - December 2024 Roll Swaps - NYMEX 36,000 Bbls/day $ 0.71 |
Realized and Unrealized Gains and Losses on Derivative Instruments | Year ended December 31, In thousands 2023 2022 2021 Cash received (paid) on derivatives: Crude oil fixed price swaps $ 17,989 $ — $ ( 44,463 ) Crude oil collars — — ( 9,365 ) Crude oil NYMEX roll swaps 3,519 ( 9,234 ) ( 163 ) Natural gas basis swaps 4,818 9,674 — Natural gas WAHA swaps 19,435 ( 16,350 ) — Natural gas fixed price swaps 178,529 ( 353,326 ) ( 84,141 ) Natural gas collars 29,139 ( 66,596 ) ( 11,546 ) Natural gas three-way collars 3,741 ( 22,287 ) — Cash received (paid) on derivatives, net 257,170 ( 458,119 ) ( 149,678 ) Non-cash gain (loss) on derivatives: Crude oil collars — — 227 Crude oil fixed price swaps 134,548 11,696 — Crude oil NYMEX roll swaps 4,051 1,879 957 Natural gas basis swaps ( 8,910 ) 9,088 ( 177 ) Natural gas WAHA swaps 2,138 19,386 — Natural gas fixed price swaps 513,129 ( 219,388 ) 25,565 Natural gas collars 42,240 ( 34,303 ) ( 7,690 ) Natural gas three-way collars ( 598 ) ( 1,334 ) 1,932 Non-cash gain (loss) on derivatives, net 686,598 ( 212,976 ) 20,814 Gain (loss) on derivative instruments, net $ 943,768 $ ( 671,095 ) $ ( 128,864 ) |
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, 2023 and 2022, all at fair value. December 31, In thousands 2023 2022 Commodity derivative assets: Gross amounts of recognized assets $ 510,375 $ 50,559 Gross amounts offset on balance sheet ( 1,862 ) ( 7,731 ) Net amounts of assets on balance sheet 508,513 42,828 Commodity derivative liabilities: Gross amounts of recognized liabilities ( 2,448 ) ( 229,230 ) Gross amounts offset on balance sheet 1,862 7,731 Net amounts of liabilities on balance sheet $ ( 586 ) $ ( 221,499 ) |
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 2023 2022 Derivative assets $ 353,261 $ 39,280 Derivative assets, noncurrent 155,252 3,548 Net amounts of assets on balance sheet 508,513 42,828 Derivative liabilities — ( 88,136 ) Derivative liabilities, noncurrent ( 586 ) ( 133,363 ) Net amounts of liabilities on balance sheet ( 586 ) ( 221,499 ) Total derivative assets (liabilities), net $ 507,927 $ ( 178,671 ) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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, 2023 and 2022. Fair value measurements at December 31, 2023 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Crude oil fixed price swaps $ — $ 146,243 $ — $ 146,243 Crude oil NYMEX roll swaps — 6,888 — 6,888 Natural gas WAHA swaps — 21,523 — 21,523 Natural gas fixed price swaps — 321,350 — 321,350 Natural gas collars — 11,923 — 11,923 Total $ — $ 507,927 $ — $ 507,927 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 ) |
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. Year ended December 31, In thousands 2023 2022 2021 Proved property impairments $ 15,455 $ 17,520 $ — Unproved property impairments 51,343 52,897 38,370 Total $ 66,798 $ 70,417 $ 38,370 |
Fair Values of Financial Instruments not Recorded at Fair Value | The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the consolidated financial statements. See Note 8. Debt for discussion of the changes in the Company’s outstanding debt in 2023 and 2022. December 31, 2023 December 31, 2022 In thousands Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Debt: Credit facility $ 210,000 $ 210,000 $ 1,160,000 $ 1,160,000 Term Loan 748,092 748,092 747,073 747,073 Notes payable 17,642 16,300 20,041 18,300 4.5 % Senior Notes due 2023 — — 635,648 633,600 3.8 % Senior Notes due 2024 892,610 886,400 891,404 867,400 2.268 % Senior Notes due 2026 795,541 736,400 794,062 693,100 4.375 % Senior Notes due 2028 994,327 968,000 993,076 917,200 5.75 % Senior Notes due 2031 1,485,460 1,490,900 1,483,843 1,412,300 2.875 % Senior Notes due 2032 792,977 647,100 792,238 600,900 4.9 % Senior Notes due 2044 692,463 556,400 692,255 527,900 Total debt $ 6,629,112 $ 6,259,592 $ 8,209,640 $ 7,577,773 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | debt, net of unamortized discounts, premiums, and debt issuance costs totaling $ 41.7 million and $ 49.6 million at December 31, 2023 and 2022, respectively, consists of the following. December 31, In thousands 2023 2022 Credit facility $ 210,000 $ 1,160,000 Term loan 748,092 747,073 Notes payable 17,642 20,041 4.5 % Senior Notes due 2023 — 635,648 3.8 % Senior Notes due 2024 (1) 892,610 891,404 2.268 % Senior Notes due 2026 795,541 794,062 4.375 % Senior Notes due 2028 994,327 993,076 5.75 % Senior Notes due 2031 1,485,460 1,483,843 2.875 % Senior Notes due 2032 792,977 792,238 4.9 % Senior Notes due 2044 692,463 692,255 Total debt 6,629,112 8,209,640 Less: Current portion of long-term debt 895,105 638,058 Long-term debt, net of current portion $ 5,734,007 $ 7,571,582 (1) The Company’s 2024 Notes, which have a face value of $ 893.1 million at December 31, 2023 , are scheduled to mature on June 1, 2024 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, 2023 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, 2023. 2024 Notes 2026 Notes 2028 Notes 2031 Notes 2032 Notes 2044 Notes Face value (in thousands) $ 893,126 $ 800,000 $ 1,000,000 $ 1,500,000 $ 800,000 $ 700,000 Maturity date June 1, 2024 November 15, 2026 January 15, 2028 January 15, 2031 April 1, 2032 June 1, 2044 Interest payment dates 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) 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, 2023 | |
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, 2023 2022 2021 In thousands Crude Oil Natural Gas and NGLs Total Crude Oil Natural Gas and NGLs Total Crude Oil Natural Gas and NGLs Total Bakken $ 3,777,412 $ 380,359 $ 4,157,771 $ 3,899,749 $ 1,051,870 $ 4,951,619 $ 2,786,320 $ 562,695 $ 3,349,015 Anadarko Basin 999,009 687,687 1,686,696 1,109,405 1,839,473 2,948,878 874,752 1,264,069 2,138,821 Powder River Basin 410,963 43,968 454,931 557,943 125,065 683,008 101,705 13,110 114,815 Permian Basin 1,135,421 74,133 1,209,554 1,122,290 151,217 1,273,507 24,857 4,499 29,356 All other 175,118 193 175,311 216,616 1,047 217,663 161,660 74 161,734 Crude oil, natural gas, and natural gas liquids sales $ 6,497,923 $ 1,186,340 $ 7,684,263 $ 6,906,003 $ 3,168,672 $ 10,074,675 $ 3,949,294 $ 1,844,447 $ 5,793,741 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Provision for Income Taxes | The items comprising the Company’s provision for income taxes are as follows for the periods presented: Year ended December 31, In thousands 2023 2022 2021 Current income tax provision: United States federal $ 461,487 $ 538,704 $ — Various states 37,173 83,671 — Total current income tax provision 498,660 622,375 — Deferred income tax provision: United States federal 318,484 374,802 467,051 Various states 10,486 23,627 52,679 Total deferred income tax provision 328,970 398,429 519,730 Provision for income taxes $ 827,630 $ 1,020,804 $ 519,730 Effective tax rate 21.1 % 20.1 % 23.8 % |
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/incentive 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 2023 2022 2021 Income before income taxes $ 3,928,947 $ 5,068,413 $ 2,186,138 U.S. federal statutory tax rate 21.0 % 21.0 % 21.0 % Expected income tax provision based on U.S. federal statutory tax rate 825,079 1,064,367 459,089 Items impacting the effective tax rate: State and local income taxes, net of federal benefit 98,257 126,932 77,979 Tax (benefit) deficiency from stock-based compensation — ( 5,282 ) 5,869 Change in valuation allowance — — ( 14,474 ) Tax credits for increasing research activities ( 67,039 ) ( 151,913 ) — Other, net ( 28,667 ) ( 13,300 ) ( 8,733 ) Provision for income taxes $ 827,630 $ 1,020,804 $ 519,730 Effective tax rate 21.1 % 20.1 % 23.8 % |
Components of Deferred Tax Assets and Liabilities | The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2023 and 2022 are reflected in the table below. December 31, In thousands 2023 2022 Deferred tax assets United States net operating loss carryforwards $ 56,377 $ 63,128 Incentive/equity compensation 40,929 34,987 Net deferred hedge losses — 42,898 Other 28,080 31,324 Total deferred tax assets 125,386 172,337 Valuation allowance — — Total deferred tax assets, net of valuation allowance 125,386 172,337 Deferred tax liabilities Property and equipment ( 2,870,259 ) ( 2,708,641 ) Net deferred hedge gains ( 120,662 ) — Other ( 1,748 ) ( 2,008 ) Total deferred tax liabilities ( 2,992,669 ) ( 2,710,649 ) Deferred income tax liabilities, net $ ( 2,867,283 ) $ ( 2,538,312 ) |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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 2023 2022 Surface use agreements $ 17,263 $ 18,136 Field equipment 19,713 5,224 Other 618 781 Total $ 37,594 $ 24,141 |
Summary of Maturities of Operating Leases | Minimum future commitments by year for the Company’s operating leases as of December 31, 2023 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 2024 $ 19,603 2025 4,571 2026 1,848 2027 1,827 2028 1,765 Thereafter 16,586 Total operating lease liabilities, at undiscounted value $ 46,200 Less: Imputed interest ( 8,606 ) Total operating lease liabilities, at discounted present value $ 37,594 Less: Current portion of operating lease liabilities ( 18,112 ) Operating lease liabilities, noncurrent $ 19,482 |
Summary of Lease Cost | Year ended December 31, In thousands, except weighted average data 2023 2022 2021 Lease costs: Operating lease costs $ 13,121 $ 3,484 $ 6,653 Variable lease costs 896 650 3,271 Short-term lease costs 168,680 124,535 77,551 Total lease costs $ 182,697 $ 128,669 $ 87,475 Other information: Right-of-use assets obtained in exchange for new operating lease liabilities $ 24,949 $ 19,944 $ 10,481 Operating cash flows from operating leases included in lease liabilities 13,166 4,370 1,731 Weighted average remaining lease term as of December 31 (in years) 6.9 12.0 14.4 Weighted average discount rate as of December 31 4.7 % 4.8 % 5.0 % |
Incentive Compensation (Tables)
Incentive Compensation (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Restricted stock [Member] | |
Summary of Changes in Non Vested Shares of Restricted Stock Outstanding Prior to Take-Private Transaction | A summary of changes in non-vested restricted shares outstanding prior to the take-private transaction from December 31, 2020 to December 31, 2022 is presented below. Number of Weighted 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, 2023 | |
Shareholders' Equity Attributable to Continental Resources [Abstract] | |
Share Repurchase Program | Number of Aggregate cost (in thousands) 2021 Share Repurchases 3,198,571 $ 123,924 2022 Share Repurchases 1,842,422 99,855 Total 5,040,993 $ 223,779 |
Capitalized Exploratory Well _2
Capitalized Exploratory Well Costs (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
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 2023 2022 2021 Balance at January 1 $ 84,822 $ 37,673 $ 32,737 Additions to capitalized exploratory well costs pending determination of proved reserves 345,434 286,059 122,068 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves ( 270,490 ) ( 229,348 ) ( 117,131 ) Capitalized exploratory well costs charged to expense ( 32 ) ( 9,562 ) ( 1 ) Balance at December 31 $ 159,734 $ 84,822 $ 37,673 Number of gross wells 34 36 17 |
Supplemental Crude Oil and Na_2
Supplemental Crude Oil and Natural Gas Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Supplemental Crude Oil and Natural Gas Information [Abstract] | |
Schedule of proved developed and undeveloped oil and gas reserve quantities | The following 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, 2023, 2022, and 2021 . December 31, 2023 2022 2021 Proved Developed Reserves Crude oil (MBbl) 401,851 454,299 424,153 Natural Gas (MMcf) 3,221,566 3,486,774 2,901,147 Total (MBoe) 938,779 1,035,428 907,678 Proved Undeveloped Reserves Crude oil (MBbl) 512,183 435,240 369,377 Natural Gas (MMcf) 2,376,765 2,358,578 2,209,532 Total (MBoe) 908,310 828,336 737,632 Total Proved Reserves Crude oil (MBbl) 914,034 889,539 793,530 Natural Gas (MMcf) 5,598,331 5,845,352 5,110,679 Total (MBoe) 1,847,089 1,863,764 1,645,310 |
Organization and Summary of S_4
Organization and Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Thousands, shares in Millions | 12 Months Ended | |||
Nov. 22, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Organization And Summary Of Significant Accounting Policies [Line Items] | ||||
Outstanding shares funded by credit facility borrowings | $ 4,792,000 | $ 3,886,000 | $ 1,663,000 | |
Number of rollover shares | 5.3 | |||
Transaction costs | 13,900 | |||
Allowance for credit losses | 3,200 | $ 5,500 | ||
Unamortized Debt Issuance Expense | 39,400 | 46,800 | ||
Cash deposits in excess of federally insured amounts | 24,700 | |||
Net asset retirement costs | 204,200 | 96,500 | ||
Capitalized debt issue costs, relating to long-term debt | 46,500 | 56,300 | ||
Accumulated amortization, relating to capitalized debt issue costs | 37,300 | 46,300 | ||
Amortization expense related to capitalized debt issuance costs | $ 10,000 | 9,300 | $ 7,200 | |
Concentration Risk, Customer | 10 | |||
Revolving Credit Facility | ||||
Organization And Summary Of Significant Accounting Policies [Line Items] | ||||
Unamortized Debt Issuance Expense | $ 7,100 | 9,400 | ||
Omega Acquisition, Inc. [Member] | ||||
Organization And Summary Of Significant Accounting Policies [Line Items] | ||||
Merger agreement date | Nov. 22, 2022 | |||
Name of the acquired entity | Omega Acquisition, Inc, | |||
Number of common stock purchased | 58.1 | |||
Total cash consideration | $ 4,310,000 | |||
Outstanding shares funded by cash | 2,200,000 | |||
Outstanding shares funded by credit facility borrowings | 1,300,000 | |||
Execution of three-year term loan | $ 750,000 | |||
Transaction costs | $ 32,000 |
Organization and Summary of S_5
Organization and Summary of Significant Accounting Policies - Components of Inventories (Detail) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Tubular goods and equipment | $ 65,205 | $ 38,636 |
Crude oil | 125,557 | 130,192 |
Natural gas | 0 | 4,436 |
Total | $ 190,762 | $ 173,264 |
Organization and Summary of S_6
Organization and Summary of Significant Accounting Policies - Schedule of Estimated Useful Lives of Service Property and Equipment (Detail) | Dec. 31, 2023 |
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, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Asset retirement obligations at January 1 | $ 261,087 | $ 219,824 | $ 179,676 | |
Accretion expense | 14,818 | 12,857 | 11,125 | |
Revisions | [1] | 112,803 | (6,672) | (1,291) |
Plus: Additions for new assets | 18,929 | 37,413 | 32,351 | |
Less: Plugging costs and sold assets | (5,709) | (2,335) | (2,037) | |
Total asset retirement obligations at December 31 | 401,928 | 261,087 | 219,824 | |
Less: Current portion of asset retirement obligations at December 31 | [2] | 9,971 | 3,935 | 4,123 |
Non-current portion of asset retirement obligations at December 31 | $ 391,957 | $ 257,152 | $ 215,701 | |
[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, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||
Income (numerator): | ||||
Net income attributable to Continental Resources | $ 3,095,827 | $ 4,024,558 | $ 1,660,968 | |
Weighted average shares - basic | 299,610,000 | 351,392,000 | 360,434,000 | |
Non-vested restricted stock and restricted stock units | [1] | 0 | 0 | 4,019,000 |
Weighted average shares - diluted | 299,610,000 | 351,392,000 | 364,453,000 | |
Net income per share: | ||||
Basic (in dollars per share) | $ 10.33 | $ 11.45 | $ 4.61 | |
Diluted (in dollars per share) | $ 10.33 | $ 11.45 | $ 4.56 | |
Weighted Average Number Diluted Shares Outstanding Adjustment | 0 | 0 | ||
[1] For the years ended December 31, 2023 and 2022, the Company’s outstanding long-term incentive awards 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 awards is presented for the years ended December 31, 2023 and 2022. |
Property Acquisitions and Dis_2
Property Acquisitions and Dispositions - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 12 Months Ended | |||
Dec. 31, 2021 | Dec. 31, 2021 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Asset Acquisition [Line Items] | |||||
Costs Incurred, Acquisition of Oil and Gas Properties | $ 681 | $ 714 | |||
Cash proceeds for sale of oil and gas properties | 390 | ||||
Pre tax net losses on transaction | 51 | ||||
Asset acquisition recognition of proved crude oil and natural gas properties | $ 2,400 | 161 | 422 | ||
Asset acquisition recognition of unproved crude oil and natural gas properties | $ 520 | $ 292 | |||
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual | $ 29.4 | ||||
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual | $ 14.1 | ||||
Business Acquisition Pro forma net income basic per share, actual contribution of acquired assets | $ 0.04 | ||||
Business Acquisition Pro forma net income diluted per share, actual contribution of acquired assets | $ 0.04 | ||||
Business Acquisition, Transaction Costs | $ 13.9 | 13.9 | $ 13.9 | ||
Powder River Basin | |||||
Asset Acquisition [Line Items] | |||||
Costs Incurred, Acquisition of Oil and Gas Properties | 453 | ||||
Asset acquisition recognition of proved crude oil and natural gas properties | 210 | ||||
Asset acquisition recognition of unproved crude oil and natural gas properties | $ 243 | ||||
Permian Basin | |||||
Asset Acquisition [Line Items] | |||||
Asset acquisition recognition of unproved crude oil and natural gas properties | 700 | ||||
Payments to Acquire Businesses, Gross | $ 3,060 |
Property Acquisitions and Dis_3
Property Acquisitions and Dispositions - Business Acquisition, Pro Forma Information (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2021 USD ($) | |
Business Acquisition, Pro Forma Information [Abstract] | |
Pro forma combined total revenues | $ 6,657 |
Pro forma combined net income attributable to Continental | $ 2,097 |
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, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||
Supplemental Cash Flow Elements [Abstract] | ||||
Cash paid for interest | $ 387,686 | $ 279,571 | $ 214,727 | |
Cash paid for income taxes | [1] | 566,253 | 470,147 | 3 |
Cash received for income tax refunds | 2 | 16 | 58 | |
Non-cash investing activities: | ||||
Asset retirement obligation additions and revisions, net | $ 131,732 | $ 30,741 | $ 31,060 | |
[1] Amounts for 2023 and 2022 represent estimated quarterly payments for 2023 and 2022 federal and state income taxes based on an estimate of taxable income for each respective year. |
Supplemental Cash Flow Inform_4
Supplemental Cash Flow Information - Additional Information (Detail) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Supplemental Cash Flow Elements [Abstract] | ||
Accrued capital expenditures | $ 367.2 | $ 344.9 |
Net Property and Equipment - Sc
Net Property and Equipment - Schedule of Net Property and Equipment (Detail) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Property, Plant and Equipment, Net [Abstract] | ||
Proved crude oil and natural gas properties | $ 37,400,304 | $ 34,741,054 |
Unproved crude oil and natural gas properties | 1,775,662 | 1,513,627 |
Service properties, equipment and other | 1,014,093 | 549,528 |
Total property and equipment | 40,190,059 | 36,804,209 |
Accumulated depreciation, depletion and amortization | (20,403,170) | (18,332,295) |
Net property and equipment | $ 19,786,889 | $ 18,471,914 |
Accrued Liabilities and Other -
Accrued Liabilities and Other - Schedule of Accrued Liabilities and Other (Detail) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Accrued Liabilities and Other Liabilities [Abstract] | ||||
Prepaid advances from joint interest owners | $ 36,923 | $ 15,575 | ||
Accrued compensation | 88,644 | 81,646 | ||
Accrued production taxes, ad valorem taxes and other non-income taxes | 133,456 | 145,436 | ||
Accrued interest | 79,640 | 83,724 | ||
Current portion of asset retirement obligations | [1] | 9,971 | 3,935 | $ 4,123 |
Other | 5,903 | 13,461 | ||
Accrued liabilities and other | $ 354,537 | $ 343,777 | ||
[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, 2023 MMBTU $ / MMBTU $ / bbl bbl | |
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 | 618,000 |
Swaps Weighted Average Price | 3.44 |
Jan 24 to Dec 24 Swaps WAHA | Natural Gas [Member] | |
Derivative [Line Items] | |
Natural Gas Production Derivative Volume | MMBTU | 42,000 |
Swaps Weighted Average Price | 3.08 |
Jan 24 to Dec 24 WTI Fixed Swaps | Crude Oil [Member] | |
Derivative [Line Items] | |
Swaps Weighted Average Price | $ / bbl | 76.84 |
Crude oil production volume hedged | bbl | 76,000 |
Jan 24 To Dec 24 NYMEX Roll Swaps | Crude Oil [Member] | |
Derivative [Line Items] | |
Swaps Weighted Average Price | $ / bbl | 0.71 |
Crude oil production volume hedged | bbl | 36,000 |
Jan25 to Dec 25 Swaps | Natural Gas [Member] | |
Derivative [Line Items] | |
Natural Gas Production Derivative Volume | MMBTU | 575,000 |
Swaps Weighted Average Price | 3.93 |
Jan 26 to Dec 26 Swaps | Natural Gas [Member] | |
Derivative [Line Items] | |
Natural Gas Production Derivative Volume | MMBTU | 635,000 |
Swaps Weighted Average Price | 4.11 |
Jan 27 to Dec 27 Swaps | Natural Gas [Member] | |
Derivative [Line Items] | |
Natural Gas Production Derivative Volume | MMBTU | 123,000 |
Swaps Weighted Average Price | 4.01 |
Derivative Instruments - Realiz
Derivative Instruments - Realized and Unrealized Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Non-cash gain (loss) on derivatives: | |||
Non-cash gain (loss) on derivatives, net | $ 686,598 | $ (212,976) | $ 20,814 |
Gain (loss) on derivative instruments, net | 943,768 | (671,095) | (128,864) |
Swap [Member] | Crude Oil [Member] | |||
Cash received (paid) on derivatives: | |||
Cash received (paid) on derivatives, net | 17,989 | 0 | (44,463) |
Non-cash gain (loss) on derivatives: | |||
Non-cash gain (loss) on derivatives, net | 134,548 | 11,696 | 0 |
Swap [Member] | Natural Gas [Member] | |||
Cash received (paid) on derivatives: | |||
Cash received (paid) on derivatives, net | 178,529 | (353,326) | (84,141) |
Non-cash gain (loss) on derivatives: | |||
Non-cash gain (loss) on derivatives, net | 513,129 | (219,388) | 25,565 |
Collars [Member] | Crude Oil [Member] | |||
Cash received (paid) on derivatives: | |||
Cash received (paid) on derivatives, net | 0 | 0 | (9,365) |
Non-cash gain (loss) on derivatives: | |||
Non-cash gain (loss) on derivatives, net | 0 | 0 | 227 |
Collars [Member] | Natural Gas [Member] | |||
Cash received (paid) on derivatives: | |||
Cash received (paid) on derivatives, net | 29,139 | (66,596) | (11,546) |
Non-cash gain (loss) on derivatives: | |||
Non-cash gain (loss) on derivatives, net | 42,240 | (34,303) | (7,690) |
NYMEX roll swaps | Crude Oil [Member] | |||
Cash received (paid) on derivatives: | |||
Cash received (paid) on derivatives, net | 3,519 | (9,234) | (163) |
Non-cash gain (loss) on derivatives: | |||
Non-cash gain (loss) on derivatives, net | 4,051 | 1,879 | 957 |
Basis swaps | Natural Gas [Member] | |||
Cash received (paid) on derivatives: | |||
Cash received (paid) on derivatives, net | 4,818 | 9,674 | 0 |
Non-cash gain (loss) on derivatives: | |||
Non-cash gain (loss) on derivatives, net | (8,910) | 9,088 | (177) |
WAHA swaps | Natural Gas [Member] | |||
Cash received (paid) on derivatives: | |||
Cash received (paid) on derivatives, net | 19,435 | (16,350) | 0 |
Non-cash gain (loss) on derivatives: | |||
Non-cash gain (loss) on derivatives, net | 2,138 | 19,386 | 0 |
Three-way collars | Natural Gas [Member] | |||
Cash received (paid) on derivatives: | |||
Cash received (paid) on derivatives, net | 3,741 | (22,287) | 0 |
Non-cash gain (loss) on derivatives: | |||
Non-cash gain (loss) on derivatives, net | (598) | (1,334) | 1,932 |
Crude Oil and Natural Gas [Member] | |||
Cash received (paid) on derivatives: | |||
Cash received (paid) on derivatives, net | 257,170 | (458,119) | (149,678) |
Non-cash gain (loss) on derivatives: | |||
Non-cash gain (loss) on derivatives, net | 686,598 | (212,976) | 20,814 |
Gain (loss) on derivative instruments, net | $ 943,768 | $ (671,095) | $ (128,864) |
Derivative Instruments - Gross
Derivative Instruments - Gross Amounts of Recognized Derivative Assets and Liabilities (Detail) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Derivative [Line Items] | ||
Gross amounts of recognized assets | $ 510,375 | $ 50,559 |
Gross amounts offset on balance sheet | (1,862) | (7,731) |
Net amounts of assets on balance sheet | 508,513 | 42,828 |
Gross amounts of recognized liabilities | (2,448) | (229,230) |
Gross amounts offset on balance sheet | 1,862 | 7,731 |
Net amounts of liabilities on balance sheet | $ (586) | $ (221,499) |
Derivative Instruments - Reconc
Derivative Instruments - Reconciles Net Amounts Derivative Assets and Liabilities (Detail) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Derivative assets | $ 353,261 | $ 39,280 |
Noncurrent derivative assets | 155,252 | 3,548 |
Net amounts of assets on balance sheet | 508,513 | 42,828 |
Derivative liabilities | 0 | (88,136) |
Derivative liabilities, noncurrent | (586) | (133,363) |
Net amounts of liabilities on balance sheet | (586) | (221,499) |
Total derivative assets (liabilities), net | $ 507,927 | $ (178,671) |
Fair Value Measurements - Valua
Fair Value Measurements - Valuation of Financial Instruments by Pricing Levels (Detail) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | $ 507,927 | $ (178,671) |
Crude Oil Fixed Price Swaps [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 146,243 | 11,696 |
Crude oil NYMEX roll swaps | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 6,888 | 2,836 |
Natural Gas Basis Swaps [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 8,910 | |
Natural Gas WAHA Swaps [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 21,523 | 19,386 |
Natural Gas Fixed Price Swaps [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 321,350 | (191,779) |
Collars [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 11,923 | (30,318) |
Natural Gas Three-way Collars [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 598 | |
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 | 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) | 507,927 | (178,671) |
Fair Value, Inputs, Level 2 [Member] | Crude Oil Fixed Price Swaps [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 146,243 | 11,696 |
Fair Value, Inputs, Level 2 [Member] | Crude oil NYMEX roll swaps | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 6,888 | 2,836 |
Fair Value, Inputs, Level 2 [Member] | Natural Gas Basis Swaps [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 8,910 | |
Fair Value, Inputs, Level 2 [Member] | Natural Gas WAHA Swaps [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 21,523 | 19,386 |
Fair Value, Inputs, Level 2 [Member] | Natural Gas Fixed Price Swaps [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 321,350 | (191,779) |
Fair Value, Inputs, Level 2 [Member] | Collars [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 11,923 | (30,318) |
Fair Value, Inputs, Level 2 [Member] | Natural Gas Three-way Collars [Member] | ||
Derivative assets (liabilities): | ||
Derivative assets (liabilities) | 598 | |
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 | 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, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
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 | $ 15,455 | $ 17,520 | $ 0 |
Fair Value Measurements - Prope
Fair Value Measurements - Property Impairments (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Proved property impairments | $ 15,455 | $ 17,520 | $ 0 |
Unproved property impairments | 51,343 | 52,897 | 38,370 |
Total | $ 66,798 | $ 70,417 | $ 38,370 |
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, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||
Term Loan | ||||
Fair Value Measurements [Line Items] | ||||
Debt instrument, stated interest rate | 6.98% | |||
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% | |||
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 | $ 210,000 | $ 1,160,000 | ||
Notes payable | 17,642 | 20,041 | ||
Total debt | 6,629,112 | 8,209,640 | ||
Carrying Amount | Term Loan | ||||
Fair Value Measurements [Line Items] | ||||
Term Loan | 748,092 | 747,073 | ||
Carrying Amount | 4.5% Senior Notes due 2023 | ||||
Fair Value Measurements [Line Items] | ||||
Senior notes | 635,648 | |||
Carrying Amount | 3.8% Senior Notes due 2024 | ||||
Fair Value Measurements [Line Items] | ||||
Senior notes | [1] | 892,610 | 891,404 | |
Carrying Amount | 2.268% Senior Notes due 2026 | ||||
Fair Value Measurements [Line Items] | ||||
Senior notes | 795,541 | 794,062 | ||
Carrying Amount | 4.375% Senior Notes due 2028 | ||||
Fair Value Measurements [Line Items] | ||||
Senior notes | 994,327 | 993,076 | ||
Carrying Amount | 5.75% Senior Notes due 2031 | ||||
Fair Value Measurements [Line Items] | ||||
Senior notes | 1,485,460 | 1,483,843 | ||
Carrying Amount | 2.875% Senior Notes due 2032 | ||||
Fair Value Measurements [Line Items] | ||||
Senior notes | 792,977 | 792,238 | ||
Carrying Amount | 4.9% Senior Notes due 2044 | ||||
Fair Value Measurements [Line Items] | ||||
Senior notes | 692,463 | 692,255 | ||
Estimated Fair Value | ||||
Fair Value Measurements [Line Items] | ||||
Credit facility | 210,000 | 1,160,000 | ||
Notes payable | 16,300 | 18,300 | ||
Total debt | 6,259,592 | 7,577,773 | ||
Estimated Fair Value | Term Loan | ||||
Fair Value Measurements [Line Items] | ||||
Term Loan | 748,092 | 747,073 | ||
Estimated Fair Value | 4.5% Senior Notes due 2023 | ||||
Fair Value Measurements [Line Items] | ||||
Senior notes | 633,600 | |||
Estimated Fair Value | 3.8% Senior Notes due 2024 | ||||
Fair Value Measurements [Line Items] | ||||
Senior notes | 886,400 | 867,400 | ||
Estimated Fair Value | 2.268% Senior Notes due 2026 | ||||
Fair Value Measurements [Line Items] | ||||
Senior notes | 736,400 | 693,100 | ||
Estimated Fair Value | 4.375% Senior Notes due 2028 | ||||
Fair Value Measurements [Line Items] | ||||
Senior notes | 968,000 | 917,200 | ||
Estimated Fair Value | 5.75% Senior Notes due 2031 | ||||
Fair Value Measurements [Line Items] | ||||
Senior notes | 1,490,900 | 1,412,300 | ||
Estimated Fair Value | 2.875% Senior Notes due 2032 | ||||
Fair Value Measurements [Line Items] | ||||
Senior notes | 647,100 | 600,900 | ||
Estimated Fair Value | 4.9% Senior Notes due 2044 | ||||
Fair Value Measurements [Line Items] | ||||
Senior notes | $ 556,400 | $ 527,900 | ||
[1] The Company’s 2024 Notes, which have a face value of $ 893.1 million at December 31, 2023 , are scheduled to mature on June 1, 2024 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, 2023 along with the current portion of the Company's notes payable. |
Debt - Additional Information (
Debt - Additional Information (Detail) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | ||||||
Apr. 30, 2023 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Nov. 30, 2022 | Jun. 30, 2020 | ||
Debt Instrument [Line Items] | ||||||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | $ 41,700 | $ 49,600 | ||||||
Proceeds from sale of assets | 390,034 | 5,740 | $ 8,041 | |||||
Loss on extinguishment of debt | 0 | 403 | 290 | |||||
Aggregate amount of lender commitments on credit facility | $ 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 | 0 | 1,587,776 | |||||
Repayments of Lines of Credit | 5,742,000 | 3,226,000 | 1,323,000 | |||||
Current portion of long-term debt | $ 895,105 | 638,058 | ||||||
Senior Notes due 2022 | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt Instrument, Repurchased Face Amount | 630,800 | |||||||
Loss on extinguishment of debt | (400) | (300) | ||||||
Note Payable | ||||||||
Debt Instrument [Line Items] | ||||||||
Notes Payable | $ 26,000 | |||||||
Debt instrument, stated interest rate | 3.50% | |||||||
Current portion of long-term debt | $ 2,500 | |||||||
Debt Instrument, Term | 10 years | |||||||
Term Loan | ||||||||
Debt Instrument [Line Items] | ||||||||
Term loan | $ 750,000 | |||||||
Debt instrument, stated interest rate | 6.98% | |||||||
Senior Notes Due 2023 | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt Instrument, Repurchased Face Amount | $ 636,000 | 13,600 | ||||||
Debt Instrument, Redemption Price, Percentage | 100% | |||||||
TotalRedemptionAmount | $ 650,300 | |||||||
Debt Instrument, Repurchase Amount | 13,900 | |||||||
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] | ||||||||
Debt instrument, stated interest rate | 5.75% | |||||||
Senior Notes | ||||||||
Debt Instrument [Line Items] | ||||||||
Proceeds from issuance of Senior Notes | $ 1,590,000 | |||||||
Revolving Credit Facility | ||||||||
Debt Instrument [Line Items] | ||||||||
Line of Credit Facility, Remaining Borrowing Capacity | $ 2,040,000 | |||||||
Carrying Amount | ||||||||
Debt Instrument [Line Items] | ||||||||
Term loan | 748,092 | 747,073 | ||||||
Line of credit facility, amount outstanding | $ 210,000 | 1,160,000 | ||||||
Debt, Weighted Average Interest Rate | 6.95% | |||||||
Notes Payable | $ 17,642 | 20,041 | ||||||
Carrying Amount | 4.5% Senior Notes due 2023 | ||||||||
Debt Instrument [Line Items] | ||||||||
Senior notes | 635,648 | |||||||
Carrying Amount | 3.8% Senior Notes due 2024 | ||||||||
Debt Instrument [Line Items] | ||||||||
Senior notes | [1] | 892,610 | 891,404 | |||||
Carrying Amount | 4.9% Senior Notes due 2044 | ||||||||
Debt Instrument [Line Items] | ||||||||
Senior notes | 692,463 | 692,255 | ||||||
Carrying Amount | 2.268% Senior Notes due 2026 | ||||||||
Debt Instrument [Line Items] | ||||||||
Senior notes | 795,541 | 794,062 | ||||||
Carrying Amount | 2.875% Senior Notes due 2032 | ||||||||
Debt Instrument [Line Items] | ||||||||
Senior notes | 792,977 | 792,238 | ||||||
Carrying Amount | 5.75% Senior Notes due 2031 | ||||||||
Debt Instrument [Line Items] | ||||||||
Senior notes | $ 1,485,460 | $ 1,483,843 | ||||||
[1] The Company’s 2024 Notes, which have a face value of $ 893.1 million at December 31, 2023 , are scheduled to mature on June 1, 2024 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, 2023 along with the current portion of the Company's notes payable. |
Debt - Long-Term Debt (Detail)
Debt - Long-Term Debt (Detail) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||
Debt Instrument [Line Items] | ||||
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net | $ 41,700 | $ 49,600 | ||
Less: Current portion of long-term debt | 895,105 | 638,058 | ||
Long-term debt, net of current portion | 5,734,007 | 7,571,582 | ||
Gain (loss) on extinguishment of debt | $ 0 | (403) | $ (290) | |
4.5% Senior Notes due 2023 | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, stated interest rate | 4.50% | |||
Debt Instrument, Maturity Date, Description | 2023 | |||
3.8% Senior Notes due 2024 | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, stated interest rate | 3.80% | |||
Debt Instrument, Maturity Date, Description | 2024 | |||
2.268% Senior Notes due 2026 | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, stated interest rate | 2.268% | |||
Debt Instrument, Maturity Date, Description | 2026 | |||
4.375% Senior Notes due 2028 | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, stated interest rate | 4.375% | |||
Debt Instrument, Maturity Date, Description | 2028 | |||
5.75% Senior Notes due 2031 | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, stated interest rate | 5.75% | |||
Debt Instrument, Maturity Date, Description | 2031 | |||
2.875% Senior Notes due 2032 | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, stated interest rate | 2.875% | |||
Debt Instrument, Maturity Date, Description | 2032 | |||
4.9% Senior Notes due 2044 | ||||
Debt Instrument [Line Items] | ||||
Debt instrument, stated interest rate | 4.90% | |||
Debt Instrument, Maturity Date, Description | 2044 | |||
Carrying Amount | ||||
Debt Instrument [Line Items] | ||||
Credit facility | $ 210,000 | 1,160,000 | ||
Term loan | 748,092 | 747,073 | ||
Notes payable | 17,642 | 20,041 | ||
Total debt | 6,629,112 | 8,209,640 | ||
Carrying Amount | 4.5% Senior Notes due 2023 | ||||
Debt Instrument [Line Items] | ||||
Senior notes | 0 | 635,648 | ||
Carrying Amount | 3.8% Senior Notes due 2024 | ||||
Debt Instrument [Line Items] | ||||
Senior notes | [1] | 892,610 | 891,404 | |
Carrying Amount | 2.268% Senior Notes due 2026 | ||||
Debt Instrument [Line Items] | ||||
Senior notes | 795,541 | 794,062 | ||
Carrying Amount | 4.375% Senior Notes due 2028 | ||||
Debt Instrument [Line Items] | ||||
Senior notes | 994,327 | 993,076 | ||
Carrying Amount | 5.75% Senior Notes due 2031 | ||||
Debt Instrument [Line Items] | ||||
Senior notes | 1,485,460 | 1,483,843 | ||
Carrying Amount | 2.875% Senior Notes due 2032 | ||||
Debt Instrument [Line Items] | ||||
Senior notes | 792,977 | 792,238 | ||
Carrying Amount | 4.9% Senior Notes due 2044 | ||||
Debt Instrument [Line Items] | ||||
Senior notes | $ 692,463 | $ 692,255 | ||
[1] The Company’s 2024 Notes, which have a face value of $ 893.1 million at December 31, 2023 , are scheduled to mature on June 1, 2024 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, 2023 along with the current portion of the Company's notes payable. |
Debt - Long-Term Debt (Parenthe
Debt - Long-Term Debt (Parenthetical) (Details) $ in Thousands | Dec. 31, 2023 USD ($) |
2024 Notes [Member] | |
Debt Instrument [Line Items] | |
Debt instrument, face amount | $ 893,126 |
Debt - Summary of Maturity Date
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, 2023 USD ($) | ||
2024 Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 893,126 | |
Debt instrument, maturity date | Jun. 01, 2024 | |
Interest payment dates | June 1, Dec 1 | |
Debt Instrument, Redemption Period, Start Date | Mar. 01, 2024 | [1] |
2026 Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 800,000 | |
Debt instrument, maturity date | Nov. 15, 2026 | |
Interest payment dates | May 15, Nov 15 | |
Debt Instrument, Redemption Period, Start Date | Nov. 15, 2023 | [1] |
2028 Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 1,000,000 | |
Debt instrument, 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 | |
Debt instrument, maturity date | Apr. 01, 2032 | |
Interest payment dates | April 1, Oct 1 | |
Debt Instrument, Redemption Period, Start Date | Jan. 01, 2032 | [1] |
2044 Notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 700,000 | |
Debt instrument, 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 | |
Debt instrument, 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, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disaggregation of Revenue [Line Items] | |||
Transportation expenses | $ 338,217 | $ 316,414 | $ 224,989 |
Natural Gas Sales | |||
Disaggregation of Revenue [Line Items] | |||
Transportation expenses | 54,000 | 62,400 | 39,900 |
Crude Oil Sales | |||
Disaggregation of Revenue [Line Items] | |||
Transportation expenses | $ 284,200 | $ 254,000 | $ 185,100 |
Revenues - Disaggregation of Re
Revenues - Disaggregation of Revenue (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | $ 7,684,263 | $ 10,074,675 | $ 5,793,741 |
Bakken | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | 4,157,771 | 4,951,619 | 3,349,015 |
Anadarko Basin | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | 1,686,696 | 2,948,878 | 2,138,821 |
Powder River Basin | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | 454,931 | 683,008 | 114,815 |
Permian Basin | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | 1,209,554 | 1,273,507 | 29,356 |
All Other | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | 175,311 | 217,663 | 161,734 |
Crude Oil Sales | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | 6,497,923 | 6,906,003 | 3,949,294 |
Crude Oil Sales | Bakken | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | 3,777,412 | 3,899,749 | 2,786,320 |
Crude Oil Sales | Anadarko Basin | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | 999,009 | 1,109,405 | 874,752 |
Crude Oil Sales | Powder River Basin | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | 410,963 | 557,943 | 101,705 |
Crude Oil Sales | Permian Basin | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | 1,135,421 | 1,122,290 | 24,857 |
Crude Oil Sales | All Other | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | 175,118 | 216,616 | 161,660 |
Natural gas sales | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | 1,186,340 | 3,168,672 | 1,844,447 |
Natural gas sales | Bakken | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | 380,359 | 1,051,870 | 562,695 |
Natural gas sales | Anadarko Basin | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | 687,687 | 1,839,473 | 1,264,069 |
Natural gas sales | Powder River Basin | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | 43,968 | 125,065 | 13,110 |
Natural gas sales | Permian Basin | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | 74,133 | 151,217 | 4,499 |
Natural gas sales | All Other | |||
Disaggregation of Revenue [Line Items] | |||
Crude oil, natural gas, and natural gas liquids sales | $ 193 | $ 1,047 | $ 74 |
Allowance for Credit Losses (De
Allowance for Credit Losses (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Financing Receivable, Allowance for Credit Loss [Line Items] | |||
Allowance for credit losses | $ 3.2 | $ 5.5 | |
Accounts Receivable, Credit Loss Expense (Reversal) | 0.1 | 3.3 | $ 0.8 |
Allowance for credit losses on joint interest receivables [Member] | |||
Financing Receivable, Allowance for Credit Loss [Line Items] | |||
Allowance for credit losses | $ 3.2 | $ 5.5 |
Income Taxes - Provision for In
Income Taxes - Provision for Income Taxes (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |||
Current federal income tax provision | $ 461,487 | $ 538,704 | $ 0 |
Current tax provision, various states | 37,173 | 83,671 | 0 |
Total current income tax provision | 498,660 | 622,375 | 0 |
Deferred federal income tax provision | 318,484 | 374,802 | 467,051 |
Deferred tax provision, various states | 10,486 | 23,627 | 52,679 |
Total deferred income tax provision | 328,970 | 398,429 | 519,730 |
Provision for income taxes | $ 827,630 | $ 1,020,804 | $ 519,730 |
Effective tax rate | 21.10% | 20.10% | 23.80% |
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, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | |||
Income before income taxes | $ 3,928,947 | $ 5,068,413 | $ 2,186,138 |
Expected income tax provision based on U.S. federal statutory tax rate | 825,079 | 1,064,367 | 459,089 |
State and local income taxes, net of federal benefit | 98,257 | 126,932 | 77,979 |
Tax benefit (deficiency) from stock-based compensation | 0 | (5,282) | 5,869 |
Change in valuation allowance | 0 | 0 | (14,474) |
Tax credits for increasing research activities | (67,039) | (151,913) | 0 |
Other, net | (28,667) | (13,300) | (8,733) |
Provision for income taxes | $ 827,630 | $ 1,020,804 | $ 519,730 |
Federal statutory income tax rate | 21% | 21% | 21% |
Effective tax rate | 21.10% | 20.10% | 23.80% |
Income Taxes - Components of De
Income Taxes - Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) | Dec. 31, 2023 | Dec. 31, 2022 |
Income Tax Disclosure [Abstract] | ||
Deferred tax assets, Net operating loss carryforwards | $ 56,377,000 | $ 63,128,000 |
Incentive/equity compensation | 40,929,000 | 34,987,000 |
Net deferred hedge losses | 0 | 42,898,000 |
Deferred Tax Assets, Other | 28,080,000 | 31,324,000 |
Total deferred tax assets | 125,386,000 | 172,337,000 |
Deferred Tax Assets, Valuation Allowance | 0 | 0 |
Total deferred tax assets, net of valuation allowance | 125,386,000 | 172,337,000 |
Deferred tax liabilities, Property and equipment | (2,870,259,000) | (2,708,641,000) |
Deferred tax liabilities, Net deferred hedge gains | (120,662,000) | 0 |
Deferred Tax Liabilities, Other | (1,748,000) | (2,008,000) |
Total deferred tax liabilities | 2,992,669,000 | 2,710,649,000 |
Deferred income tax liabilities, net | $ 2,867,283,000 | $ 2,538,312,000 |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Detail) - OKLAHOMA $ in Millions | 12 Months Ended |
Dec. 31, 2023 USD ($) | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss carryforwards | $ 1,800 |
Operating loss carryforward with indefinite life | 1,100 |
Operating loss carryforward subject to expiration | $ 673 |
Income Taxes Income Taxes - (De
Income Taxes Income Taxes - (Details) - USD ($) | Dec. 31, 2023 | Dec. 31, 2022 |
Income Tax Disclosure [Abstract] | ||
Deferred Tax Assets, Valuation Allowance | $ 0 | $ 0 |
Leases Description of leases (D
Leases Description of leases (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Lessee, Lease, Description [Line Items] | ||
Operating Lease, Liability | $ 37,594 | $ 24,141 |
Surface use agreements [Member] | ||
Lessee, Lease, Description [Line Items] | ||
Operating Lease, Liability | 17,263 | 18,136 |
Field equipment [Member] | ||
Lessee, Lease, Description [Line Items] | ||
Operating Lease, Liability | 19,713 | 5,224 |
Other [Member] | ||
Lessee, Lease, Description [Line Items] | ||
Operating Lease, Liability | $ 618 | $ 781 |
Leases additional information (
Leases additional information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Leases [Abstract] | |||
Operating Lease, Liability | $ 37,594 | $ 24,141 | |
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability | 24,949 | 19,944 | $ 10,481 |
Short-term Lease, Cost | 168,680 | 124,535 | 77,551 |
Lease, Cost | 182,697 | 128,669 | 87,475 |
Operating Lease, Cost | 13,121 | 3,484 | 6,653 |
Variable Lease, Cost | 896 | 650 | 3,271 |
Operating cash flows from operating leases | $ 13,166 | $ 4,370 | $ 1,731 |
Operating Lease, Weighted Average Remaining Lease Term | 6 years 10 months 24 days | 12 years | 14 years 4 months 24 days |
Weighted average discount rate | 4.70% | 4.80% | 5% |
Leases, maturities of operating
Leases, maturities of operating leases (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Leases [Abstract] | ||
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months | $ 19,603 | |
Lessee, Operating Lease, Liability, Payments, Due Year Two | 4,571 | |
Lessee, Operating Lease, Liability, Payments, Due Year Three | 1,848 | |
Lessee, Operating Lease, Liability, Payments, Due Year Four | 1,827 | |
Lessee, Operating Lease, Liability, Payments, Due Year Five | 1,765 | |
Lessee, Operating Lease, Liability, Payments, Due after Year Five | 16,586 | |
Lessee, Operating Lease, Liability, to be Paid, Total | 46,200 | |
Lessee, Operating Lease, Liability, Undiscounted Excess Amount | (8,606) | |
Operating Lease, Liability, Total | 37,594 | $ 24,141 |
Current portion of operating lease liabilities | (18,112) | (4,086) |
Operating lease liabilities, noncurrent | $ 19,482 | $ 20,055 |
Commitments and Contingencies -
Commitments and Contingencies - Additional Information (Detail) $ in Millions | 12 Months Ended |
Dec. 31, 2023 USD ($) | |
Long-term Purchase Commitment [Line Items] | |
Purchase Obligation Agreement Expiration Date | 2031 |
Purchase Obligation | $ 824 |
Purchase Obligation, Due in Next Twelve Months | 307 |
Purchase Obligation, Due in Second Year | 164 |
Purchase Obligation, Due in Third Year | 139 |
Purchase Obligation, Due in Fourth Year | 136 |
Purchase Obligation, Due in Fifth Year | 70 |
Purchase Obligation, Due after Fifth Year | $ 8 |
Commitments and Contingencies L
Commitments and Contingencies Loss Contingencies (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Loss Contingencies [Line Items] | ||
Legal proceedings recorded as a liability under other noncurrent liabilities | $ 13.8 | $ 20.2 |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Detail) - USD ($) | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Related Party Transaction [Line Items] | |||
Revenues from transactions with related party | $ 8,731,741,000 | $ 9,473,708,000 | $ 5,719,318,000 |
Amount charged to affiliate for aircraft use | 28,100 | 16,400 | 11,300 |
Total amount received from related party | 31,000 | 13,000 | 5,000 |
Amount charged to company by affiliate for aircraft use | 312,000 | 235,000 | 117,000 |
Officers And Other Key Employees [Member] | |||
Related Party Transaction [Line Items] | |||
Revenues from transactions with related party | 100,000 | 200,000 | 100,000 |
Due to affiliates | 31,000 | 36,000 | |
Revenues paid to related party | 400,000 | 500,000 | 400,000 |
Due from affiliates | 35,000 | 6,000 | |
Other Affiliates [Member] | |||
Related Party Transaction [Line Items] | |||
Total amount paid to related party | 299,000 | 219,000 | $ 84,000 |
Due to affiliates | 63,000 | 49,000 | |
Due from affiliates | $ 7,000 | $ 9,800 |
Incentive Compensation - Additi
Incentive Compensation - Additional Information (Detail) - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized liabilities and compensation expense related to unvested awards | $ 90.4 | ||
Unrecognized compensation expense related to non-vested, period for recognition, in years | 1 year 6 months | ||
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 settlement of awards | $ 130.6 | ||
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 settlement of awards | $ 41.7 | ||
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 |
Incentive Compensation - Associ
Incentive Compensation - Associated Compensation Expense (Detail) - USD ($) $ in Millions | 12 Months Ended | |||
Nov. 22, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Share-Based Payment Arrangement [Abstract] | ||||
Non-cash compensation expense | $ 136 | $ 91.3 | $ 217.8 | $ 63.2 |
Incentive Compensation - Summar
Incentive Compensation - Summary of Changes in Non Vested Shares of Restricted Stock Outstanding Prior to Take-Private Transaction (Detail) - $ / shares | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
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 |
Granted shares | 1,575,847 | 3,050,491 |
Vested shares | (1,736,678) | (1,750,483) |
Forfeited shares | (384,536) | (296,138) |
Cancelled shares due to take-private transaction | (5,349,141) | |
Non-vested shares, ending balance | 0 | 5,894,508 |
Non-vested, weighted average grant-date fair value, beginning of period | $ 28.38 | $ 36.26 |
Granted, weighted average grant-date fair value | 56.52 | 24.73 |
Vested, weighted average grant-date fair value | 36.04 | 44.36 |
Forfeited, weighted average grant-date fair value | 27.82 | 26.61 |
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 |
Shareholders' Equity Attribut_3
Shareholders' Equity Attributable to Continental Resources - Share Repurchase Program (Details) - USD ($) $ in Thousands | 12 Months Ended | 24 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2022 | |
Share Repurchase Program [Abstract] | |||
Stock Repurchased and Retired During Period, Shares | 1,842,422 | 3,198,571 | 5,040,993 |
Treasury Stock, Retired, Cost Method, Amount | $ 99,855 | $ 123,924 | $ 223,779 |
Shareholders' Equity Attribut_4
Shareholders' Equity Attributable to Continental Resources - (Additional Information) (Details) - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Class of Stock [Line Items] | |||
Payments of dividends | $ 2.1 | $ 283.8 | $ 165.9 |
Hamm Family | Omega Acquisition, Inc. [Member] | |||
Class of Stock [Line Items] | |||
Number of shares held in capital stock | 299.6 | 299.6 |
Noncontrolling Interests - Addi
Noncontrolling Interests - Additional Information (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
TMRC II [Member] | ||
Noncontrolling Interest [Line Items] | ||
Other Noncontrolling Interests | $ 345.1 | $ 361.4 |
SFPG, LLC [Member] | ||
Noncontrolling Interest [Line Items] | ||
Other Noncontrolling Interests | $ 11 | $ 11 |
Equity Investment (Additional I
Equity Investment (Additional Information) (Details) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Schedule of Equity Method Investments [Line Items] | ||
Equity Method Investment, Aggregate Cost | $ 33 | $ 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% |
Capitalized Exploratory Well _3
Capitalized Exploratory Well Costs - Schedule of Capitalized Exploratory Drilling Costs Pending Evaluation (Detail) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 USD ($) Well | Dec. 31, 2022 USD ($) Well | Dec. 31, 2021 USD ($) Well | |
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward] | |||
Balance at January 1 | $ 84,822 | $ 37,673 | $ 32,737 |
Additions to capitalized exploratory well costs pending determination of proved reserves | 345,434 | 286,059 | 122,068 |
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves | (270,490) | (229,348) | (117,131) |
Capitalized exploratory well costs charged to expense | (32) | (9,562) | (1) |
Balance at December 31 | $ 159,734 | $ 84,822 | $ 37,673 |
Number of wells | Well | 34 | 36 | 17 |
Supplemental Crude Oil and Na_3
Supplemental Crude Oil and Natural Gas Information - Additional Information (Detail) | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Reserve Quantities [Line Items] | |||
Discount factor utilized as standardized measure for future net cash flows | 10% | ||
Percent of proved crude oil reserve estimates prepared by external reserve engineers | 99% | 98% | 98% |
Supplemental Crude Oil and Na_4
Supplemental Crude Oil and Natural Gas Information - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities (Detail) | Dec. 31, 2023 MBoe MMcf MBbls | Dec. 31, 2022 MBoe MMcf MBbls | Dec. 31, 2021 MBoe MMcf MBbls |
Reserve Quantities [Line Items] | |||
Proved Developed Reserves (MBOE) | MBoe | 938,779 | 1,035,428 | 907,678 |
Proved Undeveloped Reserve (MBOE) | MBoe | 1,847,089 | 1,863,764 | 1,645,310 |
Proved Developed and Undeveloped Reserve, Net (MBOE) | MBoe | 908,310 | 828,336 | 737,632 |
Crude Oil [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Developed Reserves (Volume) | MBbls | 401,851 | 454,299 | 424,153 |
Proved Undeveloped Reserve (Volume) | MBbls | 512,183 | 435,240 | 369,377 |
Proved Developed and Undeveloped Reserves, Net | MBbls | 914,034 | 889,539 | 793,530 |
Natural Gas [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Developed Reserves (Volume) | MMcf | 3,221,566 | 3,486,774 | 2,901,147 |
Proved Undeveloped Reserve (Volume) | MMcf | 2,376,765 | 2,358,578 | 2,209,532 |
Proved Developed and Undeveloped Reserves, Net | MMcf | 5,598,331 | 5,845,352 | 5,110,679 |