Chord Energy (CHRD) 10-K 26 Feb 24 2023 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2023	Feb. 16, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-34776
Entity Registrant Name	Chord Energy Corporation
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	80-0554627
Entity Address, Address Line One	1001 Fannin Street
Entity Address, Address Line Two	Suite 1500
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	281
Local Phone Number	404-9500
Title of 12(b) Security	Common Stock
Trading Symbol	CHRD
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
Entity Bankruptcy Proceedings, Reporting Current	true
Entity Public Float			$ 6,340,929,766
Entity Common Stock, Shares Outstanding		41,438,134
Documents Incorporated by Reference	Portions of the registrant’s definitive proxy statement for its 2024 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2023, are incorporated by reference into Part III of this report for the year ended December 31, 2023.
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Entity Central Index Key	0001486159

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2023
Auditor Information [Abstract]
Auditor Firm ID	238
Auditor Name	PricewaterhouseCoopers LLP
Auditor Location	Houston, Texas

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Current assets
Cash and cash equivalents	$ 317,998	$ 593,151
Accounts receivable, net	943,114	781,738
Inventory	72,565	54,411
Prepaid expenses	42,450	17,624
Derivative instruments	37,369	23,735
Other current assets	11,055	11,853
Total current assets	1,424,551	1,482,512
Property, plant and equipment
Oil and gas properties (successful efforts method)	6,320,243	5,120,121
Other property and equipment	49,051	72,973
Less: accumulated depreciation, depletion and amortization	(1,054,616)	(481,751)
Total property, plant and equipment, net	5,314,678	4,711,343
Derivative instruments	22,526	37,965
Investment in unconsolidated affiliate	100,172	130,575
Long-term inventory	22,936	22,009
Operating right-of-use assets	21,343	23,875
Deferred tax assets	0	200,226
Other assets	19,944	22,576
Total assets	6,926,150	6,631,081
Current liabilities
Accounts payable	34,453	29,056
Revenues and production taxes payable	604,704	607,964
Accrued liabilities	493,381	362,454
Accrued interest payable	2,157	3,172
Derivative instruments	14,209	341,541
Advances from joint interest partners	2,381	3,736
Current operating lease liabilities	13,258	9,941
Other current liabilities	916	3,469
Total current liabilities	1,165,459	1,361,333
Long-term debt	395,902	394,209
Deferred tax liabilities	95,322	0
Asset retirement obligations	155,040	146,029
Derivative instruments	717	2,829
Operating lease liabilities	18,667	13,266
Other liabilities	18,419	33,617
Total liabilities	1,849,526	1,951,283
Commitments and contingencies
Stockholders’ equity
Common stock, $0.01 par value: 120,000,000 shares authorized, 45,032,537 shares issued and 41,249,658 shares outstanding at December 31, 2023; and 120,000,000 shares authorized, 43,726,181 shares issued and 41,477,093 shares outstanding at December 31, 2022	456	438
Treasury stock, at cost: 3,782,879 shares at December 31, 2023 and 2,249,088 shares at December 31, 2022	(493,289)	(251,950)
Additional paid-in-capital	3,608,819	3,485,819
Retained earnings	1,960,638	1,445,491
Total stockholders’ equity	5,076,624	4,679,798
Total liabilities and stockholders’ equity	$ 6,926,150	$ 6,631,081

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - $ / shares	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Common stock, par value (in usd per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	120,000,000	120,000,000
Common stock, shares issued (in shares)	45,032,537	43,726,181
Common stock, shares outstanding (in shares)	41,249,658	41,477,093
Treasury stock, shares (in shares)	3,782,879	2,249,088

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues
Total revenues	$ 3,896,641	$ 3,646,794	$ 1,579,926
Operating expenses
Lease operating expenses	658,938	443,560	203,980
Gathering, processing and transportation expenses	180,219	141,644	122,614
Production taxes	260,002	229,571	76,835
Depreciation, depletion and amortization	598,562	369,659	126,436
General and administrative expenses	126,319	209,299	80,688
Total operating expenses	2,620,695	2,067,872	993,288
Gain (loss) on sale of assets, net	(2,764)	4,867	222,806
Operating income	1,273,182	1,583,789	809,444
Other income (expense)
Net gain (loss) on derivative instruments	63,182	(208,128)	(589,641)
Net gain from investment in unconsolidated affiliate	21,330	34,366	0
Interest expense, net of capitalized interest	(28,630)	(29,349)	(30,806)
Other income (expense)	9,964	2,901	(1,010)
Total other income (expense), net	65,846	(200,210)	(621,457)
Income from continuing operations before income taxes	1,339,028	1,383,579	187,987
Income tax (expense) benefit	(315,249)	46,884	973
Net income from continuing operations	1,023,779	1,430,463	188,960
Income from discontinued operations attributable to Chord, net of income tax	0	425,696	130,642
Net income attributable to Chord	$ 1,023,779	$ 1,856,159	$ 319,602
Earnings attributable to Chord per share:
Basic from continuing operations (in usd per share)	$ 24.59	$ 46.90	$ 9.55
Basic from discontinued operations (in usd per share)	0	13.96	6.60
Basic (in dollars per share)	24.59	60.86	16.15
Diluted from continuing operations (in usd per share)	23.51	44.35	9.15
Diluted from discontinued operations (in usd per share)	0	13.20	6.33
Diluted (in usd per share)	$ 23.51	$ 57.55	$ 15.48
Weighted average shares outstanding:
Basic (in shares)	41,490	30,497	19,792
Diluted (in shares)	43,398	32,251	20,648
Oil and Gas
Revenues
Total revenues	$ 3,132,411	$ 2,976,296	$ 1,200,256
Operating expenses
Exploration and impairment	35,330	2,204	2,763
Purchased Oil and Gas
Revenues
Total revenues	764,230	670,174	378,983
Operating expenses
Purchased oil and gas expenses	761,325	671,935	379,972
Other Services
Revenues
Total revenues	$ 0	$ 324	$ 687

Consolidated Statements of Chan

Consolidated Statements of Changes in Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock	Treasury Stock	Additional Paid-in-Capital	Retained Earnings (Deficit)	Non-controlling Interests
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance	$ 1,012,739	$ 200	$ 0	$ 965,654	$ (49,912)	$ 96,797
Beginning balance, common stock (in shares) at Dec. 31, 2020		20,093,000
Beginning balance, treasury stock (in shares) at Dec. 31, 2020			0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Equity-based compensation and vestings (in shares)		3,000
Equity-based compensation and vestings	15,476			14,685		791
Dividends	(116,852)			(116,852)
Distributions to non-controlling interest owners	(28,720)					(28,720)
Issuance of OMP common units, net of offering costs	86,467					86,467
Midstream Simplification	0			2,358		(2,358)
Common control transaction costs	(5,675)			(5,675)
Warrants exercised (in shares)		51,000
Warrants exercised	2,840			2,840
Repurchase of common stock (in shares)		(871,000)	871,000
Repurchase of common stock	(100,000)		$ (100,000)
Net income (loss)	355,298				319,602	35,696
Ending balance, common stock (in shares) at Dec. 31, 2021		19,276,000
Ending balance, treasury stock (in shares) at Dec. 31, 2021			871,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance	1,221,573	$ 200	$ (100,000)	863,010	269,690	188,673
Equity-based compensation and vestings (in shares)		835,000
Equity-based compensation and vestings	61,269	$ 4		61,217		48
Tax withholding on vesting of equity-based awards (in shares)		(345,000)	35,000
Tax withholding on vesting of equity-based awards	(41,752)		$ (4,789)	(36,963)
Modification of equity-based awards	(226)			(226)
Dividends	(680,358)				(680,358)
Transfer of equity plan shares from treasury (in shares)			(35,000)
Transfer of equity plan shares from treasury	0		$ 4,789	(4,789)
Shares issued in Merger (in shares)		22,672,000
Shares issued in Merger	2,478,036	$ 227		2,477,809
Replacement equity awards issued in Merger	27,402			27,402
Replacement warrants issued in Merger	79,774			79,774
Warrants exercised (in shares)		417,000
Warrants exercised	$ 18,592	$ 7		18,585
Repurchase of common stock (in shares)	(1,378,070)	(1,378,000)	1,378,000
Repurchase of common stock	$ (151,950)		$ (151,950)
OMP Merger	(191,032)					(191,032)
Net income (loss)	$ 1,858,470				1,856,159	2,311
Ending balance, common stock (in shares) at Dec. 31, 2022	41,477,093	41,477,000
Ending balance, treasury stock (in shares) at Dec. 31, 2022	2,249,088		2,249,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance	$ 4,679,798	$ 438	$ (251,950)	3,485,819	1,445,491	0
Equity-based compensation and vestings (in shares)		305,000
Equity-based compensation and vestings	46,110	$ 6		46,104
Tax withholding on vesting of equity-based awards (in shares)		(105,000)
Tax withholding on vesting of equity-based awards	(14,604)	$ (1)		(14,603)
Dividends	$ (508,632)				(508,632)
Warrants exercised (in shares)	1,746,859	1,107,000
Warrants exercised	$ 91,512	$ 13		91,499
Repurchase of common stock (in shares)	(1,533,791)	(1,534,000)	1,534,000
Repurchase of common stock	$ (241,339)		$ (241,339)
Net income (loss)	$ 1,023,779				1,023,779
Ending balance, common stock (in shares) at Dec. 31, 2023	41,249,658	41,250,000
Ending balance, treasury stock (in shares) at Dec. 31, 2023	3,782,879		3,783,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance	$ 5,076,624	$ 456	$ (493,289)	$ 3,608,819	$ 1,960,638	$ 0

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 including non-controlling interests	$ 1,023,779	$ 1,858,470	$ 355,298
Adjustments to reconcile net income including non-controlling interests to net cash provided by operating activities:
Depreciation, depletion and amortization	598,562	369,659	158,304
(Gain) loss on sale of assets	2,764	(523,767)	(222,806)
Impairment	28,963	(344)	5
Deferred income taxes	295,548	28,341	(977)
Net gain from investment in unconsolidated affiliate	(21,330)	(34,366)	0
Net (gain) loss on derivative instruments	(63,182)	208,128	589,641
Equity-based compensation expenses	46,108	61,269	15,476
Deferred financing costs amortization and other	505	3,194	12,992
Working capital and other changes:
Change in accounts receivable, net	(147,870)	84,041	(184,605)
Change in inventory	(12,659)	8,756	2,168
Change in prepaid expenses	(1,199)	3,423	5,605
Change in accounts payable, interest payable and accrued liabilities	78,267	(131,687)	184,517
Change in other assets and liabilities, net	(8,405)	(11,091)	(1,482)
Net cash provided by operating activities	1,819,851	1,924,026	914,136
Cash flows from investing activities:
Capital expenditures	(905,673)	(531,327)	(212,820)
Acquisitions, net of cash acquired	(361,609)	(148,144)	(590,097)
Proceeds from divestitures, net of cash divested	54,445	169,198	376,081
Costs related to divestitures	0	(11,368)	(2,926)
Derivative settlements	(268,887)	(633,025)	(270,118)
Derivative modifications	0	0	(220,889)
Proceeds from sale of investment in unconsolidated affiliate	40,612	428,231	0
Distributions from investment in unconsolidated affiliate	10,806	43,873	0
Net cash used in investing activities	(1,430,306)	(682,562)	(920,769)
Cash flows from financing activities:
Proceeds from revolving credit facilities	260,000	1,035,000	399,500
Principal payments on revolving credit facilities	(260,000)	(1,020,000)	(906,500)
Proceeds from issuance of senior unsecured notes	0	0	850,000
Cash paid to settle Whiting debt	0	(2,154)	0
Deferred financing costs	0	(5,997)	(22,251)
Proceeds from issuance of OMP common units, net of offering costs	0	0	86,467
Common control transaction costs	0	0	(5,675)
Purchases of treasury stock	(239,339)	(151,950)	(100,000)
Tax withholding on vesting of equity-based awards	(14,604)	(41,752)	0
Dividends paid	(500,304)	(654,728)	(111,905)
Distributions to non-controlling interests	0	0	(28,720)
Payments on finance lease liabilities	(1,702)	(1,299)	(1,161)
Proceeds from warrants exercised	91,251	19,784	1,435
Net cash provided by (used in) financing activities	(664,698)	(823,096)	161,190
Increase (decrease) in cash, cash equivalents and restricted cash	(275,153)	418,368	154,557
Cash, cash equivalents and restricted cash:
Beginning of period	593,151	174,783	20,226
End of period	317,998	593,151	174,783
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	26,371	24,266	41,603
Cash paid for income taxes	17,195	10,000	20,000
Supplemental non-cash transactions:
Change in accrued capital expenditures	45,513	(21,668)	8,304
Change in asset retirement obligations	1,238	852	14,724
Non-cash consideration exchanged in Merger	0	2,585,211	0
Investment in unconsolidated affiliate	0	568,312	0
Note receivable from divestiture	0	0	2,900
Contingent consideration from Permian Basin Sale	0	0	32,860
Dividends payable	$ 37,553	$ 30,630	$ 4,946

Organization and Operations of

Organization and Operations of the Company	12 Months Ended
	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Operations of the Company	Organization and Operations of the Company Chord Energy Corporation (together with its consolidated subsidiaries, the “Company” or “Chord”) is an independent exploration and production (“E&P”) company engaged in the acquisition, exploration, development and production of crude oil, NGLs and natural gas in the Williston Basin. The Company, formerly known as Oasis Petroleum Inc. (“Oasis”), was established upon completion of the merger of equals with Whiting Petroleum Corporation (“Whiting”) on July 1, 2022 (the “Merger”). Whiting was an independent oil and gas company engaged in E&P activities primarily in the Rocky Mountains region of the United States. The Merger was accounted for under the acquisition method of accounting in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 805, Business Combinations (“ASC 805”). Accordingly, unless otherwise specifically noted herein, the periods prior to July 1, 2022 report the financial results of legacy Oasis, while the periods as of and subsequent to July 1, 2022 report the financial results of Chord, which include the operating results of Whiting and the associated impacts from the Merger.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Basis of Presentation The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The Company has evaluated how it is organized and managed and has identified only one reportable business segment, which is the exploration and production of crude oil, NGLs and natural gas. The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities. All of the Company’s operations and assets are located in the United States, and substantially all of its revenues are attributable to United States customers. As of December 31, 2021, the Company had two business segments related to E&P and midstream operations. The Company’s midstream segment was classified as a discontinued operation in connection with the OMP Merger (defined in Note 10 — Divestitures ) and is no longer presented as a separate reporting segment in accordance with FASB ASC 280, Segment Reporting . Use of Estimates Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to (i) proved crude oil, NGL and natural gas reserves and related cash flow estimates, (ii) assignment of fair value and allocation of purchase price in connection with business combinations, including the determination of any resulting goodwill or bargain purchase, (iii) impairment tests of long-lived assets, (iv) estimates of future development, dismantlement and abandonment costs, (v) estimates relating to certain crude oil, NGL and natural gas revenues and expenses, (vi) income taxes, (vii) valuation of derivative instruments and (viii) estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates. Estimates of crude oil, NGL and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, NGL and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future depreciation, depletion and amortization (“DD&A”) expense, dismantlement and abandonment costs and impairment expense. Risks and Uncertainties As a producer of crude oil, NGLs and natural gas, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude oil, NGLs and natural gas, which are dependent upon numerous factors beyond its control such as economic, geopolitical, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile, and there can be no assurance that the prices for crude oil, NGLs or natural gas will not be subject to wide fluctuations in the future. A substantial or extended decline in prices for crude oil and, to a lesser extent, NGLs and natural gas, could have a material adverse effect on the Company’s financial position, results of operations, cash flows, the quantities of crude oil, NGLs and natural gas reserves that may be economically produced and the Company’s access to capital. Cash and Cash Equivalents The Company invests in certain money market funds, commercial paper and time deposits, all of which are stated at fair value or cost which approximates fair value due to the short-term maturity of these investments. The Company classifies all such highly liquid investments with original maturity dates less than 90 days as cash equivalents. While the Company may maintain balances of cash and cash equivalents in excess of amounts that are federally insured by the Federal Deposit Insurance Corporation, the Company invests with financial institutions that it believes are creditworthy and has not experienced any material losses in such accounts. Accounts Receivable Accounts receivable are carried at cost on a gross basis, with no discounting, which approximates fair value due to their short-term maturities. The Company’s accounts receivable consist mainly of receivables from crude oil, NGL and natural gas purchasers and joint interest owners on properties the Company operates. The Company regularly assesses the recoverability of all material trade and other receivables to determine their collectability and if an allowance for credit losses is warranted. The Company estimates credit losses and accrues a reserve on a receivable based on (i) historic loss experience for pools of receivable balances with similar characteristics, (ii) the length of time balances have been outstanding and (iii) the economic status of each counterparty. These loss estimates are then adjusted for current and expected future economic conditions, which may include an assessment of the probability of non-payment, financial distress or expected future commodity prices and the impact that any current or future conditions could have on a counterparty’s credit quality and liquidity. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s crude oil, NGL and natural gas receivables are collected within two months. Inventory The Company’s inventory includes equipment and materials and crude oil inventory. Equipment and materials consist primarily of well equipment, tanks and tubular goods to be used in the Company’s exploration and production activities. Crude oil inventory includes crude oil in tanks and linefill. Linefill represents the minimum volume of product in a pipeline system that enables the system to operate and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Crude oil and NGL linefill in third-party pipelines that is not expected to be withdrawn within one year is included in long-term inventory on the Company’s Consolidated Balance Sheets (see Note 4—Inventory). Inventory, including long-term inventory, is stated at the lower of cost and net realizable value with cost determined on an average cost method. The Company assesses the carrying value of inventory and uses estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact the Company’s estimates are the applicable quality and location differentials to include in the Company’s net realizable value analysis. Additionally, the Company estimates the upcoming liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net realizable value. Property, Plant and Equipment Proved Oil and Gas Properties Crude oil, NGL and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and gas properties are capitalized at their estimated net present value. The provision for depletion of oil and gas properties is calculated using the unit-of-production method. All capitalized well costs (including future abandonment costs, net of salvage value) and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of crude oil. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized. The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties by field and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties in the applicable field to determine if the carrying amount is recoverable. The factors used to determine the undiscounted future cash flows are subject to management’s judgment and expertise and include, but are not limited to, future production volumes based upon estimates of proved reserves, future commodity prices and estimates of operating and development costs. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, the Company’s estimated undiscounted future cash flows, the timing and pace of development and the discount rate commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges for proved oil and gas properties will be recorded. Unproved Oil and Gas Properties Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment in the Consolidated Statements of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses its unproved properties periodically for impairment on a prospect-by-prospect basis based on remaining lease terms, drilling results or future plans to develop acreage. The Company considers the following factors in its assessment of the impairment of unproved properties: • the remaining amount of unexpired term under its leases; • its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be close to expiration; • its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development; • its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and • its evaluation of the continuing successful results from the development of properties by the Company or by other operators in areas adjacent to or near the Company’s unproved properties. For sales of entire working interests in unproved properties, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property. Capitalized Interest The Company capitalizes a portion of its interest expense incurred on its outstanding debt. The amount capitalized is determined by multiplying the capitalization rate by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period. The accumulated capital expenditures included in the capitalized interest calculation begin when the first costs are incurred and end when the asset is either placed into production or written off. The Company capitalized interest costs of $4.1 million, $4.6 million and $2.1 million for the years ended December 31, 2023, 2022 and 2021, respectively. Capitalized interest costs are amortized over the life of the related assets. Other Property and Equipment Other property and equipment consists primarily of field office buildings, oilfield equipment, furniture, software, and leasehold improvements, and is recorded at cost and depreciated using the straight-line method based on expected lives of the individual assets (ranging from two years to 30 years) and net of estimated salvage values. The cost of assets disposed of and the associated accumulated DD&A are removed from the Company’s Consolidated Balance Sheets with any gain or loss realized upon the sale or disposal included in the Company’s Consolidated Statements of Operations. Exploration Expenses Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, are charged to expense as incurred. Costs from drilling exploratory wells are initially capitalized but charged to expense if and when a well is determined to be unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drilling is completed. The Company defers capitalized exploratory drilling costs for wells that have found a sufficient quantity of producible hydrocarbons but cannot be classified as proved because they are located in areas that require major capital expenditures or governmental or other regulatory approvals before production can begin. These costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for in the near future or the necessary approvals are actively being sought. Net changes in capitalized exploratory well costs are reflected in the following table for the periods presented: Year Ended December 31, 2023 2022 2021 (In thousands) Beginning of period $ — $ 1 $ — Exploratory well cost additions (pending determination of proved reserves) — 21 — Exploratory well cost reclassifications (successful determination of proved reserves) — (2) — Exploratory well dry hole costs (unsuccessful in adding proved reserves) — — — Exploratory well cost reclassifications (canceled wells written off to predrill write-off) — (20) 1 End of period $ — $ — $ 1 As of December 31, 2023, the Company had no exploratory well costs that were capitalized for a period of greater than one year after the completion of drilling. Business Combinations The Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed measured at the estimated acquisition date fair value. Transaction and integration costs associated with business combinations are expensed as incurred. The Company makes various assumptions in estimating the fair value of the assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair value of proved and unproved oil and gas properties, which is measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include future production volumes based upon estimates of reserves prepared by the Company’s reserve engineers, future operating and development costs, future commodity prices (adjusted for basis differentials) and a market-based weighted average cost of capital discount rate. In addition, when appropriate, the Company reviews comparable transactions between market participants for the purchase and sale of oil and gas properties within the same region to measure fair value, which illustrates the amount a willing buyer and seller would enter into in exchange for such properties. The Company records goodwill for any amount of the consideration transferred in excess of the estimated fair value of the net assets acquired and a bargain purchase gain for any amount of the estimated fair value of net assets acquired in excess of the consideration transferred. Deferred taxes are recorded for any difference between the acquisition date fair value and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. The Company may adjust the provisional amounts recorded in a business combination during the measurement period which extends for up to one year after the acquisition date. Discontinued Operations The OMP Merger (defined in Note 10—Divestitures) represented a strategic shift for the Company and qualified for reporting as a discontinued operation on February 1, 2022, in accordance with FASB ASC 205-20, Presentation of financial statements – Discontinued Operations (“ASC 205-20”). Prior periods were recast so that the basis of presentation is consistent with that of the 2022 consolidated financial statements. Accordingly, the results of operations of OMP (defined in Note 10—Divestitures) were classified as discontinued operations in the Consolidated Statements of Operations for the years ended December 31, 2022 and 2021. There were no discontinued operations for the year ended December 31, 2023. The Consolidated Statements of Cash Flows were not required to be reclassified for discontinued operations for any period. See Note 11—Discontinued Operations for additional information. Investment in Unconsolidated Affiliate On February 1, 2022, the Company completed the OMP Merger (defined in Note 10—Divestitures) and received common units representing limited partner interests of Crestwood Equity Partners LP, a Delaware limited partnership (“Crestwood”). The Company elected to account for its investment in Crestwood using the fair value option under FASB ASC 825-10, Financial Instruments . Under the fair value option, the Company measures the carrying amount of its investment in Crestwood at fair value each reporting period, with changes in fair value recorded to net gain from investment in unconsolidated affiliate on the Consolidated Statement of Operations. Cash distributions from Crestwood are recorded to net gain from investment in unconsolidated affiliate on the Consolidated Statement of Operations and distributions from investment in unconsolidated affiliate on the Consolidated Statement of Cash Flows. In August 2023, Crestwood and Energy Transfer LP (“Energy Transfer”) entered into a definitive merger agreement to which Energy Transfer would acquire Crestwood. On November 3, 2023, Energy Transfer completed their acquisition of Crestwood, and holders of Crestwood common units received 2.07 Energy Transfer common units for each Crestwood unit held. See Note 6—Fair Value Measurements, Note 10—Divestitures and Note 12—Investment in Unconsolidated Affiliate for additional information. Deferred Financing Costs The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the Company’s Consolidated Statements of Operations. Deferred financing costs related to the Credit Facility (defined in Note 13—Long-Term Debt) are included in other assets on the Company’s Consolidated Balance Sheets, while deferred financing costs related to the Senior Notes (defined in Note 13—Long-Term Debt) are included as a reduction of long-term debt on the Company’s Consolidated Balance Sheets. Asset Retirement Obligations In accordance with the FASB’s authoritative guidance on asset retirement obligations (“ARO”), the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties and produced water disposal wells, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period, and the capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as a component of DD&A in the Company’s Consolidated Statements of Operations. The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs, as further discussed in Note 6—Fair Value Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset. Revenue Recognition The Company recognizes revenue in accordance with FASB ASC 606, Revenue from Contracts with Customers (“ASC 606”). ASC 606 includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Disclosures in accordance with ASC 606 have been provided in Note 3—Revenue Recognition. The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or a bundle of goods or services) at a point in time or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied. The Company’s revenues are predominantly derived from contracts for the sale of crude oil, NGLs and natural gas. Generally, for the crude oil, NGL and natural gas contracts: (i) each unit of commodity product is a separate performance obligation, as the Company’s promise is to sell multiple distinct units of commodity product at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on the Company’s right to invoice at month end for the value of commodity product sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity product’s standalone selling price and recognized as revenue at a point in time, which is typically when production is delivered and title or risk of loss transfers to the customer. The sales prices for crude oil, NGLs and natural gas are market-based and are adjusted for transportation and other related fees and deductions. Fees included in the contract that are incurred after the transfer of control to the customer are included as a reduction of the transaction price, while fees that are incurred prior to the transfer of control to the customer are classified as gathering, processing and transportation expenses in the Company’s Consolidated Statements of Operations. The sales of crude oil, NGL and natural gas as presented on the Company’s Consolidated Statements of Operations represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling crude oil, NGL and natural gas on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. Substantially all of the Company’s crude oil and natural gas production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices, and the Company’s NGL production is generally sold to purchasers under long-term (more than 12-month) contracts at market-based prices. The Company sells the majority of its production soon after it is produced at various locations, and, as a result, the Company maintains a minimum amount of product inventory in storage. For sales of commodities, the Company records revenue in the month that the production or purchased product is delivered to the purchaser. However, settlement statements and payments are typically not received for 20 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company uses knowledge of its properties, its properties’ historical performance, spot market prices and other factors as the basis for these estimates. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. In certain cases, the Company is required to estimate these volumes during a reporting period and record any differences between the estimated volumes and actual volumes in the following reporting period. Differences between estimated and actual revenues have historically not been significant. Revenue recognized related to performance obligations satisfied in prior reporting periods was not material for the periods presented. The Company’s purchased crude oil and natural gas sales are derived from the sale of crude oil and natural gas purchased from third parties. Revenues and expenses from these sales and purchases are recorded on a gross basis when the Company acts as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, the Company enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with FASB ASC 845, Nonmonetary Transactions . Leases The Company accounts for leases in accordance with FASB ASC 842, Leases (“ASC 842”). In accordance with ASC 842, the Company determines whether an arrangement is a lease at its inception. The Company’s long-term operating and finance leases consist primarily of office space, vehicles and other property and equipment used in its operations. The operating lease right-of-use (“ROU”) asset also includes any lease incentives received in the recognition of the present value of future lease payments. The Company considers renewal and termination options in determining the lease term used to establish its ROU assets and lease liabilities to the extent the Company is reasonably certain to exercise the renewal or termination. The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants. As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future lease payments. The Company determines the incremental borrowing rate based upon the rate of interest that would have been paid on a collateralized basis over similar tenors to that of the leases. The Company’s share of operating, variable and short-term lease costs are either capitalized and included in property, plant and equipment on the Company’s Consolidated Balance Sheets or are recognized in the Company’s Consolidated Statements of Operations in lease operating expenses and general and administrative expenses, as applicable. The finance lease costs for the amortization of ROU assets are included in depreciation, depletion and amortization and the interest on lease liabilities is included in interest expense, net of capitalized interest, on the Company’s Consolidated Statements of Operations. The Company has elected practical expedients under ASC 842, including the practical expedient to not reassess under the new standard any prior conclusions about lease identification, lease classification and initial direct costs; the use-of-hindsight practical expedient; the practical expedient to not reassess the prior accounting treatment for existing or expired land easements; and the practical expedient pertaining to combining lease and non-lease components for all asset classes. In addition, the Company elected not to apply the recognition requirements of ASC 842 to leases with terms of one year or less, and as such, recognition of lease payments for short-term leases are recognized in net income on a straight-line basis. See Note 19—Leases for additional information. Fair Value Measurements As defined in FASB ASC 820, Fair Value Measurement (“ASC 820”), fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. ASC 820 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows: Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Revenue Recognition	Revenue Recognition Revenues associated with contracts with customers were as follows for the periods presented: Year Ended December 31, 2023 2022 2021 (In thousands) Crude oil revenues $ 2,835,962 $ 2,366,995 $ 910,381 Purchased crude oil sales 709,817 511,020 247,252 NGL and natural gas revenues 296,449 609,301 289,875 Purchased NGL and natural gas sales 54,413 159,154 131,731 Other services revenues — 324 687 Total revenues $ 3,896,641 $ 3,646,794 $ 1,579,926 The Company has elected practical expedients, pursuant to ASC 606, to exclude from the presentation of remaining performance obligations: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct service that forms part of a series of distinct services and (ii) contracts with an original expected duration of one year or less.

Inventory

Inventory	12 Months Ended
	Dec. 31, 2023
Inventory Disclosure [Abstract]
Inventory	Inventory The following table sets forth the Company’s inventory balances for the periods presented: December 31, 2023 2022 (In thousands) Inventory Equipment and materials $ 30,201 $ 21,097 Crude oil inventory 42,364 33,314 Total inventory $ 72,565 $ 54,411 Long-term inventory Linefill in third-party pipelines $ 22,936 $ 22,009 Total long-term inventory $ 22,936 $ 22,009 Total $ 95,501 $ 76,420

Additional Balance Sheet Inform

Additional Balance Sheet Information	12 Months Ended
	Dec. 31, 2023
Balance Sheet Related Disclosures [Abstract]
Additional Balance Sheet Information	Additional Balance Sheet Information Certain balance sheet amounts are comprised of the following: December 31, 2023 2022 (In thousands) Accounts receivable, net Trade and other accounts $ 749,356 $ 661,121 Joint interest accounts 207,571 127,772 Total accounts receivable 956,927 788,893 Less: allowance for credit losses (13,813) (7,155) Total accounts receivable, net $ 943,114 $ 781,738 Revenues and production taxes payable Royalties payable $ 297,531 $ 368,574 Revenue suspense 266,704 203,388 Production taxes payable 40,469 36,002 Total revenue and production taxes payable $ 604,704 $ 607,964 Accrued liabilities Accrued oil and gas marketing $ 165,141 $ 127,240 Accrued capital costs 122,260 76,747 Accrued lease operating expenses 107,606 73,714 Accrued general and administrative expenses 37,882 42,259 Current portion of asset retirement obligations 10,507 19,376 Accrued dividends 25,167 5,873 Other accrued liabilities 24,818 17,245 Total accrued liabilities $ 493,381 $ 362,454

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements In accordance with the FASB’s authoritative guidance on fair value measurements, certain of the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market values due to their short-term maturities. The Company recognizes its non-financial assets and liabilities, such as ARO (see Note 14—Asset Retirement Obligations) and properties acquired in a business combination (see Note 9—Acquisitions) or upon impairment (see Note 8—Property, Plant and Equipment), at fair value on a non-recurring basis. Financial Assets and Liabilities Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis: Fair value at December 31, 2023 Level 1 Level 2 Level 3 Total (In thousands) Assets: Commodity derivative contracts (see Note 7) $ — $ 11,312 $ 5,877 $ 17,189 Contingent consideration (see Note 7) — 42,706 — 42,706 Investment in unconsolidated affiliate (see Note 12) 100,172 — — 100,172 Total assets $ 100,172 $ 54,018 $ 5,877 $ 160,067 Liabilities: Commodity derivative contracts (see Note 7) $ — $ 14,926 $ — $ 14,926 Total liabilities $ — $ 14,926 $ — $ 14,926 Fair value at December 31, 2022 Level 1 Level 2 Level 3 Total (In thousands) Assets: Commodity derivative contracts (see Note 7) $ — $ 780 $ — $ 780 Contingent consideration (see Note 7) — 60,920 — 60,920 Investment in unconsolidated affiliate (see Note 12) 130,575 — — 130,575 Total assets $ 130,575 $ 61,700 $ — $ 192,275 Liabilities: Commodity derivative contracts (see Note 7) $ — $ 329,676 $ 14,694 $ 344,370 Total liabilities $ — $ 329,676 $ 14,694 $ 344,370 Commodity derivative contracts. The Company enters into commodity derivative contracts to manage risks related to changes in crude oil, NGL and natural gas prices. The Company’s swaps, collars and basis swaps are valued by a third-party preparer based on an income approach. The significant inputs used are commodity prices, discount rate and the contract terms of the derivative instruments. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace and are therefore designated as Level 2 within the fair value hierarchy. The Company compares the valuation performed by the third-party preparer to counterparty valuation statements to assess the reasonableness of its valuation. The determination of the fair value also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculates the credit adjustment for derivatives in a net asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a net liability position is based on the market credit spread of the Company or similarly rated public issuers. The Company recorded an adjustment to reduce the fair value of its net derivative liability for these contracts by $0.5 million at December 31, 2023 by $3.5 million at December 31, 2022. See Note 7—Derivative Instruments for additional information. Transportation derivative contracts. The Company acquired two buy/sell transportation contracts in the Merger that are derivative contracts for which the Company has not elected the “normal purchase normal sale” exclusion under FASB ASC 815, Derivatives and Hedging . These transportation derivative contracts are valued by a third-party preparer based on an income approach. The significant inputs used are quoted forward prices for commodities, market differentials for crude oil and either the Company’s or the counterparty’s nonperformance risk, as appropriate. The assumptions used in the valuation of these contracts include certain market differential metrics that are unobservable during the term of the contracts. Such unobservable inputs are significant to the contract valuation methodology, and the contracts’ fair values are therefore designated as Level 3 within the fair value hierarchy. See Note 7—Derivative Instruments for additional information. Contingent consideration. In June 2021, the Company completed the divestiture of oil and gas properties in the Texas region of the Permian Basin. In connection with the divestiture, the Company is entitled to receive up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX West Texas Intermediate crude oil price index (“NYMEX WTI”) exceeds $60 per barrel for such year (the “Permian Basin Sale Contingent Consideration”). If NYMEX WTI for calendar year 2023 or 2024 is less than $45 per barrel, then each calendar year thereafter the buyer’s obligation to make any remaining earn-out payments is terminated. The fair value of the Permian Basin Sale Contingent Consideration is determined by a third-party preparer using a Monte Carlo simulation model and Ornstein-Uhlenbeck pricing process. The significant inputs include NYMEX WTI forward price curve, volatility, mean reversion rate and counterparty credit risk adjustment. The Company determined these were Level 2 fair value inputs that are substantially observable in active markets or can be derived from observable data. In January 2024, the Company received $25.0 million related to the 2023 earn-out payment. See Note 7—Derivative Instruments for additional information. Investment in unconsolidated affiliate. In connection with the OMP Merger (defined in Note 10—Divestitures), the Company received common units in Crestwood which are accounted for using the fair value option under FASB ASC 825-10, Financial Instruments . On November 3, 2023, Energy Transfer completed their acquisition of Crestwood. The fair value of the Company’s investment was determined using Level 1 inputs based upon the quoted market price of Energy Transfer’s publicly traded common units at December 31, 2023 and Crestwood’s publicly traded common units at December 31, 2022. See Note 12—Investment in Unconsolidated Affiliate for additional information. Non-Financial Assets and Liabilities The fair value of the Company’s non-financial assets measured at fair value on a non-recurring basis is determined using valuation techniques that include Level 3 inputs. Asset retirement obligations. The initial measurement of ARO at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, environmental and regulatory environments. Oil and gas and other properties. The Company records its properties at fair value when acquired in a business combination or upon impairment for proved oil and gas properties and other properties. Fair value is determined using a discounted cash flow model. The inputs used are subject to management’s judgment and expertise and include, but are not limited to, future production volumes based upon estimates of proved reserves, future commodity prices (adjusted for basis differentials), estimates of future operating and development costs and a risk-adjusted discount rate. These inputs are classified as Level 3 inputs, except the underlying commodity price assumptions are based on NYMEX forward strip prices (Level 1) and adjusted for price differentials. 2023 Williston Basin Acquisition. On June 30, 2023, the Company completed the 2023 Williston Basin Acquisition (defined in Note 9—Acquisitions). The assets acquired and liabilities assumed were recorded at fair value as of June 30, 2023. The fair value of the oil and gas properties acquired was calculated using an income approach based on the net discounted future cash flows from the oil and gas properties. The inputs utilized in the valuation of the oil and gas properties acquired included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included estimates of future oil and gas production from the properties’ reserve reports, commodity prices based on forward strip price curves (adjusted for basis differentials), operating and development costs, expected future development plans for the properties and the utilization of a discount rate based on a market-based weighted-average cost of capital. The Company also recorded the ARO assumed from the 2023 Williston Basin Acquisition at fair value. The inputs utilized in valuing the ARO were mostly Level 3 unobservable inputs, including estimated economic lives of oil and natural gas wells as of June 30, 2023, anticipated future plugging and abandonment costs and an appropriate credit-adjusted risk-free rate to discount such costs. See Note 9—Acquisitions for additional information. Whiting merger. On July 1, 2022, the Company completed the Merger with Whiting. The assets acquired and liabilities assumed were recorded at fair value as of July 1, 2022. The fair value of Whiting’s oil and gas properties was calculated using an income approach based on the net discounted future cash flows from the producing properties and related assets. The inputs utilized in the valuation of the oil and gas properties and related assets acquired included mostly unobservable inputs which fall within Level 3 of the fair value hierarchy. Such inputs included future production volumes based upon estimates of reserves prepared by the Company’s reserve engineers, future operating and development costs, future commodity prices (adjusted for basis differentials) and a market-based weighted average cost of capital discount rate. The Company also recorded the asset retirement obligations assumed from Whiting at fair value. The inputs utilized in valuing the asset retirement obligations were mostly Level 3 unobservable inputs, including estimated economic lives of oil and natural gas wells as of July 1, 2022, anticipated future plugging and abandonment costs and an appropriate credit-adjusted risk-free rate to discount such costs. See Note 9—Acquisitions for additional information.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments Commodity derivative contracts. The Company utilizes derivative financial instruments to manage risks related to changes in commodity prices. The Company’s crude oil contracts settle monthly based on the average NYMEX WTI, and its natural gas contracts settle monthly based on the average NYMEX Henry Hub natural gas index price (“NYMEX HH”). The Company utilizes derivative financial instruments including fixed-price swaps and two-way and three-way collars to manage risks related to changes in commodity prices. The Company’s fixed-price swaps are designed to establish a fixed price for the volumes under contract. Two-way collars are designed to establish a minimum price (floor) and a maximum price (ceiling) for the volumes under contract. Three-way collars are designed to establish a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the index price plus the difference between the purchased put and the sold call strike price. The sold call establishes a maximum price (ceiling) for the volumes under contract. The Company may, from time to time, restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts. 2021 derivative contract modifications. During 2021, the Company entered into a series of transactions with derivative counterparties to modify the swap price of certain commodity derivative contracts. The Company modified the strike price of its 2022 crude oil swap contracts to $70.00 per barrel from a weighted average price of $40.89 per barrel and its 2023 crude oil swap contracts to $50.00 per barrel from a weighted average price of $43.68 per barrel. The commodity contracts modified included total notional volumes of 6,935 MBbl which settled in 2022 and 5,110 MBbl which settled in 2023. The Company paid $220.9 million to modify these commodity derivative contracts, which is reflected as a cash outflow from investing activities in the Consolidated Statement of Cash Flows for the year ended December 31, 2021. At December 31, 2023, the Company had the following outstanding commodity derivative contracts: Commodity Settlement Derivative Volumes Weighted Average Prices Fixed-Price Swaps Sub-Floor Floor Ceiling Crude oil 2024 Two-way collars 4,660,000 Bbls $ 64.31 $ 83.89 Crude oil 2024 Three-way collars 736,000 Bbls $ 55.00 $ 71.25 $ 92.14 Crude oil 2024 Fixed-price swaps 366,000 Bbls $ 69.27 Crude oil 2025 Two-way collars 1,181,000 Bbls $ 60.00 $ 79.05 Crude oil 2025 Three-way collars 1,276,000 Bbls $ 50.71 $ 65.71 $ 82.60 Natural gas 2025 Fixed-price swaps 651,600 MMBtu $ 3.93 Subsequent to December 31, 2023, the Company entered into the following commodity derivative contracts: Weighted Average Prices Commodity Settlement Period Derivative Instrument Volumes Sub-Floor Floor Ceiling Crude oil 2024 Two-way collars 825,000 Bbls $ 66.65 $ 81.94 Crude oil 2025 Three-way collars 1,095,000 Bbls $ 55.00 $ 70.00 $ 81.62 Crude oil 2026 Three-way collars 270,000 Bbls $ 50.00 $ 65.00 $ 83.70 Transportation derivative contracts. The Company acquired two contracts in the Merger that provide for the transportation of crude oil through a buy/sell structure from North Dakota to either Cushing, Oklahoma or Guernsey, Wyoming. The Company determined that these contracts qualified as derivatives and did not elect the “normal purchase normal sale” exclusion. As of December 31, 2023, the term of one of these contracts expired. The remaining contract requires the purchase and sale of fixed volumes of crude oil through July 2024 as specified in the agreement. As of December 31, 2023, the estimated fair value of the remaining contract was a $5.9 million asset, which was classified as a current derivative asset on the Company’s Consolidated Balance Sheet. As of December 31, 2022, the estimated fair value of these contracts was a $14.7 million liability, of which $11.9 million was classified as a current derivative liability and $2.8 million was classified as a non-current derivative liability on the Company’s Consolidated Balance Sheet. The Company records the changes in fair value of these contracts to gathering, processing and transportation (“GPT”) expenses on the Company’s Consolidated Statement of Operations. Settlements on these contracts are reflected as operating activities on the Company’s Consolidated Statements of Cash Flows and represent cash payments to the counterparties for transportation of crude oil or the net settlement of contract liabilities if the transportation was not utilized, as applicable. See Note 6—Fair Value Measurements for additional information. Contingent consideration. The Company bifurcated the Permian Basin Sale Contingent Consideration from the host contract and accounted for it separately at fair value. The fair value of the Permian Basin Sale Contingent Consideration was estimated to be $32.9 million as of the close date of the Permian Basin Sale (defined in Note 10—Divestitures). The Permian Basin Sale Contingent Consideration is marked-to-market each reporting period, with changes in fair value recorded in the other income (expense) section of the Company’s Consolidated Statements of Operations as a net gain or loss on derivative instruments. As of December 31, 2023, the estimated fair value of the Permian Basin Sale Contingent Consideration was $42.7 million, of which $22.6 million was classified as a current derivative asset and $20.1 million was classified as a non-current derivative asset on the Consolidated Balance Sheet. See Note 6—Fair Value Measurements and Note 10—Divestitures for additional information. The following table summarizes the location and amounts of gains and losses from the Company’s derivative instruments recorded in the Company’s Consolidated Statements of Operations for the periods presented: Year Ended December 31, Derivative Instrument Statement of Operations Location 2023 2022 2021 (In thousands) Commodity derivatives Net gain (loss) on derivative instruments $ 56,396 $ (224,238) $ (601,591) Commodity derivatives (buy/sell transportation contracts) Gathering, processing and transportation expenses (1) 20,570 7,331 — Contingent consideration Net gain (loss) on derivative instruments 6,786 16,110 11,950 Contingent consideration Gain on sale of assets, net — — 32,860 __________________ (1) The change in the fair value of the transportation derivative contracts was recorded as a gain in GPT expenses for the year ended December 31, 2023. In accordance with the FASB’s authoritative guidance on disclosures about offsetting assets and liabilities, the Company is required to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting agreement. The Company’s derivative instruments are presented as assets and liabilities on a net basis by counterparty, as all counterparty contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, gross amounts are offset to determine the net amounts presented in the Company’s Consolidated Balance Sheets. The following tables summarize the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Consolidated Balance Sheets: December 31, 2023 Derivative Instrument Balance Sheet Location Gross Amount Gross Amount Offset Net Amount (In thousands) Derivatives assets: Commodity derivatives Derivative instruments — current assets $ 20,647 $ (11,769) $ 8,878 Contingent consideration Derivative instruments — current assets 22,614 — 22,614 Commodity derivatives (buy/sell transportation contracts) Derivative instruments — current assets 5,877 — 5,877 Commodity derivatives Derivative instruments — non-current assets 16,760 (14,326) 2,434 Contingent consideration Derivative instruments — non-current assets 20,092 — 20,092 Total derivatives assets $ 85,990 $ (26,095) $ 59,895 Derivatives liabilities: Commodity derivatives Derivative instruments — current liabilities $ 25,978 $ (11,769) $ 14,209 Commodity derivatives Derivative instruments — non-current liabilities 15,043 (14,326) 717 Total derivatives liabilities $ 41,021 $ (26,095) $ 14,926 December 31, 2022 Derivative Instrument Balance Sheet Location Gross Amount Gross Offset Amount Net Amount (In thousands) Derivatives assets: Commodity derivatives Derivative instruments — current assets $ 10,194 $ (9,414) $ 780 Contingent consideration Derivative instruments — current assets 22,955 — 22,955 Contingent consideration Derivative instruments — non-current assets 37,965 — 37,965 Total derivatives assets $ 71,114 $ (9,414) $ 61,700 Derivatives liabilities: Commodity derivatives Derivative instruments — current liabilities $ 339,090 $ (9,414) $ 329,676 Commodity derivatives (buy/sell transportation contracts) Derivative instruments — current liabilities 11,865 — 11,865 Commodity derivatives (buy/sell transportation contracts) Derivative instruments — non-current liabilities 2,829 — 2,829 Total derivatives liabilities $ 353,784 $ (9,414) $ 344,370

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment The following table sets forth the Company’s property, plant and equipment: December 31, 2023 2022 (In thousands) Proved oil and gas properties $ 6,220,766 $ 5,089,185 Less: Accumulated depletion (1,035,393) (461,175) Proved oil and gas properties, net 5,185,373 4,628,010 Unproved oil and gas properties 99,477 30,936 Other property and equipment 49,051 72,973 Less: Accumulated depreciation and impairment (19,223) (20,576) Other property and equipment, net 29,828 52,397 Total property, plant and equipment, net $ 5,314,678 $ 4,711,343 Impairment The Company reviews its property, plant and equipment for impairment by asset group whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. If events occur that indicate an asset group may not be recoverable, the asset group is tested for recoverability. Proved oil and gas properties. The Company estimates the expected undiscounted future cash flows of its proved oil and gas properties by field and then compares such amount to the carrying amount of the proved oil and gas properties in the applicable field to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company adjusts the carrying amount of the proved oil and gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production volume estimates, the timing and pace of development, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows. These assumptions represent Level 3 inputs, as further discussed under Note 6—Fair Value Measurements. During the year ended December 31, 2023, the Company recorded impairment charges of $5.6 million, primarily related to the Non-core Asset Sales (defined in Note 10—Divestitures). For the years ended 2022 and 2021, the Company did not record impairment of proved oil and gas properties. Unproved oil and gas properties. For the years ended December 31, 2023, 2022 and 2021, the Company did not record impairment of unproved oil and gas properties. Other property and equipment. The Company reviews its other property and equipment for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. For the years ended December 31, 2023, 2022 and 2021, the Company did not record impairment of other property and equipment.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
Acquisitions	Acquisitions 2023 Acquisition On May 22, 2023, the Company announced that a wholly-owned subsidiary of the Company had entered into a definitive agreement to acquire approximately 62,000 net acres in the Williston Basin from XTO Energy Inc. and affiliates, each a subsidiary of Exxon Mobil Corporation (collectively “XTO”), for total cash consideration of $375.0 million, subject to customary purchase price adjustments (the “2023 Williston Basin Acquisition”). The effective date of the 2023 Williston Basin Acquisition was April 1, 2023. On June 30, 2023, the Company completed the 2023 Williston Basin Acquisition for total cash consideration of $361.6 million, including a deposit of $37.5 million paid to XTO upon execution of the purchase and sale agreement and $324.1 million paid to XTO at closing (including customary purchase price adjustments). The Company funded the 2023 Williston Basin Acquisition with cash on hand. The 2023 Williston Basin Acquisition was accounted for as a business combination and was recorded under the acquisition method of accounting in accordance with ASC 805. The post-acquisition operating results and pro forma revenue and earnings for the 2023 Williston Basin Acquisition were not material to the Company’s consolidated financial statements and have therefore not been presented. Purchase price allocation. The Company recorded the assets acquired and liabilities assumed in the 2023 Williston Basin Acquisition at their estimated fair value on June 30, 2023 of $361.6 million. The allocation of the fair value to the identifiable assets acquired and liabilities assumed resulted in no goodwill or bargain purchase gain being recognized. Determining the fair value of the assets and liabilities of the 2023 Williston Basin Acquisition required judgement and certain assumptions to be made. See Note 6—Fair Value Measurements for additional information. The tables below present the total consideration transferred and its allocation to the identifiable assets acquired and liabilities assumed as of the acquisition date on June 30, 2023. As provided under ASC 805, the purchase price allocation may be subject to change for up to one year after June 30, 2023, which may result in a different allocation than what is presented in the tables below. As of December 31, 2023, the purchase price was finalized with an immaterial adjustment to the preliminary purchase price allocation. Purchase Price Consideration (In thousands) Cash consideration transferred $ 361,609 Preliminary Purchase Price Allocation (In thousands) Assets acquired: Oil and gas properties $ 367,672 Inventory 1,844 Total assets acquired $ 369,516 Liabilities assumed: Asset retirement obligations $ 6,771 Revenue and production taxes payable 1,136 Total liabilities assumed $ 7,907 Net assets acquired $ 361,609 2022 Acquisitions On March 7, 2022, Oasis and Whiting entered into an Agreement and Plan of Merger (the “Merger Agreement”), which provided for, among other things, the combination of Oasis and Whiting in a merger of equals transaction. On July 1, 2022, the Company completed the Merger with Whiting and issued 22,671,871 shares of common stock and paid $245.4 million of cash to Whiting stockholders. Also on July 1, 2022 and pursuant to the Merger Agreement, the Company (i) assumed the outstanding Whiting Series A Warrants and Whiting Series B Warrants, (ii) assumed the outstanding Whiting equity-based compensation awards and (iii) paid cash to satisfy and discharge in full the Whiting credit facility. Purchase price allocation. The Company recorded the assets acquired and liabilities assumed in the Merger at their estimated fair value on July 1, 2022 of $2.8 billion. The allocation of the fair value to the identifiable assets acquired and liabilities assumed resulted in no goodwill or bargain purchase gain being recognized. Determining the fair value of the assets and liabilities of Whiting required judgement and certain assumptions to be made. See Note 6—Fair Value Measurements for additional information. The tables below present the total consideration transferred and its preliminary allocation to the identifiable assets acquired and liabilities assumed as of the acquisition date on July 1, 2022. As of December 31, 2023, the purchase price was finalized with no adjustment to the preliminary purchase price allocation. Purchase Price Consideration (In thousands) Common stock issued to Whiting stockholders (1) $ 2,478,036 Cash paid to Whiting stockholders (1) 245,436 Replacement of Whiting Series A Warrants and Whiting Series B Warrants (2) 79,774 Replacement of Whiting equity-based compensation awards (3) 27,402 Cash paid to settle Whiting credit facility (4) 2,154 Total consideration transferred $ 2,832,802 __________________ (1) The Company issued 22,671,871 shares of common stock and paid $245.4 million of cash to Whiting stockholders as Merger consideration. Each holder of Whiting common stock received 0.5774 shares of common stock as share consideration and $6.25 of cash as cash consideration. The fair value of the common stock issued was based on the closing price of the Company’s common stock on July 1, 2022 of $109.30. See Note 17—Stockholders’ Equity for additional information. (2) The Company assumed (i) 4,833,455 Whiting Series A Warrants and (ii) 2,418,832 Whiting Series B Warrants. The replacement of Whiting Series A and B Warrants was based on the closing price of the warrants on July 1, 2022 of $11.25 and $10.50, respectively. See Note 17—Stockholders’ Equity for additional information. (3) The Whiting equity awards were replaced with awards issued by Chord with similar terms and conditions as the original awards. The fair value of the replacement equity awards attributable to pre-Merger service was recorded as consideration transferred. See Note 16— Equity-Based Compensation for additional information. (4) On July 1, 2022, the Company fully satisfied all obligations under the Whiting credit facility and the Whiting credit facility was concurrently terminated. See Note 13—Long-Term Debt for additional information. Purchase Price Allocation (In thousands) Assets acquired: Cash and cash equivalents $ 94,641 Accounts receivable, net 491,514 Inventory 35,256 Prepaid expenses 14,851 Other current assets 5,719 Current assets held for sale 16,074 Oil and gas properties 3,211,043 Other property and equipment 31,244 Long-term inventory 3,138 Operating right-of-use assets 15,752 Deferred tax assets 228,574 Other assets 3,346 Total assets acquired $ 4,151,152 Liabilities assumed: Accounts payable $ 116,769 Revenues and production taxes payable 411,553 Accrued liabilities 215,218 Derivatives instruments (current liability) 471,693 Current operating lease liabilities 2,629 Other current liabilities 2,902 Current liabilities held for sale 9,410 Asset retirement obligations 57,197 Derivative instruments (long-term liability) 15,128 Operating lease liabilities 13,123 Other liabilities 2,728 Total liabilities assumed $ 1,318,350 Net assets acquired $ 2,832,802 Post-merger operating results. The results of operations of Whiting have been included in the Company’s consolidated financial statements since the closing of the Merger on July 1, 2022. The following table summarizes the total revenues and income from continuing operations before income taxes attributable to Whiting that were recorded in the Company’s Consolidated Statement of Operations for the period presented. Year Ended December 31, 2022 (In thousands) Revenues $ 1,044,079 Income from continuing operations before income taxes 553,686 Other information. The Company recorded an assumed liability of $18.0 million in accrued liabilities on the Consolidated Balance Sheet as of July 1, 2022 related to success-based transaction costs that were incurred by Whiting prior to the consummation of the Merger. These amounts were paid during the year ended December 31, 2022. In addition, the Company recorded an assumed liability of $55.0 million in accrued liabilities on the Consolidated Balance Sheet as of July 1, 2022 related to a loss contingency from a legal proceeding with Arguello Inc. and Freeport-McMoRan Oil & Gas LLC that the Company determined was both probable and reasonably estimable under FASB ASC 450-20, Loss Contingencies as of the consummation of the Merger. See Note 21—Commitments and Contingencies for additional information. Unaudited pro forma financial information. Summarized below are the consolidated results of operations for the periods presented, on an unaudited pro forma basis, as if the Merger had occurred on January 1, 2021. The information presented below reflects pro forma adjustments based on available information and certain assumptions that the Company believes are factual and supportable. The pro forma financial information includes certain non-recurring pro forma adjustments that were directly attributable to the Merger, including transaction costs incurred by the Company and Whiting. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the Merger occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results. The pro forma results of operations do not include any future cost savings or other synergies that may result from the Merger or any estimated costs that have not yet been incurred by the Company to integrate the Whiting assets. Year Ended December 31, 2022 2021 (In thousands) Revenues $ 4,759,706 $ 3,113,407 Net income attributable to Chord 2,093,776 477,184 Net income attributable to Chord per share: Basic $ 50.00 $ 11.21 Diluted 47.88 10.93 2021 Acquisitions 2021 Williston Basin Acquisition. On October 21, 2021, the Company completed the acquisition of approximately 95,000 net acres in the Williston Basin, effective April 1, 2021, from QEP Energy Company (“QEP”), a wholly-owned subsidiary of Diamondback Energy Inc., for total cash consideration of $585.8 million (the “2021 Williston Basin Acquisition”). The Company paid a deposit to QEP of $74.5 million on May 3, 2021 and $511.3 million at closing on October 21, 2021. The Company funded the 2021 Williston Basin Acquisition with cash on hand, including proceeds from the Permian Basin Sale (defined in Note 10 — Divestitures ) and the Senior Notes (defined in Note 13—Long-Term Debt).

Divestitures

Divestitures	12 Months Ended
	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
Divestitures	Divestitures 2023 Divestitures Non-core properties. During the year ended December 31, 2023, the Company entered into separate agreements with multiple buyers to sell a vast majority of its non-core properties located outside of the Williston Basin (the “Non-core Asset Sales”). As of December 31, 2023, the Company completed these Non-core Asset Sales and received total net cash proceeds (including purchase price adjustments) of $39.1 million, subject to customary post-closing adjustments. During the year ended December 31, 2023, the Company recorded a pre-tax net loss on sale of assets of $8.4 million for the Non-core Asset Sales During the year ended December 31, 2023, the Company recorded an impairment loss of $5.6 million to adjust the carrying value of the assets held for sale to their estimated fair value less costs to sell. The impairment loss was recorded within exploration and impairment expenses on the Consolidated Statements of Operations. Other divestitures. In addition, during the year ended December 31, 2023, the Company completed certain non-operated wellbore divestitures in the Williston Basin for total net cash proceeds of $12.1 million. 2022 Divestitures OMP Merger. On February 1, 2022, the Company completed the merger of Oasis Midstream Partners LP (“OMP”), a master limited partnership formed by the Company to own, develop, operate and acquire midstream assets in North America, and OMP GP, the general partner of OMP, with Crestwood and Crestwood Equity GP LLC, a Delaware limited liability company, and Crestwood GP, the general partner of Crestwood. The Company merged OMP into a subsidiary of Crestwood and exchanged all of its OMP common units and all of the limited liability company interests of OMP GP for $160.0 million in cash and 20,985,668 common units of Crestwood (the “OMP Merger”). The OMP Merger represented a strategic shift for the Company and qualified for reporting as discontinued operations under ASC 205-20. See Note 11—Discontinued Operations for additional information. Immediately prior to the completion of the OMP Merger, the Company owned approximately 70% of OMP’s issued and outstanding common units. The Company recorded a pre-tax gain on sale of assets of $518.9 million, which included (i) the cash consideration of $160.0 million, (ii) the fair value of the Company’s retained investment in Crestwood of $568.3 million; less (iii) the book value of the Company’s investment in OMP of $198.0 million and (iv) transaction costs of $11.4 million. The gain on sale of assets was reported within income from discontinued operations attributable to Chord, net of income tax on the Company’s Consolidated Statement of Operations for the year ended December 31, 2022. Prior to the OMP Merger, OMP’s long-term debt consisted of $203.0 million of borrowings outstanding and $5.5 million of outstanding letters of credit issued under the OMP Credit Facility and $450.0 million of 8.00% senior unsecured notes due April 1, 2029 (the “OMP Senior Notes”). Upon consummation of the OMP Merger on February 1, 2022, Crestwood assumed the obligations pursuant to the OMP Senior Notes and paid in full all amounts due under the OMP Credit Facility. The Company had previously entered into several long-term, fee-based contractual arrangements with OMP for midstream services, including (i) natural gas gathering, compression, processing and gas lift supply services; (ii) crude oil gathering, terminaling and transportation services; (iii) produced and flowback water gathering and disposal services; and (iv) freshwater distribution services. In connection with the closing of the OMP Merger, these contracts were assigned to Crestwood, and the Company has continuing cash outflows to Crestwood for these services. On November 3, 2023, Energy Transfer completed their acquisition of Crestwood, and holders of Crestwood common units received 2.07 Energy Transfer common units for each Crestwood unit held. See Note 12—Investment in Unconsolidated Affiliate for additional information. Rio Blanco County Divestiture . On July 14, 2022, the Company completed the divestiture of its interests in various assets, including producing wells and an equity interest in a pipeline in Rio Blanco County, Colorado, for an aggregate sales price of $8.0 million (the “Rio Blanco County Divestiture”). No gain or loss was recognized for this sale. The net assets from the Rio Blanco County Divestiture were measured at fair value and classified as held-for-sale upon consummation of the Merger on July 1, 2022. 2021 Divestitures Permian Basin Sale. On May 20, 2021, Oasis Petroleum Permian LLC (“OP Permian”), a wholly-owned subsidiary of the Company, entered into a purchase and sale agreement (the “Permian Basin Sale PSA”) with Percussion Petroleum Operating II, LLC (“Percussion”). Pursuant to the Permian Basin Sale PSA, OP Permian agreed to sell to Percussion its remaining upstream assets in the Texas region of the Permian Basin with an effective date of March 1, 2021, for an aggregate purchase price of $450.0 million (the “Permian Basin Sale”). The aggregate purchase price consisted of $375.0 million in cash at closing and up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 (see Note 6—Fair Value Measurements for additional information). The Company completed the Permian Basin Sale on June 29, 2021 and received cash proceeds of $342.3 million. In addition, the Company divested certain wellbore interests in the Texas region of the Permian Basin to separate buyers in the second quarter of 2021 and received cash proceeds of $30.0 million. Well services . On March 22, 2021, the Company completed the sale of certain well services equipment and inventory in connection with its 2020 exit from the well services business for total consideration of $5.5 million, comprised of cash proceeds of $2.6 million and a $2.9 million promissory note. As of December 31, 2023, the remaining principal balance on the promissory note was immaterial. Midstream Simplification. On March 30, 2021, the Company contributed to OMP its remaining 64.7% limited liability company interest in Bobcat DevCo LLC and 30.0% limited liability company interest in Beartooth DevCo LLC, as well as eliminated OMP’s incentive distribution rights, in exchange for a cash distribution of $231.5 million and 12,949,644 common units in OMP (the “Midstream Simplification”). The Midstream Simplification was accounted for as a transaction between entities under common control.

Discontinued Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2023
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	Discontinued Operations The OMP Merger qualified for reporting as discontinued operations on February 1, 2022, in accordance with ASC 205-20. There were no discontinued operations for the year ended December 31, 2023. Consolidated Statements of Operations The results of operations reported as discontinued operations in connection with the OMP Merger were as follows for the periods presented: Year Ended December 31, (In thousands) 2022 2021 Revenues Oil and gas revenues $ — $ 1,013 Purchased oil and gas sales (1) (13,364) (131,369) Midstream revenues 23,271 254,228 Total revenues 9,907 123,872 Operating expenses Lease operating expenses (1) (4,535) (62,142) Midstream expenses 13,224 122,040 Gathering, processing and transportation expenses (1) (3,555) (49,795) Purchased oil and gas expenses (1) (12,506) (125,709) Depreciation, depletion and amortization — 31,868 Impairment — 2 General and administrative expenses (1) 3,314 4,193 Total operating expenses (4,058) (79,543) Gain on sale of assets 518,900 — Operating income 532,865 203,415 Other expense Interest expense, net of capitalized interest (3,685) (36,945) Other expense (93) (115) Total other expense, net (3,778) (37,060) Income from discontinued operations before income taxes 529,087 166,355 Income tax expense (2) (101,080) (17) Income from discontinued operations, net of income tax 428,007 166,338 Net income attributable to non-controlling interests 2,311 35,696 Income from discontinued operations attributable to Chord, net of income tax $ 425,696 $ 130,642 __________________ (1) Includes discontinued intercompany eliminations. (2) The Company applied the intraperiod tax allocation rules in accordance with FASB ASC 740-20, Intraperiod Tax Allocation (“ASC 740-20”) to determine the allocation of tax expense between continuing operations and discontinued operations. ASC 740-20 generally requires the allocation of tax expense to be based on a comparative calculation of tax expense with and without income from discontinued operations. During the year ended December 31, 2022, the Company released a portion of its valuation allowance (see Note 15—Income Taxes for additional information) and allocated the majority of the income tax benefit associated with this valuation allowance release to continuing operations. The total tax expense associated with the OMP Merger was partially offset by the release of the Company’s valuation allowance allocated to discontinued operations, resulting in a tax expense of $101.1 million attributable to discontinued operations during the year ended December 31, 2022. Consolidated Statements of Cash Flows There was no DD&A from discontinued operations included in “Cash flows from operating activities” for the year ended December 31, 2022. DD&A from discontinued operations of $31.9 million was included in “Cash flows from operating activities” for the year ended December 31, 2021. Capital expenditures attributable to discounted operations included in “Cash flows used in investing activities” were $6.1 million for the year ended December 31, 2022 and $38.5 million for the year ended December 31, 2021. There were no significant non-cash activities from discontinued operations for the periods presented.

Investment in Unconsolidated Af

Investment in Unconsolidated Affiliate	12 Months Ended
	Dec. 31, 2023
Equity Method Investments and Joint Ventures [Abstract]
Investment in Unconsolidated Affiliate	Investment in Unconsolidated Affiliate On February 1, 2022, the Company completed the OMP Merger and received 20,985,668 Crestwood common units. In August 2023, Crestwood and Energy Transfer entered into a definitive merger agreement to which Energy Transfer would acquire Crestwood. On November 3, 2023, Energy Transfer completed their acquisition of Crestwood, and holders of Crestwood common units received 2.07 Energy Transfer common units for each Crestwood unit held. The Company has continued to record its investment in Energy Transfer using the fair value option. Additionally, no gain or loss was recorded in the Consolidated Statements of Operations as a result of this merger. As of December 31, 2023 and 2022, the fair value of the Company’s investment was $100.2 million and $130.6 million, respectively. As of December 31, 2023, the Company owned less than 5% of Energy Transfer’s issued and outstanding common units. The carrying amount of the Company’s investment in Energy Transfer is recorded to investment in unconsolidated affiliate on the Consolidated Balance Sheet. During the year ended December 31, 2023, the Company recorded a net gain of $21.3 million on its investment, primarily comprised of a realized gain for cash distributions received of $10.8 million and an unrealized gain for the change in fair value of the investment of $8.4 million. During the year ended December 31, 2022, the Company recorded an unrealized loss for the change in the fair value of its investment of $52.5 million, a realized gain of $43.0 million for the sale of 16,000,000 common units and a realized gain of $43.9 million for cash distributions from Crestwood for the Company’s ownership of common units. Related Party Transactions For the year ended December 31, 2022, related party transactions with Crestwood totaled $15.7 million of revenues, $69.5 million of lease operating expenses and $56.6 million of GPT expenses. On September 12, 2022, the Company sold an aggregate of 16,000,000 common units of Crestwood in separate transactions and received net proceeds of $428.2 million. The sale reduced the Company’s ownership of Crestwood’s issued and outstanding common units below 5%. As such, Crestwood was no longer considered a related party as of December 31, 2022.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt The Company’s long-term debt consists of the following: December 31, 2023 2022 (In thousands) Senior secured revolving line of credit $ — $ — Senior unsecured notes 400,000 400,000 Less: unamortized deferred financing costs (4,098) (5,791) Total long-term debt, net $ 395,902 $ 394,209 Senior secured revolving line of credit. The Company has a senior secured revolving credit facility (the “Credit Facility”) with a $2.5 billion borrowing base and $1.0 billion of elected commitments that matures on July 1, 2027. At December 31, 2023, the Company had no borrowings outstanding and $8.9 million of outstanding letters of credit issued under the Credit Facility, resulting in an unused borrowing capacity of $991.1 million. At December 31, 2022, the Company had no borrowings outstanding and $6.4 million of outstanding letters of credit issued under the Credit Facility. For the years ended December 31, 2023 and 2022, the weighted average interest rate incurred on borrowings under the Credit Facility was 7.1% and 4.6%, respectively. The Company was in compliance with the financial covenants under the Credit Facility at December 31, 2023. Borrowings are subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a Term SOFR Loan or an ABR Loan (each as defined in the Credit Facility). The Company incurs interest on outstanding Term SOFR Loans or ABR Loans at their respective interest rate plus the margin shown in the table below plus a 0.1% credit spread adjustment applicable to Term SOFR Loans. In addition, the unused borrowing base is subject to a commitment fee as shown in the table below: Total Revolving Commitment Utilization Percentage ABR Loans SOFR Loans Commitment Fee Less than 25% 0.75 % 1.75 % 0.375 % Greater than or equal to 25% but less than 50% 1.00 % 2.00 % 0.375 % Greater than or equal to 50% but less than 75% 1.25 % 2.25 % 0.500 % Greater than or equal to 75% but less than 90% 1.50 % 2.50 % 0.500 % Greater than or equal to 90% 1.75 % 2.75 % 0.500 % The Credit Facility is restricted to a borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year, with one interim redetermination available to each of the Company and the administrative agent between scheduled redeterminations during any 12-month period. In connection with the consummation of the Merger on July 1, 2022, the Company entered into the Amended and Restated Credit Agreement. The Company completed two amendments to the Amended and Restated Credit Agreement during 2023, as follows: (i) on May 2, 2023, the Company completed its semi-annual borrowing base redetermination and entered into the Third Amendment to Amended and Restated Credit Agreement to reduce the borrowing base to $2.5 billion from $2.75 billion; and (ii) on October 31, 2023, the Company completed its semi-annual borrowing base redetermination and entered into the Fourth Amendment to Amended and Restated Credit Agreement (the “Fourth Amendment”). The Fourth Amendment, among other things (i) reaffirmed the borrowing base of $2.5 billion and maintained the aggregate amount of elected commitments of $1.0 billion and (ii) permits the borrower to incur term loans in addition to the revolving loans provided under the Amended and Restated Credit Agreement, subject to terms to be agreed with the lenders making such term loans and to the terms of the Amended and Restated Credit Agreement. The next scheduled redetermination is expected to occur in or around April 2024. A portion of the Credit Facility, in an aggregate amount not to exceed $100.0 million, may be used for the issuance of letters of credit. Additionally, the Credit Facility provides the ability for the Company to request swingline loans subject to a swingline loans sublimit of $50.0 million. Borrowings under the Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the assets of Chord, as parent, Oasis Petroleum North America LLC (“OPNA”), as borrower, and certain of the Company’s subsidiaries, as guarantors, including mortgage liens on oil and gas properties having at least 85% of the reserve value as determined by reserve reports. A loan may be repaid at any time before the scheduled maturity of the Credit Facility upon the Company providing advance notification to the lenders. The Credit Facility contains customary affirmative and negative covenants, including, among other things, as to compliance with laws (including environmental laws and anti-corruption laws), delivery of quarterly and annual financial statements, conduct of business, maintenance of property, maintenance of insurance, restrictions on the incurrence of liens, indebtedness, investments, asset dispositions, fundamental changes, restricted payments, transactions with affiliates, and other customary covenants. The financial covenants in the Credit Facility include: • a requirement that the Company maintain a ratio of Total Net Debt to EBITDAX (as defined in the Credit Facility, the “Leverage Ratio”) of less than 3.50 to 1.00 as of the last day of any fiscal quarter; and • a requirement that the Company maintain a Current Ratio (as defined in the Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter. The Credit Facility contains customary events of default, as well as cross-default provisions with other indebtedness of OPNA and the restricted subsidiaries under the Credit Facility. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable. Senior unsecured notes. At December 31, 2023, the Company had $400.0 million of 6.375% senior unsecured notes outstanding due June 1, 2026 (the “Senior Notes”). The Senior Notes were issued in a private placement on June 9, 2021 at par and resulted in net proceeds of $391.6 million, after deducting the underwriters’ discounts, commissions and other expenses. The Company recorded deferred financing costs of $8.4 million, which are being amortized over the term of the Senior Notes. The proceeds were used to fund a portion of the 2021 Williston Basin Acquisition consideration. See Note 9—Acquisitions for additional information. Interest on the Senior Notes is payable semi-annually on June 1 and December 1 of each year. The Senior Notes are guaranteed on a senior unsecured basis by the Company, along with its wholly-owned subsidiaries (the “Guarantors”). These guarantees are full and unconditional and joint and several among the Guarantors, subject to certain customary release provisions. The indentures governing the Senior Notes contain customary events of default. In addition, the indenture governing the Senior Notes contains cross-default provisions with other indebtedness of the Company and its restricted subsidiaries. The indentures governing the Senior Notes restrict the Company’s ability and the ability of certain of its subsidiaries to, among other things: (i) make investments, (ii) incur additional indebtedness or issue preferred stock, (iii) create liens, (iv) sell assets, (v) enter into agreements that restrict dividends or other payments by restricted subsidiaries, (vi) consolidate, merge or transfer all or substantially all of the Company’s assets with another company, (vii) enter into transactions with affiliates, (viii) pay dividends or make other distributions on capital stock or prepay subordinated indebtedness and (ix) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Senior Notes are rated investment grade by two out of the three rating agencies and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and the Company will cease to be subject to such covenants. The Company was in compliance with the terms of the indentures for the Senior Notes as of December 31, 2023. The fair value of the Senior Notes, which are publicly traded and represent a Level 1 fair value measurement, was $400.0 million and $389.6 million at December 31, 2023 and December 31, 2022, respectively. Whiting credit facility. Whiting had a reserves-based credit facility with a syndicate of banks. Upon consummation of the Merger on July 1, 2022, the Whiting credit facility was terminated, and the Company paid the remaining outstanding accrued interest and other fees of approximately $2.2 million to satisfy and discharge in full all such outstanding obligations that were owed under the Whiting credit facility. Bridge facility. On May 3, 2021, the Company entered into a commitment letter to provide for a senior secured second lien facility and incurred a fee of $7.8 million, which was recorded to interest expense on the Company’s Consolidated Statement of Operations for the year ended December 31, 2022. The senior secured second lien facility was terminated prior to being drawn.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations The following table reflects the changes in the Company’s ARO: Year Ended December 31, 2023 2022 (In thousands) Asset retirement obligation — beginning of period $ 165,405 $ 62,416 Liabilities incurred during period 1,238 852 Liabilities incurred through acquisitions 6,771 87,265 Liabilities settled during period (4,389) (4,532) Liabilities settled through divestitures (31,844) (8,535) Accretion expense during period 11,183 7,613 Revisions to estimates 17,182 20,326 Asset retirement obligation — end of period $ 165,546 $ 165,405 At December 31, 2023 and 2022, the current portion of the total ARO balance was approximately $10.5 million and $19.4 million, respectively, and is included in accrued liabilities on the Company’s Consolidated Balance Sheets.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The Company’s income tax expense (benefit) from continuing operations consists of the following: Year Ended December 31, 2023 2022 2021 (In thousands) Current: Federal $ 15,877 $ 7,127 $ — State 3,824 883 4 Total current tax expense 19,701 8,010 4 Deferred: Federal 264,154 (46,767) (977) State 31,394 (8,127) — Total deferred tax expense (benefit) 295,548 (54,894) (977) Total income tax expense (benefit) $ 315,249 $ (46,884) $ (973) The reconciliation of income taxes from continuing operations calculated at the U.S. federal tax statutory rate to the Company’s effective tax rate is set forth below: Year Ended December 31, 2023 2022 2021 (%) (In thousands) (%) (In thousands) (%) (In thousands) U.S. federal tax statutory rate 21.0 % $ 281,196 21.0 % $ 291,068 21.0 % $ 39,477 State income taxes, net of federal income tax benefit 2.6 % 35,219 2.6 % 36,156 3.0 % 5,679 Non-deductible executive compensation 0.4 % 5,999 0.7 % 9,204 1.3 % 2,510 Change in valuation allowance — % — (27.2) % (377,233) (71.7) % (134,713) Discharge of debt and nondeductible professional fees — % — — % — 46.3 % 87,070 Other (0.5) % (7,165) (0.5) % (6,079) (0.4) % (996) Annual effective tax expense (benefit) 23.5 % $ 315,249 (3.4) % $ (46,884) (0.5) % $ (973) Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2023 and 2022 were as follows: December 31, 2023 2022 (In thousands) Deferred tax assets Net operating loss carryforward $ 318,145 $ 316,085 Derivative instruments — 72,761 Bonus and equity-based compensation 14,324 9,806 Other deferred tax assets 17,469 7,863 Total deferred tax assets 349,938 406,515 Less: Valuation allowance (9,266) (9,617) Total deferred tax assets, net $ 340,672 $ 396,898 Deferred tax liabilities Oil and natural gas properties $ 367,046 $ 117,995 Derivative instruments 3,638 — Investment in partnerships 54,452 69,867 Other deferred tax liabilities 10,858 8,810 Total deferred tax liabilities $ 435,994 $ 196,672 Total deferred tax assets (liabilities), net $ (95,322) $ 200,226 The Company’s effective tax rate for the year ended December 31, 2023 was 23.5% of pre-tax income from continuing operations, as compared to an effective tax rate of (3.4)% of pre-tax income from continuing operations for the year ended December 31, 2022. The effective tax rate from continuing operations for the year ended December 31, 2023 was higher than the statutory federal rate of 21% primarily as a result of the impact of state income taxes. The effective tax rate from continuing operations for the year ended December 31, 2022 was lower than the statutory federal rate of 21% primarily as a result of the Company’s valuation allowance, the substantial majority of which was released as of December 31, 2022. This benefit was partially offset by the impacts of state income taxes. As of December 31, 2023, the Company had gross U.S. federal net operating loss (“NOL”) carryforwards of $1,087 million, of which approximately $988.7 million will not expire and $98.3 million will expire from 2032 to 2037. In addition, the Company had gross state NOL carryforwards of $2,406 million as of December 31, 2023, which expire between 2024 and 2042. The Company and Whiting both experienced an “ownership change” as defined by the Internal Revenue Code of 1986, as amended (the “Code”), in the past, including as a result of the Merger. Accordingly, under Section 382 of the Code, the Company’s NOL carryforwards and other tax attributes (collectively, “Tax Benefits”) are subject to various limitations going forward. However, the limitations applicable under Section 382 of the Code resulting from the Merger are not expected to have a material impact on the realizability of the Company’s deferred tax assets. Tax Benefits are recorded as an asset to the extent that management assesses the utilization of such Tax Benefits to be more likely than not, and when the future utilization of some portion of the Tax Benefits is determined not to be more likely than not, then a valuation allowance is provided to reduce the Tax Benefits from such assets. The Company’s estimated valuation allowance as of December 31, 2023 was $9.3 million, which relates to state NOL carryforwards, and is approximately consistent with the valuation allowance as of December 31, 2022. Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Company had no unrecognized tax benefits as of December 31, 2023 and 2022. With respect to income taxes, the Company’s policy is to account for interest charges as interest expense and any penalties as tax expense in its Consolidated Statements of Operations. The Company files a U.S. federal income tax return and income tax returns in the various states where it operates. As the Company has NOL carryforwards from previous tax years, of which the earliest relate to the 2012 tax year, the Internal Revenue Service (“IRS”) may examine the Company’s loss years back to the 2012 tax year.

Equity-Based Compensation

Equity-Based Compensation	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Equity-Based Compensation	Equity-Based Compensation The Company has granted equity-based compensation awards under the 2020 LTIP. In accordance with the FASB’s authoritative guidance for share-based payments, the Company accounts for awards that settle in shares of common stock as equity-classified awards and awards that settle in cash as liability-classified awards. Equity-based compensation expense from continuing operations is recognized in general and administrative expenses on the Company’s Consolidated Statements of Operations, and equity-based compensation expense from discontinued operations is recognized in discontinued operations, net of income tax on the Company’s Consolidated Statements of Operations. The Company recognized $46.1 million, $61.2 million and $14.7 million in equity-based compensation expenses related to equity-classified awards that were attributable to continued operations during the years ended December 31, 2023, 2022 and 2021, respectively. Equity-based compensation expenses related to liability-classified awards that were attributable to continued operations were $3.4 million, $4.9 million and $0.5 million during the years ended December 31, 2023, 2022 and 2021, respectively. Stock-based compensation expense related to equity-classified awards that was attributable to discontinued operations was immaterial during the years ended December 31, 2023, 2022 and 2021. Merger impacts. Pursuant to the Merger Agreement, at the effective time of the Merger, the Company assumed the Whiting Equity Incentive Plan and the outstanding restricted stock units (“RSUs”) and performance share units (“PSUs”) granted under the Whiting Equity Incentive Plan. Accordingly, (i) all shares remaining available for issuance under the Whiting Equity Incentive Plan as of the Merger were automatically converted into shares of the Company’s common stock, available for issuance under the Whiting Equity Incentive Plan and (ii) all Whiting RSUs and PSUs were automatically converted into RSUs and PSUs of the Company, respectively, that, to the extent earned, will be settled in shares of the Company’s common stock, subject to appropriate adjustments to the number of shares subject to each award, resulting in the following as of July 1, 2022: (x) 1,611,725 shares of the Company’s common stock remaining available for issuance to eligible participants under the Whiting Equity Incentive Plan, (y) 335,386 shares of the Company’s common stock subject to RSUs assumed under the Whiting Equity Incentive Plan and (z) 275,310 shares of the Company’s common stock subject to PSUs assumed under the Whiting Equity Incentive Plan. The number of PSUs assumed by the Company was determined based upon the change-in-control provisions contained in the original award agreement at the greater of (i) the target number of PSUs subject to such award and (ii) the actual achievement of the performance criteria measured based on the truncated performance period ending immediately prior to the effective time of the Merger. Following completion of the Merger, the Whiting RSUs and PSUs are subject to time-based vesting criteria. The fair value of the RSU and PSU awards assumed by the Company was $73.3 million, including $27.4 million that was attributable to pre-Merger services and recorded as a part of the consideration transferred and $45.9 million that is attributable to post-Merger services that will be recognized as equity-based compensation expense in the post-combination period. The Company previously granted restricted stock awards (“RSAs”) to non-employee directors. RSAs are legally issued shares which were scheduled to vest over a three-year period subject to a service condition. The Company measured the awards at fair value on the date of grant, which was based on the closing price of the Company’s common stock. Pursuant to the award agreements governing the RSAs, each outstanding RSA became fully vested upon completion of the Merger due to a “change in control” (as defined in the award agreement). As a result, 64,920 outstanding RSAs became fully vested on July 1, 2022 and the Company recognized the remaining unrecognized compensation expense immediately. Restricted stock units. The Company has granted RSUs to employees and non-employee directors. RSUs are contingent shares with a service-based vesting condition. The RSUs granted to employees vest following a graded vesting schedule and vest ratably each year over a three-year or four-year period. The RSUs granted to non-employee directors vest over a one-year period. The fair value is based on the closing price of the Company’s common stock on the date of grant or, if applicable, the date of modification. The Company recognizes compensation expense under the straight-line method over the requisite service period. The following table summarizes information related to RSUs held by employees and non-employee directors of the Company: Shares Weighted Average Non-vested shares outstanding December 31, 2022 421,583 $ 88.26 Granted 161,875 137.43 Vested (310,683) 104.24 Forfeited (9,716) 107.65 Non-vested shares outstanding December 31, 2023 263,059 $ 98.94 The fair value of awards vested was $42.4 million and $62.3 million for the years ended December 31, 2023 and 2022, respectively. The weighted average grant date fair value of RSUs was $137.43 per share and $144.16 per share for the years ended December 31, 2023 and 2022, respectively. Unrecognized expense as of December 31, 2023 for all outstanding RSUs was $15.3 million and will be recognized over a weighted average period of approximately 1.9 years. Performance share units. The Company has granted PSUs to certain employees. PSUs are contingent shares that may be earned over three-year and four-year performance periods subject to market-based and service-based vesting conditions. The number of PSUs to be earned was initially subject to a market condition that was based on a comparison of the total stockholder return (“TSR”) achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the applicable performance periods, with 50% of the PSU awards eligible to be earned based on performance relative to a certain group of the Company’s oil and gas peers and 50% of the PSU awards eligible to be earned based on performance relative to the broad-based Russell 2000 index. Depending on the Company’s TSR performance relative to the defined peer group, award recipients could earn between 0% and 150% of target. Pursuant to the PSU award agreements, the number of PSUs earned was certified at the greater of (i) target performance and (ii) actual achievement of the performance criteria measured based on the truncated performance period ending immediately prior to the effective time of a “change in control.” The completion of the Merger on July 1, 2022 represented a “change in control” such that 250,016 PSUs were earned by legacy Oasis award recipients subject to a service-based vesting condition, including 183,915 PSUs that were outstanding at December 31, 2021 and an incremental 66,101 PSUs that were earned based upon the achievement of the performance criteria described above. The following table summarizes information related to PSUs held by employees of the Company: Shares Weighted Average Non-vested shares outstanding December 31, 2022 373,141 $ 92.53 Granted — — Vested (283,925) 98.28 Forfeited (10,273) 109.30 Non-vested shares outstanding December 31, 2023 78,943 $ 69.67 The fair value of awards vested was $46.3 million and $16.6 million for the years ended December 31, 2023 and 2022, respectively. No PSUs were granted during the years ended December 31, 2023 and 2022. Unrecognized expense as of December 31, 2023 for all outstanding PSUs was $1.1 million and will be recognized over a weighted average period of approximately 1.2 years. Leveraged stock units. The Company has granted leveraged stock units (“LSUs”) to certain employees. LSUs are contingent shares that may be earned over a three-year or four-year performance period subject to market-based and service-based vesting conditions. The number of LSUs to be earned was initially subject to a market condition that was based on the TSR performance of the Company’s common stock measured against specific premium return objectives. Depending on the Company’s TSR performance, award recipients could earn between 0% and 300% of target; however, the number of shares delivered in respect to these awards during the grant cycle could not exceed ten times the fair value of the award on the grant date. Pursuant to LSU award agreements, the number of LSUs earned was certified at the greater of (i) target performance and (ii) actual achievement of the performance criteria measured based on the truncated performance period ending immediately prior to the effective time of a “change in control.” The completion of the Merger on July 1, 2022 represented a “change in control” such that 787,218 LSUs were earned by award recipients subject to a service-based vesting condition. The following table summarizes information related to LSUs held by employees of the Company: Shares Weighted Average Non-vested shares outstanding December 31, 2022 497,037 $ 84.59 Granted — — Vested — — Forfeited — — Non-vested shares outstanding December 31, 2023 497,037 $ 84.59 No awards vested for the year ended December 31, 2023. The fair value of awards vested was $31.5 million for the year ended December 31, 2022. No LSUs were granted during the years ended December 31, 2023 and 2022. Unrecognized expense as of December 31, 2023 for all outstanding LSUs was $2.0 million and will be recognized over a weighted average period of approximately 1.0 year. Fair value assumptions. The aggregate grant date fair value of PSUs and LSUs was determined by a third-party valuation specialist using a Monte Carlo simulation model. The key valuation inputs were: (i) the forecast period, (ii) risk-free interest rate, (iii) implied equity volatility, (iv) stock price on the date of grant and, for PSUs, (v) correlation coefficient. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that correspond to each performance period. Implied equity volatility is derived by solving for an asset volatility and equity volatility based on the leverage of the Company and each of its peers. For the PSUs, the correlation coefficient measures the strength of the linear relationship between and amongst the Company and its peers based on historical stock price data. The following table summarizes the assumptions used in the Monte Carlo simulation model to determine the grant date fair value and associated equity-based compensation expenses by grant date: Grant date January 18, 2021 February 11, 2021 April 13, 2021 Forecast period (years) 3 - 4 3 - 4 3 - 4 Risk-free interest rates 0.2% - 0.3% 0.2% - 0.3% 0.3% - 0.6% Implied equity volatility 55% - 60% 55% - 60% 45% - 50% Stock price on date of grant $44.41 $49.66 $68.07 Phantom unit awards. The Company has granted phantom unit awards to certain employees. Phantom unit awards represent the right to receive, upon vesting of the award, a cash payment equal to the fair market value of one share of common stock. The phantom unit awards are subject to a service-based vesting condition and generally vest in equal installments each year over a three-year period from the date of grant. Compensation expense is recognized over the requisite service period. The following table summarizes information related to phantom unit awards held by employees of the Company: Phantom Unit Awards Weighted Average Non-vested phantom unit awards outstanding December 31, 2022 7,868 $ 135.91 Granted 9,919 166.23 Vested (7,100) 149.26 Forfeited (644) 156.38 Non-vested phantom unit awards outstanding December 31, 2023 10,043 $ 165.87

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2023
Stockholders' Equity Note [Abstract]
Stockholders' Equity	Stockholders’ Equity Dividends The following table summarizes the Company’s fixed and variable dividends declared by quarter for the years ended December 31, 2023 and 2022: Rate per Share Base Variable Special Total Total Dividends Declared (In thousands) Q4 2023 $ 1.250 $ 1.250 $ — $ 2.500 $ 107,867 Q3 2023 1.250 0.110 — 1.360 58,374 Q2 2023 1.250 1.970 — 3.220 137,507 Q1 2023 1.250 3.550 — 4.800 204,884 Total $ 5.000 $ 6.880 $ — $ 11.880 $ 508,632 Q4 2022 $ 1.250 $ 2.420 $ — $ 3.670 $ 157,673 Q3 2022 1.250 — — 1.250 70,242 Q2 2022 0.585 2.940 15.000 18.525 379,369 Q1 2022 0.585 3.000 — 3.585 73,074 Total $ 3.670 $ 8.360 $ 15.000 $ 27.030 $ 680,358 Total dividends declared in the table above includes (i) $14.4 million and $41.6 million associated with dividend equivalent rights on unvested equity-based compensation awards for the year ended December 31, 2023 and 2022, respectively, and (ii) a special dividend of $15.00 per share of common stock declared in connection with the Merger (the “Special Dividend”), or $307.4 million in aggregate, that was paid on July 8, 2022 to stockholders of record as of June 29, 2022. The Special Dividend was accounted for separately from the Merger and recognized as a reduction of retained earnings during the second quarter of 2022, which was the period when the Special Dividend was declared. As of December 31, 2023, the Company had dividends payable of $37.6 million related to dividend equivalent rights accrued on equity-based compensation awards, including $23.8 million that was recorded under accrued liabilities and $13.8 million that was recorded under other liabilities on the Consolidated Balance Sheet. On February 21, 2024, the Company declared a base-plus-variable cash dividend of $3.25 per share of common stock. The dividend will be payable on March 19, 2024 to shareholders of record as of March 5, 2024. Share Repurchase Program The Company’s Board of Directors authorized a share repurchase program in October 2023 of up to $750 million of the Company’s common stock. This program replaces previous share repurchase programs of up to (i) $300 million of the Company’s common stock authorized in August 2022, and (ii) $150 million of the Company’s common stock authorized in February 2022. During the year ended December 31, 2023, the Company repurchased 1,533,791 shares of common stock at a weighted average price of $157.08 per common share for a total cost of $240.9 million, excluding accrued excise tax of $0.4 million, under both of the August 2022 and October 2023 share repurchase programs. As of December 31, 2023, there was $683.0 million of capacity remaining under the Company’s $750 million program. During the year ended December 31, 2022, the Company repurchased 1,378,070 shares of common stock at a weighted average price of $110.24 per common share for a total cost of $151.9 million under both of the February and August 2022 share repurchase programs. Warrants Legacy Oasis warrants. On November 19, 2020, the Company entered into a Warrant Agreement with Computershare Inc. and Computershare Trust Company N.A., as warrant agent. The warrants, which are indexed to the Company’s common stock and are classified as equity, are exercisable until November 19, 2024, at which time all unexercised warrants will expire and the rights of the holders of such warrants to purchase common stock will terminate. In the event that a holder of a warrant elects to exercise their option to acquire shares of the Company’s common stock, the warrant is required to be settled through physical settlement or net share settlement. The warrants were initially exercisable for a price of $94.57 per warrant. The number of shares of Chord common stock for which a warrant is exercisable and the exercise prices are subject to adjustment from time to time upon the occurrence of certain events, including stock splits, reverse stock splits or stock dividends to holders of common stock or a reclassification in respect of common stock. Pursuant to the terms of the Warrant Agreement, the exercise price per warrant decreased to $75.57 per warrant effective June 30, 2022 in connection with the payment of the Special Dividend. No holder of a warrant, by virtue of holding or having a beneficial interest in a warrant, will have the right to vote, receive dividends, receive notice as stockholders with respect to any meeting of stockholders for the election of directors or any other matter, or exercise any rights whatsoever as a stockholder of Chord unless, until and only to the extent such holders become holders of record of shares of Chord common stock issued upon settlement of the warrants. Assumed Whiting warrants. Pursuant to the Merger Agreement, all of Whiting’s outstanding warrants immediately prior to the effective time of the Merger were assumed by the Company at the closing of the Merger. Prior to the Merger, each legacy Whiting warrant was exercisable for one share of Whiting common stock. Following the completion of the Merger and the Company’s assumption of the legacy Whiting warrants, each such warrant was exercisable for 0.5774 shares of the Company’s common stock, which reflects an adjustment in accordance with the exchange ratio under the Merger Agreement. Also, in accordance with the Merger Agreement, the exercise price of each such legacy Whiting warrant per share of the Company’s common stock was adjusted to equal the quotient of (x) the exercise price of such warrant per share of Whiting common stock immediately prior to the effective time of the Merger less $6.25 divided by (y) the exchange ratio of 0.5774. Therefore, as a result of the completion of the Merger on July 1, 2022, the Company assumed (i) 4,833,455 legacy Whiting Series A Warrants which were exercisable for an aggregate amount of 2,790,837 shares of the Company’s common stock at an exercise price of $116.37 per share and (ii) 2,418,832 legacy Whiting Series B Warrants which were exercisable for an aggregate amount of 1,396,634 shares of the Company’s common stock at an exercise price of $133.70 per share. In the event that a holder of Whiting warrants elects to exercise their option to acquire shares of the Company’s common stock, the Company shall issue a net number of exercised shares of common stock. The net number of exercised shares is calculated as (i) the number of Whiting warrants exercised multiplied by (ii) the difference between the 30 day daily volume weighted average price of the common stock leading up to the exercise date and the relevant exercise price, calculated as a percentage of the current market price on the exercise date. The legacy Whiting Series A Warrants are exercisable until September 1, 2024 and the legacy Whiting Series B Warrants are exercisable until September 1, 2025, at which respective times all unexercised Whiting warrants will expire and the rights of the holders of such Whiting warrants to acquire common stock will terminate. Pursuant to the Whiting warrant agreements, no holder of a Whiting warrant, by virtue of holding or having a beneficial interest in a Whiting warrant, will have the right to vote, receive dividends, receive notice as stockholders with respect to any meeting of stockholders for the election of directors or any other matter, or exercise any rights whatsoever as a stockholder of Chord unless, until and only to the extent such holders become holders of record of shares of Chord common stock issued upon settlement of the Whiting warrants. The number of shares of Chord common stock for which a Whiting warrant is exercisable and the exercise prices are subject to adjustment from time to time upon the occurrence of certain events, including stock splits, reverse stock splits or stock dividends to holders of common stock or a reclassification in respect of common stock. Chord warrants. The following table summarizes the Company’s outstanding warrants as of December 31, 2023: Warrants (1) Exercise Price (2) Legacy Oasis 575,717 $ 75.57 Legacy Whiting - Series A 1,318,369 $ 116.37 Legacy Whiting - Series B 1,338,568 $ 133.70 Total 3,232,654 __________________ (1) Represents the number of warrants in terms of shares of Chord common stock. (2) The exercise price of legacy Whiting warrants was adjusted in accordance with the Merger Agreement. During the year ended December 31, 2023, there were 1,746,859 warrants exercised. Authorized Shares of Common Stock On June 28, 2022, the Company’s stockholders approved an amendment to the Amended and Restated Certificate of Incorporation to increase the number of authorized shares of common stock from 60,000,000 to 120,000,000 in connection with the Merger. The amendment became effective on July 1, 2022. Issuance of Common Stock Pursuant to the Merger Agreement, each share of Whiting common stock issued and outstanding immediately prior to the effective time of the Merger was converted into the right to receive 0.5774 shares of common stock, par value $0.01 per share, of the Company. As a result of the completion of the Merger on July 1, 2022, the Company issued 22,671,871 shares of common stock to Whiting stockholders.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2023
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share The Company calculates earnings per share under the two-class method. During the third quarter of 2022, the Company granted RSUs to non-employee directors which include non-forfeitable rights to dividends and are therefore considered “participating securities.” Accordingly, effective in the third quarter of 2022, the Company computes earnings per share under the two-class earnings allocation method. The two-class method is an earnings allocation formula that computes earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Basic earnings per share amounts have been computed as (i) net income (loss) (ii) less distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of basic shares outstanding for the periods presented. Diluted earnings per share amounts have been computed as (i) basic net income attributable to common stockholders (ii) plus the reallocation of distributed and undistributed earnings allocated to participating securities (iii) divided by the weighted average number of diluted shares outstanding for the periods presented. The Company calculates diluted earnings per share under both the two-class method and treasury stock method and reports the more dilutive of the two calculations. The following table summarizes the basic and diluted earnings per share for the periods presented: Year Ended December 31, 2023 2022 2021 (In thousands, except per share data) Net income from continuing operations $ 1,023,779 $ 1,430,463 $ 188,960 Distributed and undistributed earnings from continuing operations allocated to participating securities (3,370) (182) — Net income from continuing operations attributable to common stockholders (basic) 1,020,409 1,430,281 188,960 Reallocation of distributed and undistributed earnings from continuing operations allocated to participating securities 76 6 — Net income from continuing operations attributable to common stockholders (diluted) $ 1,020,485 $ 1,430,287 $ 188,960 Weighted average common shares outstanding: Basic weighted average common shares outstanding 41,490 30,497 19,792 Dilutive effect of share-based awards 944 1,134 856 Dilutive effect of warrants 964 620 — Diluted weighted average common shares outstanding 43,398 32,251 20,648 Basic earnings per share from continuing operations $ 24.59 $ 46.90 $ 9.55 Diluted earnings per share from continuing operations $ 23.51 $ 44.35 $ 9.15 Anti-dilutive weighted average common shares: Potential common shares 3,709 2,901 2,144 For the years ended December 31, 2023, 2022 and 2021, the diluted earnings per share calculation excludes the impact of unvested share-based awards and outstanding warrants that were anti-dilutive. Basic earnings per share from discontinued operations was 13.96 for the year ended December 31, 2022 and 6.60 for the year ended December 31, 2021. Diluted earnings per share from discontinued operations was 13.20 for the year ended December 31, 2022 and 6.33 for the year ended December 31, 2021.

Leases

Leases	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Leases	Leases The Company’s long-term leases consist primarily of office space, vehicles and other property and equipment used in its operations. The components of lease costs attributable to continuing operations were as follows for the periods presented: Year Ended December 31, 2023 2022 2021 (In thousands) Operating lease costs $ 9,853 $ 11,292 $ 2,966 Variable lease costs (1) 13,391 8,562 1,737 Short-term lease costs 56,100 25,716 8,244 Sublease income (199) — — Finance lease costs: Amortization of ROU assets 1,367 1,342 1,578 Interest on lease liabilities 126 65 86 Total lease costs $ 80,638 $ 46,977 $ 14,611 ___________________ (1) Based on payments made by the Company to lessors for the right to use an underlying asset that vary because of changes in circumstances occurring after the commencement date, other than the passage of time, such as property taxes, operating and maintenance costs, which do not depend on an index or rate. The amounts disclosed herein are presented on a gross basis and do not reflect the Company’s net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners. Total lease costs attributable to discontinued operations were recorded in income from discontinued operations, net of income tax on the Consolidated Statements of Operations. Total lease costs attributable to discontinued operations were immaterial for the periods reported. As of December 31, 2023, maturities of the Company’s lease liabilities were as follows: Operating Leases Finance Leases (In thousands) 2024 $ 14,880 $ 1,025 2025 7,997 913 2026 5,100 684 2027 2,116 352 2028 2,010 17 Thereafter 3,425 — Total future lease payments 35,528 2,991 Less: Imputed interest 3,548 249 Present value of future lease payments $ 31,980 $ 2,742 Supplemental balance sheet information related to the Company’s leases were as follows: Balance Sheet Location December 31, 2023 December 31, 2022 (In thousands) Assets Operating lease assets (1) Operating right-of-use assets $ 21,343 $ 23,875 Finance lease assets (2)(3) Other assets 2,748 1,803 Total lease assets $ 24,091 $ 25,678 Liabilities Current Operating lease liabilities (1) Current operating lease liabilities $ 13,258 $ 9,941 Finance lease liabilities (3) Other current liabilities 916 1,012 Long-term Operating lease liabilities (1) Operating lease liabilities 18,667 13,266 Finance lease liabilities (3) Other liabilities 1,881 789 Total lease liabilities $ 34,722 $ 25,008 ___________________ (1) The Company acquired certain operating leases for office buildings and operating equipment in connection with the Merger. As of December 31, 2022, these included operating lease assets of $14.5 million, current operating lease liabilities of $2.5 million and long-term operating lease liabilities of $11.9 million. (2) Finance lease ROU assets are recorded net of accumulated amortization of $1.2 million as of December 31, 2023 and $1.6 million as of December 31, 2022. (3) The Company acquired certain finance leases for vehicles in connection with the Merger. As of December 31, 2022, these included finance lease assets of $1.4 million, current finance lease liabilities of $0.8 million and long-term finance lease liabilities of $0.6 million. In the first quarter of 2023, the Company began negotiations to sublease a portion of its Denver corporate office. As a result of an offer received and the overall market conditions, the Company recorded an asset impairment charge of $17.5 million, during the year ended December 31, 2023. This asset impairment charge primarily consisted of $12.1 million related to the amount by which the carrying value of the ROU asset exceeded the fair value and $5.5 million related to the remaining leasehold improvements within property, plant and equipment on the Consolidated Balance Sheet. The Company estimated the fair value of the ROU asset using an income approach based on the net present value of the expected sublease rental income during the sublease term. The ROU asset impairment charge is recorded within exploration and impairment on the Consolidated Statements of Operations. Supplemental cash flow information and non-cash transactions related to the Company’s leases were as follows: Year Ended December 31, 2023 2022 2021 (In thousands) Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 15,627 $ 15,843 $ 3,420 Operating cash flows from finance leases 160 57 62 Financing cash flows from finance leases 1,702 1,299 1,161 ROU assets obtained in exchange for lease obligations Operating leases (1) $ 22,201 $ 20,164 $ 14,140 Finance leases (2) 2,307 2,659 127 ___________________ (1) The year ended December 31, 2022 includes $15.8 million related to operating leases acquired in the Merger. The year ended December 31, 2021 includes $12.3 million related to operating leases acquired in the 2021 Williston Basin Acquisition. (2) The year ended December 31, 2022 includes $2.1 million related to finance leases acquired in the Merger. Weighted-average remaining lease terms and discount rates for the Company’s leases were as follows: December 31, 2023 2022 Operating Leases Weighted average remaining lease term 3.6 years 4.6 years Weighted average discount rate 6.3 % 4.9 % Finance Leases Weighted average remaining lease term 3.2 years 2.3 years Weighted average discount rate 5.7 % 5.4 %
Leases	Leases The Company’s long-term leases consist primarily of office space, vehicles and other property and equipment used in its operations. The components of lease costs attributable to continuing operations were as follows for the periods presented: Year Ended December 31, 2023 2022 2021 (In thousands) Operating lease costs $ 9,853 $ 11,292 $ 2,966 Variable lease costs (1) 13,391 8,562 1,737 Short-term lease costs 56,100 25,716 8,244 Sublease income (199) — — Finance lease costs: Amortization of ROU assets 1,367 1,342 1,578 Interest on lease liabilities 126 65 86 Total lease costs $ 80,638 $ 46,977 $ 14,611 ___________________ (1) Based on payments made by the Company to lessors for the right to use an underlying asset that vary because of changes in circumstances occurring after the commencement date, other than the passage of time, such as property taxes, operating and maintenance costs, which do not depend on an index or rate. The amounts disclosed herein are presented on a gross basis and do not reflect the Company’s net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners. Total lease costs attributable to discontinued operations were recorded in income from discontinued operations, net of income tax on the Consolidated Statements of Operations. Total lease costs attributable to discontinued operations were immaterial for the periods reported. As of December 31, 2023, maturities of the Company’s lease liabilities were as follows: Operating Leases Finance Leases (In thousands) 2024 $ 14,880 $ 1,025 2025 7,997 913 2026 5,100 684 2027 2,116 352 2028 2,010 17 Thereafter 3,425 — Total future lease payments 35,528 2,991 Less: Imputed interest 3,548 249 Present value of future lease payments $ 31,980 $ 2,742 Supplemental balance sheet information related to the Company’s leases were as follows: Balance Sheet Location December 31, 2023 December 31, 2022 (In thousands) Assets Operating lease assets (1) Operating right-of-use assets $ 21,343 $ 23,875 Finance lease assets (2)(3) Other assets 2,748 1,803 Total lease assets $ 24,091 $ 25,678 Liabilities Current Operating lease liabilities (1) Current operating lease liabilities $ 13,258 $ 9,941 Finance lease liabilities (3) Other current liabilities 916 1,012 Long-term Operating lease liabilities (1) Operating lease liabilities 18,667 13,266 Finance lease liabilities (3) Other liabilities 1,881 789 Total lease liabilities $ 34,722 $ 25,008 ___________________ (1) The Company acquired certain operating leases for office buildings and operating equipment in connection with the Merger. As of December 31, 2022, these included operating lease assets of $14.5 million, current operating lease liabilities of $2.5 million and long-term operating lease liabilities of $11.9 million. (2) Finance lease ROU assets are recorded net of accumulated amortization of $1.2 million as of December 31, 2023 and $1.6 million as of December 31, 2022. (3) The Company acquired certain finance leases for vehicles in connection with the Merger. As of December 31, 2022, these included finance lease assets of $1.4 million, current finance lease liabilities of $0.8 million and long-term finance lease liabilities of $0.6 million. In the first quarter of 2023, the Company began negotiations to sublease a portion of its Denver corporate office. As a result of an offer received and the overall market conditions, the Company recorded an asset impairment charge of $17.5 million, during the year ended December 31, 2023. This asset impairment charge primarily consisted of $12.1 million related to the amount by which the carrying value of the ROU asset exceeded the fair value and $5.5 million related to the remaining leasehold improvements within property, plant and equipment on the Consolidated Balance Sheet. The Company estimated the fair value of the ROU asset using an income approach based on the net present value of the expected sublease rental income during the sublease term. The ROU asset impairment charge is recorded within exploration and impairment on the Consolidated Statements of Operations. Supplemental cash flow information and non-cash transactions related to the Company’s leases were as follows: Year Ended December 31, 2023 2022 2021 (In thousands) Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 15,627 $ 15,843 $ 3,420 Operating cash flows from finance leases 160 57 62 Financing cash flows from finance leases 1,702 1,299 1,161 ROU assets obtained in exchange for lease obligations Operating leases (1) $ 22,201 $ 20,164 $ 14,140 Finance leases (2) 2,307 2,659 127 ___________________ (1) The year ended December 31, 2022 includes $15.8 million related to operating leases acquired in the Merger. The year ended December 31, 2021 includes $12.3 million related to operating leases acquired in the 2021 Williston Basin Acquisition. (2) The year ended December 31, 2022 includes $2.1 million related to finance leases acquired in the Merger. Weighted-average remaining lease terms and discount rates for the Company’s leases were as follows: December 31, 2023 2022 Operating Leases Weighted average remaining lease term 3.6 years 4.6 years Weighted average discount rate 6.3 % 4.9 % Finance Leases Weighted average remaining lease term 3.2 years 2.3 years Weighted average discount rate 5.7 % 5.4 %

Significant Concentrations

Significant Concentrations	12 Months Ended
	Dec. 31, 2023
Risks and Uncertainties [Abstract]
Significant Concentrations	Significant Concentrations Major customers. For the year ended December 31, 2023, sales to Phillips 66 Company and Gunvor USA LLC accounted for approximately 20% and 14%, respectively, of the Company’s total product sales. For the year ended December 31, 2022, sales to Phillips 66 Company and Shell Trading (US) Company accounted for approximately 17% and 11%, respectively, of the Company’s total product sales. For the year ended December 31, 2021, sales to Phillips 66 Company accounted for approximately 13% of the Company’s total product sales. No other purchasers accounted for more than 10% of the Company’s total sales for the years ended December 31, 2023, 2022 or 2021. Substantially all of the Company’s accounts receivable result from sales of crude oil, NGLs and natural gas as well as joint interest billings to third-party companies who have working interest payment obligations in projects completed by the Company. This concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions. Management believes that the loss of any of these purchasers would not have a material adverse effect on the Company’s operations, as there are a number of alternative crude oil, NGL and natural gas purchasers in the Company’s producing regions.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Included below is a discussion of various future commitments of the Company as of December 31, 2023. The commitments under these arrangements are not recorded in the accompanying Consolidated Balance Sheets. The amounts disclosed represent undiscounted cash flows on a gross basis and no inflation elements have been applied. As of December 31, 2023, the Company’s material off-balance sheet arrangements and transactions include $8.9 million in outstanding letters of credit issued under the Credit Facility and $27.1 million in net surety bond exposure issued as financial assurance on certain agreements. Volume commitment agreements. As of December 31, 2023, the Company had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 20.6 MMBbl of crude oil, 12.0 MMBbl of NGLs, 438.7 Bcf of natural gas and 1.6 MMBbl of water, prior to any applicable volume credits and within specified timeframes, of which, the majority have a remaining term of five years or less. The estimable future commitments under these volume commitment agreements as of December 31, 2023 are as follows: (In thousands) 2024 $ 100,434 2025 100,966 2026 83,045 2027 62,079 2028 31,109 Thereafter 13,939 $ 391,572 The future commitments under certain agreements cannot be estimated and are therefore excluded from the table above as they are based on fixed differentials relative to a commodity index price under the agreements as compared to the differential relative to a commodity index price for the production month. The Company enters into long-term contracts to provide production flow assurance in oversupplied areas with limited infrastructure, which provides for optimization of transportation and processing costs. As properties are undergoing development activities, the Company may experience temporary delivery or transportation shortfalls until production volumes grow to meet or exceed the minimum volume commitments. The Company recognizes any monthly deficiency payments in the period in which the under delivery takes place and the related liability has been incurred. The table above does not include any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since it cannot be predicted with accuracy the amount and timing of any such penalties incurred. Whiting Chapter 11 bankruptcy claims. On April 1, 2020, Whiting and certain of its subsidiaries (the “Debtors”) commenced voluntary cases (the “Whiting Chapter 11 Cases”) under chapter 11 of the United States Bankruptcy Code. On June 30, 2020, the Debtors filed their proposed Joint Chapter 11 Plan of Reorganization of Whiting and its Debtor affiliates (as amended, modified and supplemented, the “Whiting Plan”). On August 14, 2020, the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) confirmed the Whiting Plan and on September 1, 2020, the Debtors satisfied all conditions required for plan effectiveness and emerged from the Whiting Chapter 11 Cases. The filing of the Whiting Chapter 11 Cases allowed Whiting to, upon approval of the Bankruptcy Court, assume, assign or reject certain contractual commitments, including certain executory contracts. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such contract and subject to certain exceptions, relieves Whiting from performing future obligations under such contract but entitles the counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. To the extent that the Bankruptcy Court allows any unsecured claims against the Company, such claims may have been satisfied through an issuance of the Company’s common stock or other remedy or agreement under and pursuant to the Whiting Plan. In connection with the closing of the Merger on July 1, 2022, the Company assumed Whiting’s obligations with respect to the Whiting Plan and, accordingly, reserved 1,224,840 shares of common stock for potential future distribution to certain general unsecured claimants whose claim values are pending resolution in the Bankruptcy Court. As of October 19, 2023, all claims were resolved and the Company released the previously reserved shares of common stock. Arguello Inc. and Freeport-McMoRan Oil & Gas LLC. Whiting Oil and Gas Corporation (“WOG”), a wholly-owned subsidiary of the Company, had interests in federal oil and gas leases in the Point Arguello Unit located offshore in California. While those interests have expired, pursuant to certain related agreements (the “Point Arguello Agreements”), WOG was subject to certain abandonment and decommissioning obligations prior to WOG and Whiting rejecting the related contracts pursuant to the Whiting Plan. On October 1, 2020, Arguello Inc. and Freeport-McMoRan Oil & Gas LLC, individually and in its capacity as the designated Point Arguello Unit operator (collectively, the “FMOG Entities”) filed with the Bankruptcy Court an application for allowance of certain administrative claims arguing the FMOG Entities were entitled to recover Whiting’s proportionate share of decommissioning obligations owed to the U.S. government through subrogation to the U.S. government’s economic rights. The U.S. Government may also be able to bring claims against WOG directly for decommissioning costs. On February 18, 2021, WOG entered into a stipulation and agreed order with the United States Department of the Interior, Bureau of Safety & Environmental Enforcement (the “BSEE”) pursuant to which the BSEE withdrew its proofs of claims against Whiting and WOG and acknowledged their respective rights and obligations pursuant to the Whiting Plan. On October 20, 2022, the Company filed stipulations and proposed orders with the Bankruptcy Court to resolve all outstanding claims asserted by the FMOG Entities. Those stipulations and proposed orders were signed by the Bankruptcy Court on October 27, 2022. On November l, 2022, the Company paid $55.0 million in cash as full and final satisfaction, discharge and release of all such claims. Litigation . The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. When the Company determines that a loss is probable of occurring and is reasonably estimable, the Company accrues an undiscounted liability for such contingencies based on its best estimate using information available at the time. The Company discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed. Mandan, Hidatsa and Arikara Nation (“MHA Nation”) Title Dispute. This matter relates to certain leases acquired by the Company from QEP in October 2021: In June 2018, the MHA Nation notified QEP of its position that QEP has no valid lease covering certain minerals underlying the Missouri and Little Missouri Riverbeds on the Fort Berthold Reservation in North Dakota. The MHA Nation also passed a resolution purporting to rescind those portions of QEP's Indian Mineral Development Act of 1982 lease covering the disputed minerals underlying the Missouri River. QEP responded in September 2018 stating that the minerals underlying the Missouri River are properly leased. In May 2020, the Office of the Solicitor of the United States Department of the Interior (the “Department of the Interior”) issued an opinion (the “Missouri River Opinion”) finding that the State of North Dakota, not the MHA Nation, is the legal owner of the minerals underlying the Missouri River. The MHA Nation filed actions in two federal courts seeking to overturn the May 2020 decision, and in March 2021, the Department of the Interior withdrew the Missouri River Opinion and on February 4, 2022, the Department of the Interior issued a new opinion on the matter stating that the minerals beneath the Missouri River riverbed located on the Fort Berthold Indian Reservation belong to the MHA Nation and not the state of North Dakota. Based on the new opinion from the Department of Interior, on June 21, 2022, the D.C. Federal District Court issued an order dismissing the MHA Nation’s claims relating to title of the riverbed as moot and denied the State of North Dakota’s motion to intervene on remaining counts. The D.C. Federal District Court did not address the substantive question of ownership at that time. On June 29, 2022, the State of North Dakota appealed this order to the D.C. Circuit Court of Appeals. On April 21, 2023, the D.C. Circuit Court of Appeals issued an opinion reversing the D.C. Federal District Court’s denial of the State of North Dakota’s motion to intervene on the remaining counts. The case was then remanded back to the D.C. Federal District Court. The Department of the Interior’s motion for leave to amend its answer and assert a crossclaim against the State of North Dakota is currently pending before the D.C. Federal District Court. The Department of the Interior seeks to assert a crossclaim against the State of North Dakota to quiet title to the ownership of the Missouri Riverbed. The State of North Dakota does not object to the Department of the Interior’s crossclaim to quiet title, as a general matter, but argues for a change in venue to the North Dakota Federal District Court. The briefing on this motion is complete; however, as of the date of this report, the D.C. Federal District Court has not issued a ruling on the latest motion for leave to amend the pleadings.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2023
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On February 21, 2024, the Company entered into an arrangement agreement (the “Arrangement Agreement”) with Enerplus Corporation (“Enerplus”), pursuant to which, among other things, the Company has agreed to acquire Enerplus in a stock-and-cash transaction, subject to satisfaction of certain closing conditions. The transaction will be effected by way of a plan of arrangement under the Business Corporations Act (Alberta) (the “Plan of Arrangement”). Enerplus is an independent North American oil and gas exploration and production company. Under the terms of the Arrangement Agreement, Enerplus shareholders will receive 0.10125 shares of Chord common stock and $1.84 in cash in exchange for each common share of Enerplus they own at closing.

Supplemental Oil and Gas Disclo

Supplemental Oil and Gas Disclosures - Unaudited	12 Months Ended
	Dec. 31, 2023
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Oil and Gas Disclosures - Unaudited	Supplemental Oil and Gas Disclosures — Unaudited The supplemental data presented below reflects information for all of the Company’s oil and gas producing activities. Prior periods have not been recast for discontinued operations. Capitalized Costs The following table sets forth the capitalized costs related to the Company’s oil and gas producing activities: December 31, 2023 2022 (In thousands) Proved oil and gas properties $ 6,220,766 $ 5,089,185 Less: Accumulated depletion and impairment (1,035,393) (461,175) Proved oil and gas properties, net 5,185,373 4,628,010 Unproved oil and gas properties 99,477 30,936 Total oil and gas properties, net $ 5,284,850 $ 4,658,946 Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities The following table sets forth costs incurred related to the Company’s oil and gas activities for the periods presented: Year Ended December 31, 2023 2022 2021 (In thousands) Acquisition costs: Proved oil and gas properties $ 178,629 $ 3,164,665 $ 605,868 Unproved oil and gas properties 185,392 43,084 85 Exploration costs 6,366 859 1 Development costs 922,506 507,961 170,178 Asset retirement costs 18,461 21,165 15,750 Total costs incurred $ 1,311,354 $ 3,737,734 $ 791,882 Results of Operations for Oil and Gas Producing Activities The following table sets forth the results of operations for oil and gas producing activities, which exclude general and administrative expenses and interest expense, for the periods presented: Year Ended December 31, 2023 2022 2021 (In thousands) Revenues $ 3,132,411 $ 2,976,296 $ 1,200,256 Production costs 1,099,159 814,588 403,382 Depreciation, depletion and amortization 582,127 354,050 109,881 Exploration and impairment 17,830 2,204 2,763 Income tax expense 335,534 426,087 162,163 Results of operations for oil and gas producing activities $ 1,097,761 $ 1,379,367 $ 522,067

Supplemental Oil and Gas Reserv

Supplemental Oil and Gas Reserve Information - Unaudited	12 Months Ended
	Dec. 31, 2023
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Oil and Gas Reserve Information - Unaudited	Supplemental Oil and Gas Reserve Information — Unaudited The reserve estimates presented below at December 31, 2023 and 2022 are based on reports prepared by Netherland, Sewell & Associates, Inc., the Company’s independent reserve engineers. The reserve estimates at December 31, 2021 were based on reports prepared by DeGolyer and MacNaughton, the Company’s previous independent reserve engineers. All of the Company’s oil and gas reserves are attributable to properties within the United States. Proved oil and gas reserves are the estimated quantities of crude oil, NGLs and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. Estimated Quantities of Proved Reserves The following table summarizes changes in quantities of the Company’s estimated net proved reserves by product for the periods presented: Crude Oil NGLs (1) (MBbl) Natural Gas MBoe (2) 2021 Proved reserves Beginning balance 119,765 — 376,170 182,460 Revisions of previous estimates 42,411 — 68,768 53,871 Extensions, discoveries and other additions 7,734 — 14,539 10,157 Sales of reserves in place (24,760) — (40,211) (31,461) Purchases of reserves in place 42,656 — 86,153 57,015 Production (13,489) — (46,157) (21,182) Net proved reserves at December 31, 2021 174,317 — 459,262 250,860 Proved developed reserves, December 31, 2021 114,041 — 361,836 174,347 Proved undeveloped reserves, December 31, 2021 60,276 — 97,426 76,513 2022 Proved reserves Beginning balance 174,317 — 459,262 250,860 Revisions of previous estimates (8,032) 64,557 (56,500) 47,110 Extensions, discoveries and other additions 38,144 7,452 35,689 51,544 Sales of reserves in place — — — — Purchases of reserves in place 202,316 73,468 443,903 349,768 Production (25,457) (7,026) (67,428) (43,722) Net proved reserves at December 31, 2022 381,288 138,451 814,926 655,560 Proved developed reserves, December 31, 2022 272,529 115,227 689,651 502,698 Proved undeveloped reserves, December 31, 2022 108,759 23,224 125,275 152,862 2023 Proved reserves Beginning balance 381,288 138,451 814,926 655,560 Revisions of previous estimates (38,073) (5,270) (33,308) (48,895) Extensions, discoveries and other additions 53,207 15,046 62,273 78,632 Sales of reserves in place (3,999) (53) (3,067) (4,564) Purchases of reserves in place 12,375 3,052 20,060 18,771 Production (36,427) (13,047) (82,953) (63,300) Net proved reserves at December 31, 2023 368,371 138,179 777,931 636,204 Proved developed reserves, December 31, 2023 241,362 105,702 640,180 453,762 Proved undeveloped reserves, December 31, 2023 127,008 32,476 137,751 182,442 __________________ (1) For periods prior to July 1, 2022 , we reported crude oil and natural gas on a two-stream basis, and NGLs were combined with the natural gas stream when reporting reserves. As of July 1, 2022, NGLs are reported separately from the natural gas stream on a three-stream basis. This prospective change impacts the comparability of the periods presented. (2) Natural gas is converted to barrel of oil equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil. 2023 Proved reserves decreased by 19.4 MMBoe during the year ended December 31, 2023 due to the following: Production. Production decreased proved reserves by 63.3 MMBoe. Revisions of previous estimates. The Company had net negative revisions of 48.9 MMBoe attributable to the following: Decreases: • 41.2 MMBoe associated with lower crude oil, NGL and natural gas prices and tighter differentials • 19.6 MMBoe associated with increases in operating expenses and capital expenses primarily associated with inflation • 9.9 MMBoe primarily associated with updated expectations on undeveloped well reserves and changes to development timing Increases: • 14.4 MMBoe associated with stronger NGL yields • 7.4 MMBoe primarily associated with reservoir and engineering analysis and well performance across the Company’s Williston Basin assets Extensions, discoveries and other additions. The Company added 78.6 MMBoe of proved reserves associated with extensions and discoveries primarily attributable to successful drilling in the Williston Basin. New wells drilled in this area, as well as proved undeveloped (“PUD”) locations added as a result of offset drilling, increased proved reserves. Purchases of reserves in place. The Company added 18.8 MMBoe of proved reserves from the purchase of reserves in place as a result of the 2023 Williston Basin Acquisition. Sales of reserves in place. Proved reserves decreased 4.6 MMBoe primarily as a result of the Non-core Asset Sales. 2022 Proved reserves increased by 404.7 MMBoe during the year ended December 31, 2022 due to the following: Purchases of reserves in place. The Company added 349.8 MMBoe of proved reserves from the purchase of reserves in place as a result of the Merger. Extensions, discoveries and other additions. The Company added 51.5 MMBoe of proved reserves associated with extensions and discoveries primarily attributable to successful drilling in the Williston Basin. New wells drilled in this area, as well as PUD locations added as a result of offset drilling, increased proved reserves. Revisions of previous estimates. The Company had net positive revisions of 47.1 MMBoe attributable to the following: Increases: • 30.3 MMBoe associated with the change to reporting reserves on a three-stream basis in 2022 • 26.1 MMBoe associated with higher crude oil, NGL and natural gas prices • 2.6 MMBoe associated with tighter differentials and stronger NGL yields Decreases: • 6.7 MMBoe associated with reservoir and engineering analysis and well performance across the Company’s Williston Basin assets • 5.2 MMBoe primarily associated with lower working interests as a result of well payouts associated with higher commodity pricing Production. Production decreased proved reserves by 43.7 MMBoe. Sales of reserves in place. There were no impacts to proved reserves as a result of the sale of reserves in place. 2021 Proved reserves increased by 68.4 MMBoe during the year ended December 31, 2021 due to the following: Purchases of reserves in place. The Company added 57.0 MMBoe of proved reserves from the purchase of reserves in place as a result of the 2021 Williston Basin Acquisition. Revisions of previous estimates. The Company had net positive revisions of 53.9 MMBoe attributable to the following: Increases: • 38.6 MMBoe associated with alignment to the anticipated five-year development plan • 37.2 MMBoe associated with higher realized prices • 6.2 MMBoe associated with lower operating expenses Decreases: • 22.9 MMBoe associated with reservoir analysis and well performance across the Company’s Williston Basin assets • 5.2 MMBoe associated with the impact of removing the benefits of midstream operations from operating expenses Extensions, discoveries and other additions. The Company added 10.2 MMBoe of proved reserves associated with extensions and discoveries. Of these additions, 7.6 MMBoe were associated with the Company’s anticipated five-year development plan and 2.6 MMBoe were associated with new producing wells. Sales of reserves in place. Proved reserves decreased 31.5 MMBoe as a result of the Permian Basin Sale in June 2021. Production. Production decreased proved reserves by 21.2 MMBoe. Changes in Proved Undeveloped Reserves The following table summarizes the changes in the Company’s estimates of PUD reserves during 2023: Year Ended December 31, 2023 (MBoe) Proved undeveloped reserves, beginning of period 152,862 Purchases of minerals in place 7,167 Extensions, discoveries and other additions 74,514 Revisions of previous estimates (8,198) Conversion to proved developed reserves (43,903) Proved undeveloped reserves, end of period 182,442 Proved undeveloped reserves increased by 29.6 MMBoe during the year ended December 31, 2023 due to the following: Extensions, discoveries and other additions. The Company added 74.5 MMBoe of PUD reserves associated with extensions and discoveries primarily attributable to successful drilling in the Williston Basin. Purchases of minerals in place. The Company added 7.2 MMBoe of PUD reserves from the purchase of minerals in place as a result of the 2023 Williston Basin Acquisition. Revisions of previous estimates. The Company had net negative revisions of 8.2 MMBoe attributable to the following: Decreases: • 9.9 MMBoe primarily associated with changes to development timing and updated expectations on undeveloped well volumes • 1.5 MMBoe associated with lower crude oil, NGL and natural gas prices and tighter differentials • 0.7 MMBoe associated with increases in operating expenses and capital expenses primarily associated with inflation Increases: • 3.9 MMBoe associated with stronger NGL yields Conversions to proved developed reserves. The Company incurred $545.0 million in capital expenditures to convert 43.9 MMBoe of PUD reserves to proved developed reserves during 2023. The PUD conversions represented 29% of the Company’s PUD reserves balance at the beginning of 2023. As of December 31, 2023, the Company expects to develop all of its PUD reserves, including all wells drilled but not yet completed within five years after the initial year booked. Substantially all PUD locations are located on properties where the leases are held by existing production or continuous drilling operations. Approximately 12% of the Company’s PUD reserves at December 31, 2023 are attributable to wells that have been drilled but not yet completed, and all of the Company’s PUD reserves are within its core acreage in the Williston Basin. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves The Standardized Measure represents the present value of estimated future net cash flows from estimated net proved oil and natural gas reserves, less future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include DD&A of capitalized acquisition, exploration and development costs. The Company’s estimated net proved reserves and related future net revenues and Standardized Measure were determined using index prices for crude oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $78.22 per Bbl for crude oil and $2.64 per MMBtu for natural gas, $93.67 per Bbl for crude oil and $6.36 per MMBtu for natural gas and $66.55 per Bbl for crude oil and $3.64 per MMBtu for natural gas for the years ended December 31, 2023, 2022 and 2021, respectively. These prices were adjusted by lease for quality, energy content, transportation fees and marketing differentials. Future operating costs, production taxes and capital costs were based on current costs as of each year end. The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s estimated net proved reserves at December 31, 2023, 2022 and 2021: At December 31, 2023 2022 2021 (In thousands) Future cash inflows $ 31,882,940 $ 44,544,247 $ 13,366,064 Future production costs (13,815,882) (15,879,712) (6,548,794) Future development costs (3,055,823) (2,553,605) (1,322,207) Future income tax expense (2,573,017) (5,283,201) (717,721) Future net cash flows 12,438,218 20,827,729 4,777,342 10% annual discount for estimated timing of cash flows (5,447,578) (9,333,254) (2,080,404) Standardized measure of discounted future net cash flows $ 6,990,640 $ 11,494,475 $ 2,696,938 The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to estimated net proved reserves for the periods presented: 2023 2022 2021 (In thousands) January 1 $ 11,494,475 $ 2,696,938 $ 948,877 Net changes in prices and production costs (6,138,846) 3,148,745 1,617,331 Net changes in future development costs (92,072) 35,427 (36,645) Sales of crude oil and natural gas, net (2,033,251) (2,161,708) (796,874) Extensions 864,249 958,924 98,125 Purchases of reserves in place 373,913 7,441,750 780,442 Sales of reserves in place (75,097) — (204,153) Revisions of previous quantity estimates (1,142,960) 1,434,357 639,320 Previously estimated development costs incurred 574,607 137,534 102,519 Accretion of discount 1,445,215 683,631 94,090 Net change in income taxes 1,419,851 (2,539,182) (252,347) Changes in timing and other 300,556 (341,941) (293,747) December 31 $ 6,990,640 $ 11,494,475 $ 2,696,938

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net Income (Loss)	$ 1,023,779	$ 1,856,159	$ 319,602

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
Business Segments	The Company has evaluated how it is organized and managed and has identified only one reportable business segment, which is the exploration and production of crude oil, NGLs and natural gas. The Company considers its gathering, processing and marketing functions as ancillary to its oil and gas producing activities. All of the Company’s operations and assets are located in the United States, and substantially all of its revenues are attributable to United States customers. As of December 31, 2021, the Company had two business segments related to E&P and midstream operations. The Company’s midstream segment was classified as a discontinued operation in connection with the OMP Merger (defined in Note 10 — Divestitures ) and is no longer presented as a separate reporting segment in accordance with FASB ASC 280, Segment Reporting .
Use of Estimates	Use of Estimates Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to (i) proved crude oil, NGL and natural gas reserves and related cash flow estimates, (ii) assignment of fair value and allocation of purchase price in connection with business combinations, including the determination of any resulting goodwill or bargain purchase, (iii) impairment tests of long-lived assets, (iv) estimates of future development, dismantlement and abandonment costs, (v) estimates relating to certain crude oil, NGL and natural gas revenues and expenses, (vi) income taxes, (vii) valuation of derivative instruments and (viii) estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates. Estimates of crude oil, NGL and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, NGL and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future depreciation, depletion and amortization (“DD&A”) expense, dismantlement and abandonment costs and impairment expense.
Risks and Uncertainties	Risks and Uncertainties As a producer of crude oil, NGLs and natural gas, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude oil, NGLs and natural gas, which are dependent upon numerous factors beyond its control such as economic, geopolitical, political and regulatory developments and competition from other energy sources. The energy markets have historically been very volatile, and there can be no assurance that the prices for crude oil, NGLs or natural gas will not be subject to wide fluctuations in the future. A substantial or extended decline in prices for crude oil and, to a lesser extent, NGLs and natural gas, could have a material adverse effect on the Company’s financial position, results of operations, cash flows, the quantities of crude oil, NGLs and natural gas reserves that may be economically produced and the Company’s access to capital.
Cash and Cash Equivalents	Cash and Cash Equivalents The Company invests in certain money market funds, commercial paper and time deposits, all of which are stated at fair value or cost which approximates fair value due to the short-term maturity of these investments. The Company classifies all such highly liquid investments with original maturity dates less than 90 days as cash equivalents. While the Company may maintain balances of cash and cash equivalents in excess of amounts that are federally insured by the Federal Deposit Insurance Corporation, the Company invests with financial institutions that it believes are creditworthy and has not experienced any material losses in such accounts.
Accounts Receivable	Accounts Receivable Accounts receivable are carried at cost on a gross basis, with no discounting, which approximates fair value due to their short-term maturities. The Company’s accounts receivable consist mainly of receivables from crude oil, NGL and natural gas purchasers and joint interest owners on properties the Company operates. The Company regularly assesses the recoverability of all material trade and other receivables to determine their collectability and if an allowance for credit losses is warranted. The Company estimates credit losses and accrues a reserve on a receivable based on (i) historic loss experience for pools of receivable balances with similar characteristics, (ii) the length of time balances have been outstanding and (iii) the economic status of each counterparty. These loss estimates are then adjusted for current and expected future economic conditions, which may include an assessment of the probability of non-payment, financial distress or expected future commodity prices and the impact that any current or future conditions could have on a counterparty’s credit quality and liquidity. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s crude oil, NGL and natural gas receivables are collected within two months.
Inventory	Inventory The Company’s inventory includes equipment and materials and crude oil inventory. Equipment and materials consist primarily of well equipment, tanks and tubular goods to be used in the Company’s exploration and production activities. Crude oil inventory includes crude oil in tanks and linefill. Linefill represents the minimum volume of product in a pipeline system that enables the system to operate and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Crude oil and NGL linefill in third-party pipelines that is not expected to be withdrawn within one year is included in long-term inventory on the Company’s Consolidated Balance Sheets (see Note 4—Inventory). Inventory, including long-term inventory, is stated at the lower of cost and net realizable value with cost determined on an average cost method. The Company assesses the carrying value of inventory and uses estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact the Company’s estimates are the applicable quality and location differentials to include in the Company’s net realizable value analysis. Additionally, the Company estimates the upcoming liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net realizable value.
Property, Plant and Equipment	Property, Plant and Equipment Proved Oil and Gas Properties Crude oil, NGL and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and gas properties are capitalized at their estimated net present value. The provision for depletion of oil and gas properties is calculated using the unit-of-production method. All capitalized well costs (including future abandonment costs, net of salvage value) and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of crude oil. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized. The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties by field and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties in the applicable field to determine if the carrying amount is recoverable. The factors used to determine the undiscounted future cash flows are subject to management’s judgment and expertise and include, but are not limited to, future production volumes based upon estimates of proved reserves, future commodity prices and estimates of operating and development costs. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, the Company’s estimated undiscounted future cash flows, the timing and pace of development and the discount rate commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges for proved oil and gas properties will be recorded. Unproved Oil and Gas Properties Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment in the Consolidated Statements of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis. The Company assesses its unproved properties periodically for impairment on a prospect-by-prospect basis based on remaining lease terms, drilling results or future plans to develop acreage. The Company considers the following factors in its assessment of the impairment of unproved properties: • the remaining amount of unexpired term under its leases; • its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be close to expiration; • its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development; • its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and • its evaluation of the continuing successful results from the development of properties by the Company or by other operators in areas adjacent to or near the Company’s unproved properties. For sales of entire working interests in unproved properties, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property. Capitalized Interest The Company capitalizes a portion of its interest expense incurred on its outstanding debt. The amount capitalized is determined by multiplying the capitalization rate by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period. The accumulated capital expenditures included in the capitalized interest calculation begin when the first costs are incurred and end when the asset is either placed into production or written off. The Company capitalized interest costs of $4.1 million, $4.6 million and $2.1 million for the years ended December 31, 2023, 2022 and 2021, respectively. Capitalized interest costs are amortized over the life of the related assets. Other Property and Equipment Other property and equipment consists primarily of field office buildings, oilfield equipment, furniture, software, and leasehold improvements, and is recorded at cost and depreciated using the straight-line method based on expected lives of the individual assets (ranging from two years to 30 years) and net of estimated salvage values. The cost of assets disposed of and the associated accumulated DD&A are removed from the Company’s Consolidated Balance Sheets with any gain or loss realized upon the sale or disposal included in the Company’s Consolidated Statements of Operations. Exploration Expenses Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, are charged to expense as incurred. Costs from drilling exploratory wells are initially capitalized but charged to expense if and when a well is determined to be unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drilling is completed. The Company defers capitalized exploratory drilling costs for wells that have found a sufficient quantity of producible hydrocarbons but cannot be classified as proved because they are located in areas that require major capital expenditures or governmental or other regulatory approvals before production can begin. These costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for in the near future or the necessary approvals are actively being sought. Impairment The Company reviews its property, plant and equipment for impairment by asset group whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. If events occur that indicate an asset group may not be recoverable, the asset group is tested for recoverability. Proved oil and gas properties.
Business Combinations	Business Combinations The Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed measured at the estimated acquisition date fair value. Transaction and integration costs associated with business combinations are expensed as incurred. The Company makes various assumptions in estimating the fair value of the assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair value of proved and unproved oil and gas properties, which is measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include future production volumes based upon estimates of reserves prepared by the Company’s reserve engineers, future operating and development costs, future commodity prices (adjusted for basis differentials) and a market-based weighted average cost of capital discount rate. In addition, when appropriate, the Company reviews comparable transactions between market participants for the purchase and sale of oil and gas properties within the same region to measure fair value, which illustrates the amount a willing buyer and seller would enter into in exchange for such properties. The Company records goodwill for any amount of the consideration transferred in excess of the estimated fair value of the net assets acquired and a bargain purchase gain for any amount of the estimated fair value of net assets acquired in excess of the consideration transferred. Deferred taxes are recorded for any difference between the acquisition date fair value and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. The Company may adjust the provisional amounts recorded in a business combination during the measurement period which extends for up to one year after the acquisition date.
Discontinued Operations	Discontinued Operations The OMP Merger (defined in Note 10—Divestitures) represented a strategic shift for the Company and qualified for reporting as a discontinued operation on February 1, 2022, in accordance with FASB ASC 205-20, Presentation of financial statements – Discontinued Operations
Investment in Unconsolidated Affiliate	Investment in Unconsolidated Affiliate On February 1, 2022, the Company completed the OMP Merger (defined in Note 10—Divestitures) and received common units representing limited partner interests of Crestwood Equity Partners LP, a Delaware limited partnership (“Crestwood”). The Company elected to account for its investment in Crestwood using the fair value option under FASB ASC 825-10, Financial Instruments
Deferred Financing Costs	Deferred Financing Costs The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the Company’s Consolidated Statements of Operations. Deferred financing costs related to the Credit Facility (defined in Note 13—Long-Term Debt) are included in other assets on the Company’s Consolidated Balance Sheets, while deferred financing costs related to the Senior Notes (defined in Note 13—Long-Term Debt) are included as a reduction of long-term debt on the Company’s Consolidated Balance Sheets.
Asset Retirement Obligations	Asset Retirement Obligations In accordance with the FASB’s authoritative guidance on asset retirement obligations (“ARO”), the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties and produced water disposal wells, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period, and the capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as a component of DD&A in the Company’s Consolidated Statements of Operations. The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs, as further discussed in Note 6—Fair Value Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.
Revenue Recognition	Revenue Recognition The Company recognizes revenue in accordance with FASB ASC 606, Revenue from Contracts with Customers (“ASC 606”). ASC 606 includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Disclosures in accordance with ASC 606 have been provided in Note 3—Revenue Recognition. The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or a bundle of goods or services) at a point in time or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied. The Company’s revenues are predominantly derived from contracts for the sale of crude oil, NGLs and natural gas. Generally, for the crude oil, NGL and natural gas contracts: (i) each unit of commodity product is a separate performance obligation, as the Company’s promise is to sell multiple distinct units of commodity product at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on the Company’s right to invoice at month end for the value of commodity product sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity product’s standalone selling price and recognized as revenue at a point in time, which is typically when production is delivered and title or risk of loss transfers to the customer. The sales prices for crude oil, NGLs and natural gas are market-based and are adjusted for transportation and other related fees and deductions. Fees included in the contract that are incurred after the transfer of control to the customer are included as a reduction of the transaction price, while fees that are incurred prior to the transfer of control to the customer are classified as gathering, processing and transportation expenses in the Company’s Consolidated Statements of Operations. The sales of crude oil, NGL and natural gas as presented on the Company’s Consolidated Statements of Operations represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling crude oil, NGL and natural gas on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. Substantially all of the Company’s crude oil and natural gas production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices, and the Company’s NGL production is generally sold to purchasers under long-term (more than 12-month) contracts at market-based prices. The Company sells the majority of its production soon after it is produced at various locations, and, as a result, the Company maintains a minimum amount of product inventory in storage. For sales of commodities, the Company records revenue in the month that the production or purchased product is delivered to the purchaser. However, settlement statements and payments are typically not received for 20 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company uses knowledge of its properties, its properties’ historical performance, spot market prices and other factors as the basis for these estimates. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. In certain cases, the Company is required to estimate these volumes during a reporting period and record any differences between the estimated volumes and actual volumes in the following reporting period. Differences between estimated and actual revenues have historically not been significant. Revenue recognized related to performance obligations satisfied in prior reporting periods was not material for the periods presented. The Company’s purchased crude oil and natural gas sales are derived from the sale of crude oil and natural gas purchased from third parties. Revenues and expenses from these sales and purchases are recorded on a gross basis when the Company acts as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, the Company enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with FASB ASC 845, Nonmonetary Transactions . The Company has elected practical expedients, pursuant to ASC 606, to exclude from the presentation of remaining performance obligations: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct service that forms part of a series of distinct services and (ii) contracts with an original expected duration of one year or less.
Leases	Leases The Company accounts for leases in accordance with FASB ASC 842, Leases (“ASC 842”). In accordance with ASC 842, the Company determines whether an arrangement is a lease at its inception. The Company’s long-term operating and finance leases consist primarily of office space, vehicles and other property and equipment used in its operations. The operating lease right-of-use (“ROU”) asset also includes any lease incentives received in the recognition of the present value of future lease payments. The Company considers renewal and termination options in determining the lease term used to establish its ROU assets and lease liabilities to the extent the Company is reasonably certain to exercise the renewal or termination. The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants. As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future lease payments. The Company determines the incremental borrowing rate based upon the rate of interest that would have been paid on a collateralized basis over similar tenors to that of the leases. The Company’s share of operating, variable and short-term lease costs are either capitalized and included in property, plant and equipment on the Company’s Consolidated Balance Sheets or are recognized in the Company’s Consolidated Statements of Operations in lease operating expenses and general and administrative expenses, as applicable. The finance lease costs for the amortization of ROU assets are included in depreciation, depletion and amortization and the interest on lease liabilities is included in interest expense, net of capitalized interest, on the Company’s Consolidated Statements of Operations.
Fair Value Measurement	Fair Value Measurements As defined in FASB ASC 820, Fair Value Measurement (“ASC 820”), fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. ASC 820 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows: Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, 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. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Level 3 — Pricing inputs are generally unobservable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value. Financial Assets and Liabilities The fair value of the Company’s non-financial assets measured at fair value on a non-recurring basis is determined using valuation techniques that include Level 3 inputs. Asset retirement obligations. The initial measurement of ARO at fair value is recorded in the period in which the liability is incurred. Fair value is determined by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding the timing and existence of a liability, as well as what constitutes adequate restoration when considering current regulatory requirements. Inherent in the fair value calculation are numerous assumptions and judgments, including the ultimate costs, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, environmental and regulatory environments. Oil and gas and other properties.
Concentrations of Market and Credit Risk	Concentrations of Market and Credit Risk The future results of the Company’s operations will be affected by the market prices of crude oil, NGLs and natural gas. The availability of a ready market for crude oil, NGL and natural gas products in the future will depend on numerous factors beyond the Company’s control, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, NGLs and natural gas, the regulatory environment, the economic environment and other regional and political events, none of which can be predicted with certainty. Commodity prices have been volatile in recent years and could be volatile in the future. A substantial or extended decline in the price of crude oil could have a material adverse effect on the Company’s financial position, cash flows and results of operations. The Company’s receivables include amounts due from purchasers of its crude oil, NGL and natural gas production and amounts due from joint interest partners for their respective portions of operating expenses and development costs. While certain of these customers and joint interest partners are affected by periodic downturns in the economy in general or in their specific segment of the oil and gas industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long term. The Company manages market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments, which potentially subject the Company to credit risk, consist principally of cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally-insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its customers is generally high. In the normal course of business, letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit risk.
Risk Management	Risk Management The Company utilizes derivative financial instruments to manage risks related to changes in crude oil, NGL and natural gas prices. As of December 31, 2023, the Company utilized fixed-price swaps and collars to reduce the volatility of crude oil, NGL and natural gas prices on future expected production. See Note 7—Derivative Instruments for additional information. The Company records all derivative instruments on the Consolidated Balance Sheets as either assets or liabilities measured at their estimated fair value. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all existing counterparty contracts provide for net settlement. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. Gains and losses from valuation changes in commodity derivative instruments are reported in the other income (expense) section of the Company’s Consolidated Statements of Operations and as operating activities in the Company’s Consolidated Statement of Cash Flows. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows. Derivative financial instruments that hedge the price of crude oil, NGL and natural gas are executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. At December 31, 2023, the Company had derivatives in place with nine counterparties, all of which are secured parties under the Credit Facility (defined in Note 13—Long-Term Debt), which eliminates the need to post or receive collateral associated with its derivative positions. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of nonperformance by the counterparties are substantially smaller. The credit worthiness of the counterparties is subject to continual review. The Company believes the risk of nonperformance by its counterparties is low. Full performance is anticipated, and the Company has no past-due receivables from the counterparties to its commodity derivative contracts. The Company’s policy is to execute financial derivatives only with major, credit-worthy financial institutions.
Contingencies	Contingencies Certain conditions may exist as of the date the Company’s consolidated financial statements are issued that may result in a loss to the Company, but which will only be resolved when one or more future events occur or fail to occur. The Company’s management, with input from legal counsel, assesses such contingent liabilities, and such assessment inherently involves judgment. In assessing loss contingencies related to legal proceedings that are pending against the Company or unasserted claims that may result in proceedings, the Company’s management, with input from legal counsel, evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein. If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount of liability can be estimated, then the estimated undiscounted liability is accrued in the Company’s consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed. Actual results could vary from these estimates and judgments.
Environmental Costs	Environmental Costs Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and which do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable, and the costs can be reasonably estimated.
Equity-Based Compensation	Equity-Based Compensation The Company has the 2020 Long Term Incentive Plan (the “2020 LTIP”), which provides for the grant of incentive stock options, nonstatutory stock options, restricted stock, restricted stock units, stock appreciation rights, dividend equivalents, other stock-based awards, cash awards, performance awards or any combination of the foregoing. In connection with the Merger, the Company assumed the Whiting Petroleum Corporation 2020 Equity Incentive Plan (the “Whiting Equity Incentive Plan”), which provides for the grant of incentive stock options, nonstatutory stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units and annual incentive awards or any combination of the foregoing. The Company determines the compensation expense for share-settled awards based on the grant date fair value, and such expense is recognized ratably over the requisite service period, which is generally the vesting period. The Company recognizes compensation expense using the straight-line attribution method for service-based awards with a graded vesting feature. Compensation expense for cash-settled awards is recognized over the requisite service period and is remeasured at the fair value of such awards at the end of each reporting period. Forfeitures are accounted for as they occur by reversing the expense previously recognized for awards that were forfeited during the period. Equity awards that settle in shares of common stock are generally net settled by withholding shares of common stock to satisfy income tax withholding obligations due upon vesting. The fair values of awards are determined based on the type of award and may utilize market prices on the date of grant (for service-based equity awards) or at the end of the reporting period (for liability-classified awards), Monte Carlo simulations or other acceptable valuation methodologies, as appropriate for the type of award. A Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. See Note 16—Equity-Based Compensation for additional information. Any excess tax benefit arising from the Company’s equity-based compensation plans is recognized as a credit to income tax expense or benefit in the Company’s Consolidated Statements of Operations.
Treasury Stock	Treasury Stock Treasury stock purchases are recorded at cost and represent shares of common stock repurchased under the Company’s share repurchase program.
Income Taxes	Income Taxes The Company’s provision for taxes includes both federal and state income taxes. The Company records its income taxes in accordance with FASB ASC 740 which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. The Company applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from the Company’s estimates, which could impact its financial position, results of operations and cash flows. The Company also accounts for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company did not have any uncertain tax positions outstanding and, as such, did not record a liability as of December 31, 2023 or 2022. All deferred tax assets and liabilities, along with any related valuation allowance, are classified as non-current on the Company’s Consolidated Balance Sheets.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (“ASU 2023-07”). This standard clarifies that single reportable segment entities are subject to the disclosure requirements under Topic 280 in its entirety. This ASU requires disclosure of significant segment expense categories that are regularly provided to the chief operating decision maker (“CODM”) and included in each reported measure of segment performance. Additionally, this ASU requires that public entities disclose the title and position of the CODM. The amendments in this standard extend certain annual disclosures to interim periods. ASU 2023-07 is effective for fiscal years beginning after December 15, 2023 and interim periods within those fiscal years beginning after December 15, 2024. A public entity should apply ASU 2023-07 retrospectively to all prior periods presented in the financial statements. Early adoption is permitted. The Company is currently evaluating this ASU to determine its impact on the Company’s annual financial statement disclosures.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Schedule of Net Changes in Capitalized Exploratory Well Costs	Net changes in capitalized exploratory well costs are reflected in the following table for the periods presented: Year Ended December 31, 2023 2022 2021 (In thousands) Beginning of period $ — $ 1 $ — Exploratory well cost additions (pending determination of proved reserves) — 21 — Exploratory well cost reclassifications (successful determination of proved reserves) — (2) — Exploratory well dry hole costs (unsuccessful in adding proved reserves) — — — Exploratory well cost reclassifications (canceled wells written off to predrill write-off) — (20) 1 End of period $ — $ — $ 1

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Schedule of Disaggregation of Revenue	Revenues associated with contracts with customers were as follows for the periods presented: Year Ended December 31, 2023 2022 2021 (In thousands) Crude oil revenues $ 2,835,962 $ 2,366,995 $ 910,381 Purchased crude oil sales 709,817 511,020 247,252 NGL and natural gas revenues 296,449 609,301 289,875 Purchased NGL and natural gas sales 54,413 159,154 131,731 Other services revenues — 324 687 Total revenues $ 3,896,641 $ 3,646,794 $ 1,579,926

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2023
Inventory Disclosure [Abstract]
Schedule of Inventory	The following table sets forth the Company’s inventory balances for the periods presented: December 31, 2023 2022 (In thousands) Inventory Equipment and materials $ 30,201 $ 21,097 Crude oil inventory 42,364 33,314 Total inventory $ 72,565 $ 54,411 Long-term inventory Linefill in third-party pipelines $ 22,936 $ 22,009 Total long-term inventory $ 22,936 $ 22,009 Total $ 95,501 $ 76,420
Schedule of Long-term Inventory	The following table sets forth the Company’s inventory balances for the periods presented: December 31, 2023 2022 (In thousands) Inventory Equipment and materials $ 30,201 $ 21,097 Crude oil inventory 42,364 33,314 Total inventory $ 72,565 $ 54,411 Long-term inventory Linefill in third-party pipelines $ 22,936 $ 22,009 Total long-term inventory $ 22,936 $ 22,009 Total $ 95,501 $ 76,420

Additional Balance Sheet Info_2

Additional Balance Sheet Information (Tables)	12 Months Ended
	Dec. 31, 2023
Balance Sheet Related Disclosures [Abstract]
Schedule of Components of Balance Sheet Amounts	Certain balance sheet amounts are comprised of the following: December 31, 2023 2022 (In thousands) Accounts receivable, net Trade and other accounts $ 749,356 $ 661,121 Joint interest accounts 207,571 127,772 Total accounts receivable 956,927 788,893 Less: allowance for credit losses (13,813) (7,155) Total accounts receivable, net $ 943,114 $ 781,738 Revenues and production taxes payable Royalties payable $ 297,531 $ 368,574 Revenue suspense 266,704 203,388 Production taxes payable 40,469 36,002 Total revenue and production taxes payable $ 604,704 $ 607,964 Accrued liabilities Accrued oil and gas marketing $ 165,141 $ 127,240 Accrued capital costs 122,260 76,747 Accrued lease operating expenses 107,606 73,714 Accrued general and administrative expenses 37,882 42,259 Current portion of asset retirement obligations 10,507 19,376 Accrued dividends 25,167 5,873 Other accrued liabilities 24,818 17,245 Total accrued liabilities $ 493,381 $ 362,454

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Schedule of Hierarchy of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following tables present the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis: Fair value at December 31, 2023 Level 1 Level 2 Level 3 Total (In thousands) Assets: Commodity derivative contracts (see Note 7) $ — $ 11,312 $ 5,877 $ 17,189 Contingent consideration (see Note 7) — 42,706 — 42,706 Investment in unconsolidated affiliate (see Note 12) 100,172 — — 100,172 Total assets $ 100,172 $ 54,018 $ 5,877 $ 160,067 Liabilities: Commodity derivative contracts (see Note 7) $ — $ 14,926 $ — $ 14,926 Total liabilities $ — $ 14,926 $ — $ 14,926 Fair value at December 31, 2022 Level 1 Level 2 Level 3 Total (In thousands) Assets: Commodity derivative contracts (see Note 7) $ — $ 780 $ — $ 780 Contingent consideration (see Note 7) — 60,920 — 60,920 Investment in unconsolidated affiliate (see Note 12) 130,575 — — 130,575 Total assets $ 130,575 $ 61,700 $ — $ 192,275 Liabilities: Commodity derivative contracts (see Note 7) $ — $ 329,676 $ 14,694 $ 344,370 Total liabilities $ — $ 329,676 $ 14,694 $ 344,370

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Outstanding Commodity Derivative Instruments	At December 31, 2023, the Company had the following outstanding commodity derivative contracts: Commodity Settlement Derivative Volumes Weighted Average Prices Fixed-Price Swaps Sub-Floor Floor Ceiling Crude oil 2024 Two-way collars 4,660,000 Bbls $ 64.31 $ 83.89 Crude oil 2024 Three-way collars 736,000 Bbls $ 55.00 $ 71.25 $ 92.14 Crude oil 2024 Fixed-price swaps 366,000 Bbls $ 69.27 Crude oil 2025 Two-way collars 1,181,000 Bbls $ 60.00 $ 79.05 Crude oil 2025 Three-way collars 1,276,000 Bbls $ 50.71 $ 65.71 $ 82.60 Natural gas 2025 Fixed-price swaps 651,600 MMBtu $ 3.93 Subsequent to December 31, 2023, the Company entered into the following commodity derivative contracts: Weighted Average Prices Commodity Settlement Period Derivative Instrument Volumes Sub-Floor Floor Ceiling Crude oil 2024 Two-way collars 825,000 Bbls $ 66.65 $ 81.94 Crude oil 2025 Three-way collars 1,095,000 Bbls $ 55.00 $ 70.00 $ 81.62 Crude oil 2026 Three-way collars 270,000 Bbls $ 50.00 $ 65.00 $ 83.70
Schedule of Realized and Unrealized Gains and Losses From Commodity Derivative Instruments	The following table summarizes the location and amounts of gains and losses from the Company’s derivative instruments recorded in the Company’s Consolidated Statements of Operations for the periods presented: Year Ended December 31, Derivative Instrument Statement of Operations Location 2023 2022 2021 (In thousands) Commodity derivatives Net gain (loss) on derivative instruments $ 56,396 $ (224,238) $ (601,591) Commodity derivatives (buy/sell transportation contracts) Gathering, processing and transportation expenses (1) 20,570 7,331 — Contingent consideration Net gain (loss) on derivative instruments 6,786 16,110 11,950 Contingent consideration Gain on sale of assets, net — — 32,860 __________________ (1) The change in the fair value of the transportation derivative contracts was recorded as a gain in GPT expenses for the year ended December 31, 2023.
Schedule of Location and Fair Value of Outstanding Commodity Derivative Instruments	The following tables summarize the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Consolidated Balance Sheets: December 31, 2023 Derivative Instrument Balance Sheet Location Gross Amount Gross Amount Offset Net Amount (In thousands) Derivatives assets: Commodity derivatives Derivative instruments — current assets $ 20,647 $ (11,769) $ 8,878 Contingent consideration Derivative instruments — current assets 22,614 — 22,614 Commodity derivatives (buy/sell transportation contracts) Derivative instruments — current assets 5,877 — 5,877 Commodity derivatives Derivative instruments — non-current assets 16,760 (14,326) 2,434 Contingent consideration Derivative instruments — non-current assets 20,092 — 20,092 Total derivatives assets $ 85,990 $ (26,095) $ 59,895 Derivatives liabilities: Commodity derivatives Derivative instruments — current liabilities $ 25,978 $ (11,769) $ 14,209 Commodity derivatives Derivative instruments — non-current liabilities 15,043 (14,326) 717 Total derivatives liabilities $ 41,021 $ (26,095) $ 14,926 December 31, 2022 Derivative Instrument Balance Sheet Location Gross Amount Gross Offset Amount Net Amount (In thousands) Derivatives assets: Commodity derivatives Derivative instruments — current assets $ 10,194 $ (9,414) $ 780 Contingent consideration Derivative instruments — current assets 22,955 — 22,955 Contingent consideration Derivative instruments — non-current assets 37,965 — 37,965 Total derivatives assets $ 71,114 $ (9,414) $ 61,700 Derivatives liabilities: Commodity derivatives Derivative instruments — current liabilities $ 339,090 $ (9,414) $ 329,676 Commodity derivatives (buy/sell transportation contracts) Derivative instruments — current liabilities 11,865 — 11,865 Commodity derivatives (buy/sell transportation contracts) Derivative instruments — non-current liabilities 2,829 — 2,829 Total derivatives liabilities $ 353,784 $ (9,414) $ 344,370

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	The following table sets forth the Company’s property, plant and equipment: December 31, 2023 2022 (In thousands) Proved oil and gas properties $ 6,220,766 $ 5,089,185 Less: Accumulated depletion (1,035,393) (461,175) Proved oil and gas properties, net 5,185,373 4,628,010 Unproved oil and gas properties 99,477 30,936 Other property and equipment 49,051 72,973 Less: Accumulated depreciation and impairment (19,223) (20,576) Other property and equipment, net 29,828 52,397 Total property, plant and equipment, net $ 5,314,678 $ 4,711,343

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
Schedule of Purchase Price Allocation	The tables below present the total consideration transferred and its allocation to the identifiable assets acquired and liabilities assumed as of the acquisition date on June 30, 2023. As provided under ASC 805, the purchase price allocation may be subject to change for up to one year after June 30, 2023, which may result in a different allocation than what is presented in the tables below. As of December 31, 2023, the purchase price was finalized with an immaterial adjustment to the preliminary purchase price allocation. Purchase Price Consideration (In thousands) Cash consideration transferred $ 361,609 Preliminary Purchase Price Allocation (In thousands) Assets acquired: Oil and gas properties $ 367,672 Inventory 1,844 Total assets acquired $ 369,516 Liabilities assumed: Asset retirement obligations $ 6,771 Revenue and production taxes payable 1,136 Total liabilities assumed $ 7,907 Net assets acquired $ 361,609 Purchase Price Allocation (In thousands) Assets acquired: Cash and cash equivalents $ 94,641 Accounts receivable, net 491,514 Inventory 35,256 Prepaid expenses 14,851 Other current assets 5,719 Current assets held for sale 16,074 Oil and gas properties 3,211,043 Other property and equipment 31,244 Long-term inventory 3,138 Operating right-of-use assets 15,752 Deferred tax assets 228,574 Other assets 3,346 Total assets acquired $ 4,151,152 Liabilities assumed: Accounts payable $ 116,769 Revenues and production taxes payable 411,553 Accrued liabilities 215,218 Derivatives instruments (current liability) 471,693 Current operating lease liabilities 2,629 Other current liabilities 2,902 Current liabilities held for sale 9,410 Asset retirement obligations 57,197 Derivative instruments (long-term liability) 15,128 Operating lease liabilities 13,123 Other liabilities 2,728 Total liabilities assumed $ 1,318,350 Net assets acquired $ 2,832,802
Schedule of Business Acquisitions, by Acquisition	The tables below present the total consideration transferred and its preliminary allocation to the identifiable assets acquired and liabilities assumed as of the acquisition date on July 1, 2022. As of December 31, 2023, the purchase price was finalized with no adjustment to the preliminary purchase price allocation. Purchase Price Consideration (In thousands) Common stock issued to Whiting stockholders (1) $ 2,478,036 Cash paid to Whiting stockholders (1) 245,436 Replacement of Whiting Series A Warrants and Whiting Series B Warrants (2) 79,774 Replacement of Whiting equity-based compensation awards (3) 27,402 Cash paid to settle Whiting credit facility (4) 2,154 Total consideration transferred $ 2,832,802 __________________ (1) The Company issued 22,671,871 shares of common stock and paid $245.4 million of cash to Whiting stockholders as Merger consideration. Each holder of Whiting common stock received 0.5774 shares of common stock as share consideration and $6.25 of cash as cash consideration. The fair value of the common stock issued was based on the closing price of the Company’s common stock on July 1, 2022 of $109.30. See Note 17—Stockholders’ Equity for additional information. (2) The Company assumed (i) 4,833,455 Whiting Series A Warrants and (ii) 2,418,832 Whiting Series B Warrants. The replacement of Whiting Series A and B Warrants was based on the closing price of the warrants on July 1, 2022 of $11.25 and $10.50, respectively. See Note 17—Stockholders’ Equity for additional information. (3) The Whiting equity awards were replaced with awards issued by Chord with similar terms and conditions as the original awards. The fair value of the replacement equity awards attributable to pre-Merger service was recorded as consideration transferred. See Note 16— Equity-Based Compensation for additional information. (4) On July 1, 2022, the Company fully satisfied all obligations under the Whiting credit facility and the Whiting credit facility was concurrently terminated. See Note 13—Long-Term Debt for additional information. Year Ended December 31, 2022 (In thousands) Revenues $ 1,044,079 Income from continuing operations before income taxes 553,686
Schedule of Pro Forma Information	The pro forma results of operations do not include any future cost savings or other synergies that may result from the Merger or any estimated costs that have not yet been incurred by the Company to integrate the Whiting assets. Year Ended December 31, 2022 2021 (In thousands) Revenues $ 4,759,706 $ 3,113,407 Net income attributable to Chord 2,093,776 477,184 Net income attributable to Chord per share: Basic $ 50.00 $ 11.21 Diluted 47.88 10.93

Discontinued Operations and Dis

Discontinued Operations and Disposal Groups (Tables)	12 Months Ended
	Dec. 31, 2023
Discontinued Operations and Disposal Groups [Abstract]
Schedule of Discontinued Operations By Statement Of Operations And Balance Sheet	Consolidated Statements of Operations The results of operations reported as discontinued operations in connection with the OMP Merger were as follows for the periods presented: Year Ended December 31, (In thousands) 2022 2021 Revenues Oil and gas revenues $ — $ 1,013 Purchased oil and gas sales (1) (13,364) (131,369) Midstream revenues 23,271 254,228 Total revenues 9,907 123,872 Operating expenses Lease operating expenses (1) (4,535) (62,142) Midstream expenses 13,224 122,040 Gathering, processing and transportation expenses (1) (3,555) (49,795) Purchased oil and gas expenses (1) (12,506) (125,709) Depreciation, depletion and amortization — 31,868 Impairment — 2 General and administrative expenses (1) 3,314 4,193 Total operating expenses (4,058) (79,543) Gain on sale of assets 518,900 — Operating income 532,865 203,415 Other expense Interest expense, net of capitalized interest (3,685) (36,945) Other expense (93) (115) Total other expense, net (3,778) (37,060) Income from discontinued operations before income taxes 529,087 166,355 Income tax expense (2) (101,080) (17) Income from discontinued operations, net of income tax 428,007 166,338 Net income attributable to non-controlling interests 2,311 35,696 Income from discontinued operations attributable to Chord, net of income tax $ 425,696 $ 130,642 __________________ (1) Includes discontinued intercompany eliminations. (2) The Company applied the intraperiod tax allocation rules in accordance with FASB ASC 740-20, Intraperiod Tax Allocation (“ASC 740-20”) to determine the allocation of tax expense between continuing operations and discontinued operations. ASC 740-20 generally requires the allocation of tax expense to be based on a comparative calculation of tax expense with and without income from discontinued operations. During the year ended December 31, 2022, the Company released a portion of its valuation allowance (see Note 15—Income Taxes for additional information) and allocated the majority of the income tax benefit associated with this valuation allowance release to continuing operations. The total tax expense associated with the OMP Merger was partially offset by the release of the Company’s valuation allowance allocated to discontinued operations, resulting in a tax expense of $101.1 million attributable to discontinued operations during the year ended December 31, 2022.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Schedule of Long-Term Debt	The Company’s long-term debt consists of the following: December 31, 2023 2022 (In thousands) Senior secured revolving line of credit $ — $ — Senior unsecured notes 400,000 400,000 Less: unamortized deferred financing costs (4,098) (5,791) Total long-term debt, net $ 395,902 $ 394,209 Total Revolving Commitment Utilization Percentage ABR Loans SOFR Loans Commitment Fee Less than 25% 0.75 % 1.75 % 0.375 % Greater than or equal to 25% but less than 50% 1.00 % 2.00 % 0.375 % Greater than or equal to 50% but less than 75% 1.25 % 2.25 % 0.500 % Greater than or equal to 75% but less than 90% 1.50 % 2.50 % 0.500 % Greater than or equal to 90% 1.75 % 2.75 % 0.500 %

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Changes in Asset Retirement Obligations	The following table reflects the changes in the Company’s ARO: Year Ended December 31, 2023 2022 (In thousands) Asset retirement obligation — beginning of period $ 165,405 $ 62,416 Liabilities incurred during period 1,238 852 Liabilities incurred through acquisitions 6,771 87,265 Liabilities settled during period (4,389) (4,532) Liabilities settled through divestitures (31,844) (8,535) Accretion expense during period 11,183 7,613 Revisions to estimates 17,182 20,326 Asset retirement obligation — end of period $ 165,546 $ 165,405

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense	The Company’s income tax expense (benefit) from continuing operations consists of the following: Year Ended December 31, 2023 2022 2021 (In thousands) Current: Federal $ 15,877 $ 7,127 $ — State 3,824 883 4 Total current tax expense 19,701 8,010 4 Deferred: Federal 264,154 (46,767) (977) State 31,394 (8,127) — Total deferred tax expense (benefit) 295,548 (54,894) (977) Total income tax expense (benefit) $ 315,249 $ (46,884) $ (973)
Schedule of Effective Income Tax Rate Reconciliation	The reconciliation of income taxes from continuing operations calculated at the U.S. federal tax statutory rate to the Company’s effective tax rate is set forth below: Year Ended December 31, 2023 2022 2021 (%) (In thousands) (%) (In thousands) (%) (In thousands) U.S. federal tax statutory rate 21.0 % $ 281,196 21.0 % $ 291,068 21.0 % $ 39,477 State income taxes, net of federal income tax benefit 2.6 % 35,219 2.6 % 36,156 3.0 % 5,679 Non-deductible executive compensation 0.4 % 5,999 0.7 % 9,204 1.3 % 2,510 Change in valuation allowance — % — (27.2) % (377,233) (71.7) % (134,713) Discharge of debt and nondeductible professional fees — % — — % — 46.3 % 87,070 Other (0.5) % (7,165) (0.5) % (6,079) (0.4) % (996) Annual effective tax expense (benefit) 23.5 % $ 315,249 (3.4) % $ (46,884) (0.5) % $ (973)
Schedule of Deferred Tax Assets and Liabilities	Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2023 and 2022 were as follows: December 31, 2023 2022 (In thousands) Deferred tax assets Net operating loss carryforward $ 318,145 $ 316,085 Derivative instruments — 72,761 Bonus and equity-based compensation 14,324 9,806 Other deferred tax assets 17,469 7,863 Total deferred tax assets 349,938 406,515 Less: Valuation allowance (9,266) (9,617) Total deferred tax assets, net $ 340,672 $ 396,898 Deferred tax liabilities Oil and natural gas properties $ 367,046 $ 117,995 Derivative instruments 3,638 — Investment in partnerships 54,452 69,867 Other deferred tax liabilities 10,858 8,810 Total deferred tax liabilities $ 435,994 $ 196,672 Total deferred tax assets (liabilities), net $ (95,322) $ 200,226

Equity-Based Compensation (Tabl

Equity-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Schedule of Summarized Information Related to Restricted Stock and Restricted Units	The following table summarizes information related to RSUs held by employees and non-employee directors of the Company: Shares Weighted Average Non-vested shares outstanding December 31, 2022 421,583 $ 88.26 Granted 161,875 137.43 Vested (310,683) 104.24 Forfeited (9,716) 107.65 Non-vested shares outstanding December 31, 2023 263,059 $ 98.94
Schedule of Summarized Information Related to Performance Share Units	The following table summarizes information related to PSUs held by employees of the Company: Shares Weighted Average Non-vested shares outstanding December 31, 2022 373,141 $ 92.53 Granted — — Vested (283,925) 98.28 Forfeited (10,273) 109.30 Non-vested shares outstanding December 31, 2023 78,943 $ 69.67
Schedule of Nonvested Leveraged Stock Units Activity	The following table summarizes information related to LSUs held by employees of the Company: Shares Weighted Average Non-vested shares outstanding December 31, 2022 497,037 $ 84.59 Granted — — Vested — — Forfeited — — Non-vested shares outstanding December 31, 2023 497,037 $ 84.59
Schedule of Assumptions	The following table summarizes the assumptions used in the Monte Carlo simulation model to determine the grant date fair value and associated equity-based compensation expenses by grant date: Grant date January 18, 2021 February 11, 2021 April 13, 2021 Forecast period (years) 3 - 4 3 - 4 3 - 4 Risk-free interest rates 0.2% - 0.3% 0.2% - 0.3% 0.3% - 0.6% Implied equity volatility 55% - 60% 55% - 60% 45% - 50% Stock price on date of grant $44.41 $49.66 $68.07
Schedule of Summarized Information Related to Phantom Units	The following table summarizes information related to phantom unit awards held by employees of the Company: Phantom Unit Awards Weighted Average Non-vested phantom unit awards outstanding December 31, 2022 7,868 $ 135.91 Granted 9,919 166.23 Vested (7,100) 149.26 Forfeited (644) 156.38 Non-vested phantom unit awards outstanding December 31, 2023 10,043 $ 165.87

Stockholder's Equity (Tables)

Stockholder's Equity (Tables)	12 Months Ended
	Dec. 31, 2023
Stockholders' Equity Note [Abstract]
Schedule of Dividends Payable	The following table summarizes the Company’s fixed and variable dividends declared by quarter for the years ended December 31, 2023 and 2022: Rate per Share Base Variable Special Total Total Dividends Declared (In thousands) Q4 2023 $ 1.250 $ 1.250 $ — $ 2.500 $ 107,867 Q3 2023 1.250 0.110 — 1.360 58,374 Q2 2023 1.250 1.970 — 3.220 137,507 Q1 2023 1.250 3.550 — 4.800 204,884 Total $ 5.000 $ 6.880 $ — $ 11.880 $ 508,632 Q4 2022 $ 1.250 $ 2.420 $ — $ 3.670 $ 157,673 Q3 2022 1.250 — — 1.250 70,242 Q2 2022 0.585 2.940 15.000 18.525 379,369 Q1 2022 0.585 3.000 — 3.585 73,074 Total $ 3.670 $ 8.360 $ 15.000 $ 27.030 $ 680,358
Schedule of Warrants	The following table summarizes the Company’s outstanding warrants as of December 31, 2023: Warrants (1) Exercise Price (2) Legacy Oasis 575,717 $ 75.57 Legacy Whiting - Series A 1,318,369 $ 116.37 Legacy Whiting - Series B 1,338,568 $ 133.70 Total 3,232,654 __________________ (1) Represents the number of warrants in terms of shares of Chord common stock. (2) The exercise price of legacy Whiting warrants was adjusted in accordance with the Merger Agreement.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2023
Earnings Per Share [Abstract]
Schedule of Weighted-Average Number of Shares Outstanding	The following table summarizes the basic and diluted earnings per share for the periods presented: Year Ended December 31, 2023 2022 2021 (In thousands, except per share data) Net income from continuing operations $ 1,023,779 $ 1,430,463 $ 188,960 Distributed and undistributed earnings from continuing operations allocated to participating securities (3,370) (182) — Net income from continuing operations attributable to common stockholders (basic) 1,020,409 1,430,281 188,960 Reallocation of distributed and undistributed earnings from continuing operations allocated to participating securities 76 6 — Net income from continuing operations attributable to common stockholders (diluted) $ 1,020,485 $ 1,430,287 $ 188,960 Weighted average common shares outstanding: Basic weighted average common shares outstanding 41,490 30,497 19,792 Dilutive effect of share-based awards 944 1,134 856 Dilutive effect of warrants 964 620 — Diluted weighted average common shares outstanding 43,398 32,251 20,648 Basic earnings per share from continuing operations $ 24.59 $ 46.90 $ 9.55 Diluted earnings per share from continuing operations $ 23.51 $ 44.35 $ 9.15 Anti-dilutive weighted average common shares: Potential common shares 3,709 2,901 2,144

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Schedule of Components of Lease Costs	The Company’s long-term leases consist primarily of office space, vehicles and other property and equipment used in its operations. The components of lease costs attributable to continuing operations were as follows for the periods presented: Year Ended December 31, 2023 2022 2021 (In thousands) Operating lease costs $ 9,853 $ 11,292 $ 2,966 Variable lease costs (1) 13,391 8,562 1,737 Short-term lease costs 56,100 25,716 8,244 Sublease income (199) — — Finance lease costs: Amortization of ROU assets 1,367 1,342 1,578 Interest on lease liabilities 126 65 86 Total lease costs $ 80,638 $ 46,977 $ 14,611 ___________________ (1) Based on payments made by the Company to lessors for the right to use an underlying asset that vary because of changes in circumstances occurring after the commencement date, other than the passage of time, such as property taxes, operating and maintenance costs, which do not depend on an index or rate.
Schedule of Maturities of Company's Finance Leases	As of December 31, 2023, maturities of the Company’s lease liabilities were as follows: Operating Leases Finance Leases (In thousands) 2024 $ 14,880 $ 1,025 2025 7,997 913 2026 5,100 684 2027 2,116 352 2028 2,010 17 Thereafter 3,425 — Total future lease payments 35,528 2,991 Less: Imputed interest 3,548 249 Present value of future lease payments $ 31,980 $ 2,742
Schedule of Maturities of Company's Operating Leases	As of December 31, 2023, maturities of the Company’s lease liabilities were as follows: Operating Leases Finance Leases (In thousands) 2024 $ 14,880 $ 1,025 2025 7,997 913 2026 5,100 684 2027 2,116 352 2028 2,010 17 Thereafter 3,425 — Total future lease payments 35,528 2,991 Less: Imputed interest 3,548 249 Present value of future lease payments $ 31,980 $ 2,742
Schedule of Supplemental Balance Sheet Information Related to Company's Leases	Supplemental balance sheet information related to the Company’s leases were as follows: Balance Sheet Location December 31, 2023 December 31, 2022 (In thousands) Assets Operating lease assets (1) Operating right-of-use assets $ 21,343 $ 23,875 Finance lease assets (2)(3) Other assets 2,748 1,803 Total lease assets $ 24,091 $ 25,678 Liabilities Current Operating lease liabilities (1) Current operating lease liabilities $ 13,258 $ 9,941 Finance lease liabilities (3) Other current liabilities 916 1,012 Long-term Operating lease liabilities (1) Operating lease liabilities 18,667 13,266 Finance lease liabilities (3) Other liabilities 1,881 789 Total lease liabilities $ 34,722 $ 25,008 ___________________ (1) The Company acquired certain operating leases for office buildings and operating equipment in connection with the Merger. As of December 31, 2022, these included operating lease assets of $14.5 million, current operating lease liabilities of $2.5 million and long-term operating lease liabilities of $11.9 million. (2) Finance lease ROU assets are recorded net of accumulated amortization of $1.2 million as of December 31, 2023 and $1.6 million as of December 31, 2022. (3) The Company acquired certain finance leases for vehicles in connection with the Merger. As of December 31, 2022, these included finance lease assets of $1.4 million, current finance lease liabilities of $0.8 million and long-term finance lease liabilities of $0.6 million.
Schedule of Supplemental Cash Flow Information and Non-cash Transactions	Supplemental cash flow information and non-cash transactions related to the Company’s leases were as follows: Year Ended December 31, 2023 2022 2021 (In thousands) Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 15,627 $ 15,843 $ 3,420 Operating cash flows from finance leases 160 57 62 Financing cash flows from finance leases 1,702 1,299 1,161 ROU assets obtained in exchange for lease obligations Operating leases (1) $ 22,201 $ 20,164 $ 14,140 Finance leases (2) 2,307 2,659 127 ___________________ (1) The year ended December 31, 2022 includes $15.8 million related to operating leases acquired in the Merger. The year ended December 31, 2021 includes $12.3 million related to operating leases acquired in the 2021 Williston Basin Acquisition. (2) The year ended December 31, 2022 includes $2.1 million related to finance leases acquired in the Merger.
Schedule of Weighted-average Lease Terms and Discount Rates for the Company's Leases	Weighted-average remaining lease terms and discount rates for the Company’s leases were as follows: December 31, 2023 2022 Operating Leases Weighted average remaining lease term 3.6 years 4.6 years Weighted average discount rate 6.3 % 4.9 % Finance Leases Weighted average remaining lease term 3.2 years 2.3 years Weighted average discount rate 5.7 % 5.4 %

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Schedule of Minimum Volume Commitments	The estimable future commitments under these volume commitment agreements as of December 31, 2023 are as follows: (In thousands) 2024 $ 100,434 2025 100,966 2026 83,045 2027 62,079 2028 31,109 Thereafter 13,939 $ 391,572

Supplemental Oil and Gas Disc_2

Supplemental Oil and Gas Disclosures - Unaudited (Tables)	12 Months Ended
	Dec. 31, 2023
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of Capitalized Costs Related to Oil and Natural Gas Producing Activities	The following table sets forth the capitalized costs related to the Company’s oil and gas producing activities: December 31, 2023 2022 (In thousands) Proved oil and gas properties $ 6,220,766 $ 5,089,185 Less: Accumulated depletion and impairment (1,035,393) (461,175) Proved oil and gas properties, net 5,185,373 4,628,010 Unproved oil and gas properties 99,477 30,936 Total oil and gas properties, net $ 5,284,850 $ 4,658,946
Schedule of Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities	The following table sets forth costs incurred related to the Company’s oil and gas activities for the periods presented: Year Ended December 31, 2023 2022 2021 (In thousands) Acquisition costs: Proved oil and gas properties $ 178,629 $ 3,164,665 $ 605,868 Unproved oil and gas properties 185,392 43,084 85 Exploration costs 6,366 859 1 Development costs 922,506 507,961 170,178 Asset retirement costs 18,461 21,165 15,750 Total costs incurred $ 1,311,354 $ 3,737,734 $ 791,882
Schedule of Results of Operations for Oil and Natural Gas Producing Activities	The following table sets forth the results of operations for oil and gas producing activities, which exclude general and administrative expenses and interest expense, for the periods presented: Year Ended December 31, 2023 2022 2021 (In thousands) Revenues $ 3,132,411 $ 2,976,296 $ 1,200,256 Production costs 1,099,159 814,588 403,382 Depreciation, depletion and amortization 582,127 354,050 109,881 Exploration and impairment 17,830 2,204 2,763 Income tax expense 335,534 426,087 162,163 Results of operations for oil and gas producing activities $ 1,097,761 $ 1,379,367 $ 522,067

Supplemental Oil and Gas Rese_2

Supplemental Oil and Gas Reserve Information - Unaudited (Tables)	12 Months Ended
	Dec. 31, 2023
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of Net Proved, Proved Developed and Proved Undeveloped Reserves	The following table summarizes changes in quantities of the Company’s estimated net proved reserves by product for the periods presented: Crude Oil NGLs (1) (MBbl) Natural Gas MBoe (2) 2021 Proved reserves Beginning balance 119,765 — 376,170 182,460 Revisions of previous estimates 42,411 — 68,768 53,871 Extensions, discoveries and other additions 7,734 — 14,539 10,157 Sales of reserves in place (24,760) — (40,211) (31,461) Purchases of reserves in place 42,656 — 86,153 57,015 Production (13,489) — (46,157) (21,182) Net proved reserves at December 31, 2021 174,317 — 459,262 250,860 Proved developed reserves, December 31, 2021 114,041 — 361,836 174,347 Proved undeveloped reserves, December 31, 2021 60,276 — 97,426 76,513 2022 Proved reserves Beginning balance 174,317 — 459,262 250,860 Revisions of previous estimates (8,032) 64,557 (56,500) 47,110 Extensions, discoveries and other additions 38,144 7,452 35,689 51,544 Sales of reserves in place — — — — Purchases of reserves in place 202,316 73,468 443,903 349,768 Production (25,457) (7,026) (67,428) (43,722) Net proved reserves at December 31, 2022 381,288 138,451 814,926 655,560 Proved developed reserves, December 31, 2022 272,529 115,227 689,651 502,698 Proved undeveloped reserves, December 31, 2022 108,759 23,224 125,275 152,862 2023 Proved reserves Beginning balance 381,288 138,451 814,926 655,560 Revisions of previous estimates (38,073) (5,270) (33,308) (48,895) Extensions, discoveries and other additions 53,207 15,046 62,273 78,632 Sales of reserves in place (3,999) (53) (3,067) (4,564) Purchases of reserves in place 12,375 3,052 20,060 18,771 Production (36,427) (13,047) (82,953) (63,300) Net proved reserves at December 31, 2023 368,371 138,179 777,931 636,204 Proved developed reserves, December 31, 2023 241,362 105,702 640,180 453,762 Proved undeveloped reserves, December 31, 2023 127,008 32,476 137,751 182,442 __________________ (1) For periods prior to July 1, 2022 , we reported crude oil and natural gas on a two-stream basis, and NGLs were combined with the natural gas stream when reporting reserves. As of July 1, 2022, NGLs are reported separately from the natural gas stream on a three-stream basis. This prospective change impacts the comparability of the periods presented. (2) Natural gas is converted to barrel of oil equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil. The following table summarizes the changes in the Company’s estimates of PUD reserves during 2023: Year Ended December 31, 2023 (MBoe) Proved undeveloped reserves, beginning of period 152,862 Purchases of minerals in place 7,167 Extensions, discoveries and other additions 74,514 Revisions of previous estimates (8,198) Conversion to proved developed reserves (43,903) Proved undeveloped reserves, end of period 182,442
Schedule of Standardized Measure of Discounted Future Cash Flows	The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s estimated net proved reserves at December 31, 2023, 2022 and 2021: At December 31, 2023 2022 2021 (In thousands) Future cash inflows $ 31,882,940 $ 44,544,247 $ 13,366,064 Future production costs (13,815,882) (15,879,712) (6,548,794) Future development costs (3,055,823) (2,553,605) (1,322,207) Future income tax expense (2,573,017) (5,283,201) (717,721) Future net cash flows 12,438,218 20,827,729 4,777,342 10% annual discount for estimated timing of cash flows (5,447,578) (9,333,254) (2,080,404) Standardized measure of discounted future net cash flows $ 6,990,640 $ 11,494,475 $ 2,696,938
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows Applicable to Proved Oil and Natural Gas Reserves	The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to estimated net proved reserves for the periods presented: 2023 2022 2021 (In thousands) January 1 $ 11,494,475 $ 2,696,938 $ 948,877 Net changes in prices and production costs (6,138,846) 3,148,745 1,617,331 Net changes in future development costs (92,072) 35,427 (36,645) Sales of crude oil and natural gas, net (2,033,251) (2,161,708) (796,874) Extensions 864,249 958,924 98,125 Purchases of reserves in place 373,913 7,441,750 780,442 Sales of reserves in place (75,097) — (204,153) Revisions of previous quantity estimates (1,142,960) 1,434,357 639,320 Previously estimated development costs incurred 574,607 137,534 102,519 Accretion of discount 1,445,215 683,631 94,090 Net change in income taxes 1,419,851 (2,539,182) (252,347) Changes in timing and other 300,556 (341,941) (293,747) December 31 $ 6,990,640 $ 11,494,475 $ 2,696,938

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Narrative (Details)		12 Months Ended
	Nov. 03, 2023 shares	Dec. 31, 2023 USD ($) segment counterparty	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($) segment
Property, Plant and Equipment [Line Items]
Number of reportable segments | segment		1		2
Number of business segments | segment		1		2
Capitalized interest costs		$ 4,100,000	$ 4,600,000	$ 2,100,000
Amount of capitalized exploratory well costs that have been capitalized for period greater than one year		$ 0
Derivative, number of counterparties | counterparty		9
Past-due receivables from counterparties		$ 0
Unrecognized tax benefits		$ 0	$ 0
Energy Transfer | Crestwood Equity Partners LP
Property, Plant and Equipment [Line Items]
Shares issued (in shares) | shares	2.07
Furniture, Software and Equipment | Minimum
Property, Plant and Equipment [Line Items]
Estimated life of assets		2 years
Produced and Flowback Water Disposal Facilities, Natural Gas Processing Plants and Pipelines
Property, Plant and Equipment [Line Items]
Estimated life of assets		30 years

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Well Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Beginning of period	$ 0	$ 1	$ 0
Exploratory well cost additions (pending determination of proved reserves)	0	21	0
Exploratory well cost reclassifications (successful determination of proved reserves)	0	(2)	0
Exploratory well dry hole costs (unsuccessful in adding proved reserves)	0	0	0
Exploratory well cost reclassifications (canceled wells written off to predrill write-off)	0	(20)	1
End of period	$ 0	$ 0	$ 1

Revenue Recognition - Disaggreg

Revenue Recognition - Disaggregation of Revenues (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Revenues	$ 3,896,641	$ 3,646,794	$ 1,579,926
Crude oil revenues
Disaggregation of Revenue [Line Items]
Revenues	2,835,962	2,366,995	910,381
Purchased crude oil sales
Disaggregation of Revenue [Line Items]
Revenues	709,817	511,020	247,252
NGL and natural gas revenues
Disaggregation of Revenue [Line Items]
Revenues	296,449	609,301	289,875
Purchased NGL and natural gas sales
Disaggregation of Revenue [Line Items]
Revenues	54,413	159,154	131,731
Other services revenues
Disaggregation of Revenue [Line Items]
Revenues	$ 0	$ 324	$ 687

Inventory (Details)

Inventory (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Inventory
Equipment and materials	$ 30,201	$ 21,097
Crude oil inventory	42,364	33,314
Total inventory	72,565	54,411
Long-term inventory
Linefill in third-party pipelines	22,936	22,009
Total long-term inventory	22,936	22,009
Total	$ 95,501	$ 76,420

Additional Balance Sheet Info_3

Additional Balance Sheet Information (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 956,927	$ 788,893
Less: allowance for credit losses	(13,813)	(7,155)
Total accounts receivable, net	943,114	781,738
Royalties payable	297,531	368,574
Revenue suspense	266,704	203,388
Production taxes payable	40,469	36,002
Revenues and production taxes payable	604,704	607,964
Accrued oil and gas marketing	165,141	127,240
Accrued capital costs	122,260	76,747
Accrued lease operating expenses	107,606	73,714
Accrued general and administrative expenses	37,882	42,259
Current portion of asset retirement obligations	10,507	19,376
Accrued dividends	25,167	5,873
Other accrued liabilities	24,818	17,245
Total accrued liabilities	493,381	362,454
Trade and other accounts
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	749,356	661,121
Joint interest accounts
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 207,571	$ 127,772

Fair Value Measurements - Hiera

Fair Value Measurements - Hierarchy of Fair Value, Assets and Liabilities Measured on Recurring Basis (Details) - Recurring - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Assets:
Total assets	$ 160,067	$ 192,275
Total liabilities	14,926	344,370
Commodity derivatives
Assets:
Total assets	17,189	780
Total liabilities	14,926	344,370
Contingent consideration
Assets:
Total assets	42,706	60,920
Investment in unconsolidated affiliate
Assets:
Total assets	100,172	130,575
Level 1
Assets:
Total assets	100,172	130,575
Total liabilities	0	0
Level 1 | Commodity derivatives
Assets:
Total assets	0	0
Total liabilities	0	0
Level 1 | Contingent consideration
Assets:
Total assets	0	0
Level 1 | Investment in unconsolidated affiliate
Assets:
Total assets	100,172	130,575
Level 2
Assets:
Total assets	54,018	61,700
Total liabilities	14,926	329,676
Level 2 | Commodity derivatives
Assets:
Total assets	11,312	780
Total liabilities	14,926	329,676
Level 2 | Contingent consideration
Assets:
Total assets	42,706	60,920
Level 2 | Investment in unconsolidated affiliate
Assets:
Total assets	0	0
Level 3
Assets:
Total assets	5,877	0
Total liabilities	0	14,694
Level 3 | Commodity derivatives
Assets:
Total assets	5,877	0
Total liabilities	0	14,694
Level 3 | Contingent consideration
Assets:
Total assets	0	0
Level 3 | Investment in unconsolidated affiliate
Assets:
Total assets	$ 0	$ 0

Fair Value Measurements - Narra

Fair Value Measurements - Narrative (Details) $ in Millions		1 Months Ended	12 Months Ended
	May 20, 2021 USD ($)	Jan. 31, 2024 USD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($) instrument $ / bbl	Dec. 31, 2022 USD ($)	Jun. 30, 2021 payment
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net derivative liability adjustment					$ 0.5	$ 3.5
Number of contracts acquired | instrument					2
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Primary Permian Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of earn-out payments | payment							3
Proceeds from divestiture	$ 375				$ 25
Contingent consideration, minimum average daily settlement price, requiring additional payment (in dollars per barrel) | $ / bbl					60
Contingent consideration, minimum average daily settlement price, requiring additional payment (in dollars per barrel) | $ / bbl					45
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Primary Permian Basin | Subsequent Event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture		$ 25
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Primary Permian Basin | Expected
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture			$ 25	$ 25

Derivative Instruments - Narrat

Derivative Instruments - Narrative (Details) bbl in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) instrument	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($) $ / bbl bbl	May 20, 2021 USD ($)	Dec. 31, 2020 $ / bbl
Derivative [Line Items]
Payments for derivative modifications	$ 0	$ 0	$ 220,889
Number of contracts acquired | instrument	2
Number of contracts expired | instrument	1
Derivative assets, gross amount	$ 85,990	71,114
Derivative liabilities, gross amount	41,021	353,784
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Primary Permian Basin
Derivative [Line Items]
Contingent consideration	42,700			$ 32,900
Derivative instruments — current liabilities | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Primary Permian Basin
Derivative [Line Items]
Contingent consideration	22,600
Derivative instruments — non-current liabilities | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Primary Permian Basin
Derivative [Line Items]
Contingent consideration	20,100
Commodity derivatives (buy/sell transportation contracts)
Derivative [Line Items]
Derivative assets, gross amount	5,877
Derivative liabilities, gross amount		14,700
Commodity derivatives (buy/sell transportation contracts) | Derivative instruments — current liabilities
Derivative [Line Items]
Derivative assets, gross amount	$ 5,900
Derivative liabilities, gross amount		11,865
Commodity derivatives (buy/sell transportation contracts) | Derivative instruments — non-current liabilities
Derivative [Line Items]
Derivative liabilities, gross amount		$ 2,829
NYMEX WTI | Crude Oil (MBbl) | 2022 Fixed price swaps
Derivative [Line Items]
Weighted average prices (in dollars per barrel / dollars per btu) | $ / bbl			70		40.89
Volumes (in Bbls / in Gallons) | bbl			6,935
NYMEX WTI | Crude Oil (MBbl) | 2023 Fixed price swaps
Derivative [Line Items]
Weighted average prices (in dollars per barrel / dollars per btu) | $ / bbl			50		43.68
Volumes (in Bbls / in Gallons) | bbl			5,110

Derivative Instruments - Schedu

Derivative Instruments - Schedule of Outstanding Commodity Derivative Instruments (Details)	2 Months Ended	12 Months Ended
	Feb. 26, 2024 $ / bbl bbl	Dec. 31, 2023 MMBTU $ / bbl $ / gal bbl
NYMEX WTI | Crude Oil (MBbl) | 2024 Two-way collars
Derivative [Line Items]
Volumes (in Bbls / in Gallons) | bbl		4,660,000
Weighted Average Prices, Floor (in dollars per barrel / dollars per btu)		64.31
Weighted Average Prices, Ceiling (in dollars per barrel / dollars per btu)		83.89
NYMEX WTI | Crude Oil (MBbl) | 2024 Two-way collars | Subsequent Event
Derivative [Line Items]
Volumes (in Bbls / in Gallons) | bbl	825,000
Weighted Average Prices, Floor (in dollars per barrel / dollars per btu)	66.65
Weighted Average Prices, Ceiling (in dollars per barrel / dollars per btu)	81.94
NYMEX WTI | Crude Oil (MBbl) | 2024 Three-way collars
Derivative [Line Items]
Volumes (in Bbls / in Gallons) | bbl		736,000
Weighted Average Prices, Sub-Floor (in usd per bbl)		55
Weighted Average Prices, Floor (in dollars per barrel / dollars per btu)		71.25
Weighted Average Prices, Ceiling (in dollars per barrel / dollars per btu)		92.14
NYMEX WTI | Crude Oil (MBbl) | 2024 Fixed-price swaps
Derivative [Line Items]
Volumes (in Bbls / in Gallons) | bbl		366,000
Weighted average prices (in dollars per barrel / dollars per btu)		69.27
NYMEX WTI | Crude Oil (MBbl) | 2025 Two-way collars
Derivative [Line Items]
Volumes (in Bbls / in Gallons) | bbl		1,181,000
Weighted Average Prices, Floor (in dollars per barrel / dollars per btu)		60
Weighted Average Prices, Ceiling (in dollars per barrel / dollars per btu)		79.05
NYMEX WTI | Crude Oil (MBbl) | 2025 Three-way collars
Derivative [Line Items]
Volumes (in Bbls / in Gallons) | bbl		1,276,000
Weighted Average Prices, Sub-Floor (in usd per bbl)		50.71
Weighted Average Prices, Floor (in dollars per barrel / dollars per btu)		65.71
Weighted Average Prices, Ceiling (in dollars per barrel / dollars per btu)		82.60
NYMEX WTI | Crude Oil (MBbl) | 2025 Three-way collars | Subsequent Event
Derivative [Line Items]
Volumes (in Bbls / in Gallons) | bbl	1,095,000
Weighted Average Prices, Sub-Floor (in usd per bbl)	55
Weighted Average Prices, Floor (in dollars per barrel / dollars per btu)	70
Weighted Average Prices, Ceiling (in dollars per barrel / dollars per btu)	81.62
NYMEX WTI | Crude Oil (MBbl) | 2026 Three Way Collars | Subsequent Event
Derivative [Line Items]
Volumes (in Bbls / in Gallons) | bbl	270,000
Weighted Average Prices, Sub-Floor (in usd per bbl)	50
Weighted Average Prices, Floor (in dollars per barrel / dollars per btu)	65
Weighted Average Prices, Ceiling (in dollars per barrel / dollars per btu)	83.70
NYMEX HH | Natural Gas (MMcf) | 2025 Fixed-price swaps
Derivative [Line Items]
Volumes (in MMBtu) | MMBTU		651,600
Weighted average prices (in dollars per barrel / dollars per btu) | $ / gal		3.93

Derivative Instruments - Realiz

Derivative Instruments - Realized and Unrealized Gains and Losses from Commodity Derivative Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Net gain (loss) on derivative instruments	$ 63,182	$ (208,128)	$ (589,641)
Net gain (loss) on derivative instruments | Contingent consideration
Derivative [Line Items]
Net gain (loss) on derivative instruments	6,786	16,110	11,950
Gain on sale of assets, net | Contingent consideration
Derivative [Line Items]
Net gain (loss) on derivative instruments	0	0	32,860
Commodity derivatives
Derivative [Line Items]
Net gain (loss) on derivative instruments	56,396	(224,238)	(601,591)
Commodity derivatives (buy/sell transportation contracts)
Derivative [Line Items]
Net gain (loss) on derivative instruments	$ 20,570	$ 7,331	$ 0

Derivative Instruments - Locati

Derivative Instruments - Location and Fair Value of Commodity Derivatives (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Derivatives assets:
Gross Amount	$ 85,990	$ 71,114
Gross Amount Offset	(26,095)	(9,414)
Net Amount	$ 59,895	$ 61,700
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Derivative instruments	Derivative instruments
Derivatives liabilities:
Gross Amount	$ 41,021	$ 353,784
Gross Offset Amount	(26,095)	(9,414)
Net Amount	14,926	$ 344,370
Derivative Liability, Statement of Financial Position [Extensible Enumeration]		Derivative instruments
Commodity derivatives
Derivatives assets:
Gross Amount		$ 10,194
Gross Amount Offset		(9,414)
Net Amount		780
Derivatives liabilities:
Gross Amount		339,090
Gross Offset Amount		(9,414)
Net Amount		329,676
Commodity derivatives | Derivative instruments — current assets
Derivatives assets:
Gross Amount	20,647
Gross Amount Offset	(11,769)
Net Amount	8,878
Commodity derivatives | Derivative instruments — non-current assets
Derivatives assets:
Gross Amount	16,760
Gross Amount Offset	(14,326)
Net Amount	2,434
Commodity derivatives | Derivative instruments — current liabilities
Derivatives liabilities:
Gross Amount	25,978
Gross Offset Amount	(11,769)
Net Amount	14,209
Commodity derivatives | Derivative instruments — non-current liabilities
Derivatives liabilities:
Gross Amount	15,043
Gross Offset Amount	(14,326)
Net Amount	717
Contingent consideration | Derivative instruments — current assets
Derivatives assets:
Gross Amount	22,614	22,955
Gross Amount Offset	0	0
Net Amount	22,614	22,955
Contingent consideration | Derivative instruments — non-current assets
Derivatives assets:
Gross Amount	20,092	37,965
Gross Amount Offset	0	0
Net Amount	20,092	37,965
Commodity derivatives (buy/sell transportation contracts)
Derivatives assets:
Gross Amount	5,877
Gross Amount Offset	0
Net Amount	5,877
Derivatives liabilities:
Gross Amount		14,700
Commodity derivatives (buy/sell transportation contracts) | Derivative instruments — current liabilities
Derivatives assets:
Gross Amount	$ 5,900
Derivatives liabilities:
Gross Amount		11,865
Gross Offset Amount		0
Net Amount		11,865
Commodity derivatives (buy/sell transportation contracts) | Derivative instruments — non-current liabilities
Derivatives liabilities:
Gross Amount		2,829
Gross Offset Amount		0
Net Amount		$ 2,829

Property, Plant and Equipment -

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Proved oil and gas properties	$ 6,220,766	$ 5,089,185
Less: Accumulated depletion	(1,035,393)	(461,175)
Proved oil and gas properties, net	5,185,373	4,628,010
Unproved oil and gas properties	99,477	30,936
Other property and equipment	49,051	72,973
Less: Accumulated depreciation and impairment	(19,223)	(20,576)
Other property and equipment, net	29,828	52,397
Total property, plant and equipment, net	$ 5,314,678	$ 4,711,343

Property, Plant and Equipment_2

Property, Plant and Equipment - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Impairment charge	$ 28,963,000	$ (344,000)	$ 5,000
Proved Oil and Gas Properties
Property, Plant and Equipment [Line Items]
Impairment charge			0
Unproved oil and gas properties
Property, Plant and Equipment [Line Items]
Impairment charge	0	0	0
Other property and equipment
Property, Plant and Equipment [Line Items]
Impairment charge	0	$ 0	$ 0
Non-core Asset Sales
Property, Plant and Equipment [Line Items]
Impairment charge	$ 5,600,000

Acquisitions - Narrative (Detai

Acquisitions - Narrative (Details) a in Thousands	Jun. 30, 2023 USD ($)	May 22, 2023 USD ($) a	Jul. 01, 2022 USD ($) shares	Oct. 21, 2021 USD ($) a	May 21, 2021 USD ($)	May 03, 2021 USD ($)
Williston Basin
Business Acquisition [Line Items]
Cash consideration		$ 375,000,000
Williston Basin 2021 Acquisition
Business Acquisition [Line Items]
Area of Land | a				95
Cash consideration				$ 585,800,000
Payments for asset acquisitions					$ 511,300,000	$ 74,500,000
Williston Basin
Business Acquisition [Line Items]
Area of Land | a		62
Cash paid	$ 361,609,000
Security deposit	37,500,000
Payments for asset acquisitions	324,100,000
Estimated fair value	361,600,000
Goodwill	0
Bargain purchase gain	0
Net assets acquired	$ 361,609,000
Whiting Merger
Business Acquisition [Line Items]
Cash paid			$ 245,436,000
Goodwill			0
Bargain purchase gain			$ 0
Shares issued (in shares) | shares			22,671,871
Net assets acquired			$ 2,832,802,000
Assumed liability from success based transaction costs incurred by acquire			18,000,000
Loss accrual			$ 55,000,000

Acquisitions - Consideration Tr

Acquisitions - Consideration Transferred (Details) $ / shares in Units, $ in Thousands	Jun. 30, 2023 USD ($)	Jul. 01, 2022 USD ($) $ / shares shares	Dec. 31, 2023 $ / shares shares	Jun. 30, 2022 $ / shares	Jun. 29, 2022 $ / shares
Business Acquisition [Line Items]
Warrants outstanding (in shares) | shares			3,232,654
Exercise price of warrants or rights (in usd per share) | $ / shares				$ 75.57	$ 94.57
Legacy Whiting - Series A
Business Acquisition [Line Items]
Warrants outstanding (in shares) | shares			1,318,369
Exercise price of warrants or rights (in usd per share) | $ / shares		$ 116.37	$ 116.37
Legacy Whiting - Series B
Business Acquisition [Line Items]
Warrants outstanding (in shares) | shares			1,338,568
Exercise price of warrants or rights (in usd per share) | $ / shares		$ 133.70	$ 133.70
Williston Basin
Business Acquisition [Line Items]
Cash consideration transferred & Cash paid to Whiting stockholders | $	$ 361,609
Whiting Merger
Business Acquisition [Line Items]
Cash consideration transferred & Cash paid to Whiting stockholders | $		$ 245,436
Common stock issued to Whiting shareholder | $		2,478,036
Replacement of Whiting Series A Warrants and Whiting Series B Warrants | $		79,774
Replacement of Whiting equity-based compensation awards | $		27,402
Cash paid to settle Whiting credit facility | $		2,154
Total consideration transferred | $		$ 2,832,802
Shares issued (in shares) | shares		22,671,871
Conversion ratio		0.5774
Cash paid per share (in usd per share) | $ / shares		$ 6.25
Share price (in dollars per share) | $ / shares		$ 109.30
Whiting Merger | Legacy Whiting - Series A
Business Acquisition [Line Items]
Warrants outstanding (in shares) | shares		4,833,455
Exercise price of warrants or rights (in usd per share) | $ / shares		$ 11.25
Whiting Merger | Legacy Whiting - Series B
Business Acquisition [Line Items]
Warrants outstanding (in shares) | shares		2,418,832
Exercise price of warrants or rights (in usd per share) | $ / shares		$ 10.50

Acquisitions - Schedule of Purc

Acquisitions - Schedule of Purchase Price Allocation (Details) - USD ($) $ in Thousands	Jun. 30, 2023	Jul. 01, 2022
Williston Basin
Assets acquired:
Oil and gas properties	$ 367,672
Inventory	1,844
Total assets acquired	369,516
Liabilities assumed:
Asset retirement obligations	6,771
Revenues and production taxes payable	1,136
Total liabilities assumed	7,907
Net assets acquired	$ 361,609
Whiting Merger
Assets acquired:
Oil and gas properties		$ 3,211,043
Inventory		35,256
Cash and cash equivalents		94,641
Accounts receivable, net		491,514
Prepaid expenses		14,851
Other current assets		5,719
Current assets held for sale		16,074
Other property and equipment		31,244
Long-term inventory		3,138
Operating right-of-use assets		15,752
Deferred tax assets		228,574
Other assets		3,346
Total assets acquired		4,151,152
Liabilities assumed:
Asset retirement obligations		57,197
Revenues and production taxes payable		411,553
Accounts payable		116,769
Accrued liabilities		215,218
Derivatives instruments (current liability)		471,693
Current operating lease liabilities		2,629
Other current liabilities		2,902
Current liabilities held for sale		9,410
Derivative instruments (long-term liability)		15,128
Operating lease liabilities		13,123
Other liabilities		2,728
Total liabilities assumed		1,318,350
Net assets acquired		$ 2,832,802

Acquisitions - Schedule of Post

Acquisitions - Schedule of Post-Merger Operating Results (Details) - Whiting Merger $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($)
Business Acquisition [Line Items]
Revenues	$ 1,044,079
Income from continuing operations before income taxes	$ 553,686

Acquisitions - Schedule of Pro

Acquisitions - Schedule of Pro Forma Information (Details) - Whiting Merger - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Revenues	$ 4,759,706	$ 3,113,407
Net income attributable to Chord	$ 2,093,776	$ 477,184
Net income attributable to Chord per share:
Basic (in usd per share)	$ 50	$ 11.21
Diluted (in usd per share)	$ 47.88	$ 10.93

Divestitures - 2023 Divestiture

Divestitures - 2023 Divestitures (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal, Statement of Income or Comprehensive Income [Extensible Enumeration]	Revenues
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Non-Core Properties, Williston Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds received	$ 39.1
Pre-tax net loss on sale	8.4
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Non-Operated Wellbore Properties, Williston Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds received	12.1
Discontinued Operations, Held-for-sale | Williston Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment of assets held for sale	$ 5.6

Divestitures - 2022 Divestiture

Divestitures - 2022 Divestitures (Details) - USD ($) $ in Thousands	Sep. 12, 2022	Feb. 01, 2022	Dec. 31, 2023	Dec. 31, 2022	Jul. 14, 2022
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Investment in unconsolidated affiliate			$ 100,172	$ 130,575
Long-term debt, net			395,902	394,209
Line of Credit
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term debt, gross			0	0
Credit Facility | Line of Credit
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Outstanding letters of credit			8,900	6,400
Long-term debt, gross			0	0
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Rio Blanco County
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Purchase price of divestiture					$ 8,000
OMP Merger
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Shares issued (in shares)	16,000,000
Investment in unconsolidated affiliate			$ 100,200	$ 130,600
OMP Merger | Credit Facility | Line of Credit
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term debt, net		$ 203,000
Outstanding letters of credit		5,500
OMP Merger | OMP Senior Notes | Unsecured Debt
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term debt, gross		$ 450,000
Stated interest rate (as a percent)		8%
OMP Merger | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale of assets		$ 518,900
OMP Merger | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Crestwood Equity Partners LP
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash paid		$ 160,000
Shares issued (in shares)		20,985,668
Percentage ownership prior to merger		70%
Success based transaction costs		$ 11,400
OMP Merger | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Crestwood Equity Partners LP | Crestwood Equity Partners LP | Level 2
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Investment in unconsolidated affiliate		568,300
OMP Merger | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Crestwood Equity Partners LP | OMP GP | Level 2
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Investment in unconsolidated affiliate		$ 198,000

Divestitures - 2021 Divestiture

Divestitures - 2021 Divestitures (Details) $ in Millions					3 Months Ended	12 Months Ended
	Jun. 29, 2021 USD ($)	May 20, 2021 USD ($)	Mar. 30, 2021 USD ($) shares	Mar. 22, 2021 USD ($)	Jun. 30, 2021 USD ($) payment	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Simplification Transaction | Affiliated Entity
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cumulative cash distributions			$ 231.5
Ownership interest (in shares) | shares			12,949,644
Bobcat DevCo | Oasis Midstream Partners, LP
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage acquired			64.70%
Beartooth DevCo | Oasis Midstream Partners, LP
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage acquired			30%
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Primary Permian Basin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Purchase price of divestiture		$ 450
Proceeds from divestiture		$ 375						$ 25
Number of earn-out payments | payment					3
Proceeds from divestiture, net of adjustments	$ 342.3
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Primary Permian Basin | Expected
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture						$ 25	$ 25
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Permian Basin Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture, net of adjustments					$ 30
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Well Services Exit
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Purchase price of divestiture				$ 5.5
Proceeds from divestiture				2.6
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Well Services Exit | Notes Receivable
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Promissory note				$ 2.9				$ 0

Discontinued Operations and D_2

Discontinued Operations and Disposal Groups - Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income from discontinued operations attributable to Chord, net of income tax	$ 0	$ 425,696	$ 130,642
Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues		9,907	123,872
Lease operating expenses		(4,535)	(62,142)
Gathering, processing and transportation expenses		(3,555)	(49,795)
Depreciation, depletion and amortization		0	31,868
Impairment		0	2
General and administrative expenses		3,314	4,193
Total operating expenses		(4,058)	(79,543)
Gain on sale of assets		518,900	0
Operating income		532,865	203,415
Interest expense, net of capitalized interest		(3,685)	(36,945)
Other expense		(93)	(115)
Total other expense, net		(3,778)	(37,060)
Income from discontinued operations before income taxes		529,087	166,355
Income tax expense		(101,080)	(17)
Income from discontinued operations, net of income tax		428,007	166,338
Net income attributable to non-controlling interests		2,311	35,696
Income from discontinued operations attributable to Chord, net of income tax		425,696	130,642
Oil and Gas | Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues		0	1,013
Purchased Oil and Gas | Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues		(13,364)	(131,369)
Expenses		(12,506)	(125,709)
Midstream | Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total revenues		23,271	254,228
Expenses		$ 13,224	$ 122,040

Discontinued Operations and D_3

Discontinued Operations and Disposal Groups - Cash Flow Detail (Details) - Discontinued Operations - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash flows from operating activities	$ 0	$ 31.9
Cash flows from investing activities	$ 6.1	$ 38.5

Investment in Unconsolidated _2

Investment in Unconsolidated Affiliate (Details) - USD ($) $ in Thousands		12 Months Ended
	Sep. 12, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Schedule of Equity Method Investments [Line Items]
Investment in unconsolidated affiliate		$ 100,172	$ 130,575
Net gain from investment in unconsolidated affiliate		21,330	34,366	$ 0
Revenues
Schedule of Equity Method Investments [Line Items]
Related party transaction amount			15,700
Lease Operating Expenses | Related Party
Schedule of Equity Method Investments [Line Items]
Related party transaction amount			69,500
Gathering, Processing And Transportation Expenses | Related Party
Schedule of Equity Method Investments [Line Items]
Related party transaction amount			56,600
OMP Merger
Schedule of Equity Method Investments [Line Items]
Shares issued (in shares)	16,000,000
Investment in unconsolidated affiliate		100,200	130,600
Net gain from investment in unconsolidated affiliate			43,000
Unconsolidated affiliate, unrealized loss		8,400	52,500
Unconsolidated affiliate, realized gain		$ 10,800	$ 43,900
Net proceeds received	$ 428,200
OMP Merger | Crestwood Equity Partners LP
Schedule of Equity Method Investments [Line Items]
Ownership interest acquired	5%	5%

Long-term Debt - Schedule of Lo

Long-term Debt - Schedule of Long-term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Total long-term debt, net	$ 395,902	$ 394,209
Line of Credit
Debt Instrument [Line Items]
Long-term debt, gross	0	0
Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross	400,000	400,000
Less: unamortized deferred financing costs	$ (4,098)	$ (5,791)

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details) - USD ($) $ in Thousands		12 Months Ended
	Jul. 01, 2022	Dec. 31, 2023	Dec. 31, 2022	May 02, 2023	May 01, 2023	Jun. 09, 2021
Minimum
Debt Instrument [Line Items]
Total Revolving Commitment Utilization Percentage		85%
Line of Credit
Debt Instrument [Line Items]
Long-term debt, gross		$ 0	$ 0
Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross		$ 400,000	400,000
Stated interest rate (as a percent)		6.375%
Less: unamortized deferred financing costs on senior unsecured notes		$ 4,098	5,791
Senior Notes | Level 1
Debt Instrument [Line Items]
Long-term debt, fair value						$ 391,600
Senior Notes | Level 1
Debt Instrument [Line Items]
Long-term debt, fair value		$ 400,000	$ 389,600
Credit Facility
Debt Instrument [Line Items]
Weighted average interest rate (percent)		7.10%	4.60%
Credit Facility | Line of Credit
Debt Instrument [Line Items]
Line of credit sublimit		$ 2,500,000
Long-term debt, gross		0	$ 0
Outstanding letters of credit		8,900	6,400
Letter of credit unused borrowing base capacity		991,100
Line of credit				$ 2,500,000	$ 2,750,000
Credit Facility | Elected Commitments
Debt Instrument [Line Items]
Line of credit sublimit		$ 1,000,000
Credit Facility | Unsecured Debt
Debt Instrument [Line Items]
Less: unamortized deferred financing costs on senior unsecured notes						$ 8,400
Amended and Restated Credit Facility | Line of Credit | SOFR Loans
Debt Instrument [Line Items]
Spread on variable rate (as a percent)	0.10%
Credit Facility | Line of Credit
Debt Instrument [Line Items]
Maximum leverage ratio		3.50
Minimum current ratio		100%
Credit Facility | Letter of Credit
Debt Instrument [Line Items]
Line of credit sublimit		$ 100,000
Swingline Loan | Line of Credit
Debt Instrument [Line Items]
Line of credit sublimit		$ 50,000
Whiting Credit Facility | Line of Credit
Debt Instrument [Line Items]
Payment for debt extinguishment costs, including accrued interest	$ 2,200
Senior Secured Lien | Senior Notes
Debt Instrument [Line Items]
Write-off of specified default interest			$ 7,800

Long-Term Debt - Commitments (D

Long-Term Debt - Commitments (Details)	Jul. 01, 2022	Dec. 31, 2023
Amended and Restated Credit Facility | SOFR Loans | Line of Credit
Debt Instrument [Line Items]
Spread on variable rate (as a percent)	0.10%
Minimum
Debt Instrument [Line Items]
Total Revolving Commitment Utilization Percentage		85%
Less than 25% | Amended and Restated Credit Facility | Line of Credit
Debt Instrument [Line Items]
Commitment Fee	0.375%
Less than 25% | Amended and Restated Credit Facility | ABR Loans | Line of Credit
Debt Instrument [Line Items]
Spread on variable rate (as a percent)	0.75%
Less than 25% | Amended and Restated Credit Facility | SOFR Loans | Line of Credit
Debt Instrument [Line Items]
Spread on variable rate (as a percent)	1.75%
Less than 25% | Maximum
Debt Instrument [Line Items]
Total Revolving Commitment Utilization Percentage	25%
Greater than or equal to 25% but less than 50% | Amended and Restated Credit Facility | Line of Credit
Debt Instrument [Line Items]
Commitment Fee	0.375%
Greater than or equal to 25% but less than 50% | Amended and Restated Credit Facility | ABR Loans | Line of Credit
Debt Instrument [Line Items]
Spread on variable rate (as a percent)	1%
Greater than or equal to 25% but less than 50% | Amended and Restated Credit Facility | SOFR Loans | Line of Credit
Debt Instrument [Line Items]
Spread on variable rate (as a percent)	2%
Greater than or equal to 25% but less than 50% | Minimum
Debt Instrument [Line Items]
Total Revolving Commitment Utilization Percentage	25%
Greater than or equal to 25% but less than 50% | Maximum
Debt Instrument [Line Items]
Total Revolving Commitment Utilization Percentage	50%
Greater than or equal to 50% but less than 75% | Amended and Restated Credit Facility | Line of Credit
Debt Instrument [Line Items]
Commitment Fee	0.50%
Greater than or equal to 50% but less than 75% | Amended and Restated Credit Facility | ABR Loans | Line of Credit
Debt Instrument [Line Items]
Spread on variable rate (as a percent)	1.25%
Greater than or equal to 50% but less than 75% | Amended and Restated Credit Facility | SOFR Loans | Line of Credit
Debt Instrument [Line Items]
Spread on variable rate (as a percent)	2.25%
Greater than or equal to 50% but less than 75% | Minimum
Debt Instrument [Line Items]
Total Revolving Commitment Utilization Percentage	50%
Greater than or equal to 50% but less than 75% | Maximum
Debt Instrument [Line Items]
Total Revolving Commitment Utilization Percentage	75%
Greater than or equal to 75% but less than 90% | Amended and Restated Credit Facility | Line of Credit
Debt Instrument [Line Items]
Commitment Fee	0.50%
Greater than or equal to 75% but less than 90% | Amended and Restated Credit Facility | ABR Loans | Line of Credit
Debt Instrument [Line Items]
Spread on variable rate (as a percent)	1.50%
Greater than or equal to 75% but less than 90% | Amended and Restated Credit Facility | SOFR Loans | Line of Credit
Debt Instrument [Line Items]
Spread on variable rate (as a percent)	2.50%
Greater than or equal to 75% but less than 90% | Minimum
Debt Instrument [Line Items]
Total Revolving Commitment Utilization Percentage	75%
Greater than or equal to 75% but less than 90% | Maximum
Debt Instrument [Line Items]
Total Revolving Commitment Utilization Percentage	90%
Greater than or equal to 90% | Amended and Restated Credit Facility | Line of Credit
Debt Instrument [Line Items]
Commitment Fee	0.50%
Greater than or equal to 90% | Amended and Restated Credit Facility | ABR Loans | Line of Credit
Debt Instrument [Line Items]
Spread on variable rate (as a percent)	1.75%
Greater than or equal to 90% | Amended and Restated Credit Facility | SOFR Loans | Line of Credit
Debt Instrument [Line Items]
Spread on variable rate (as a percent)	2.75%
Greater than or equal to 90% | Minimum
Debt Instrument [Line Items]
Total Revolving Commitment Utilization Percentage	90%

Asset Retirement Obligations -

Asset Retirement Obligations - Schedule of Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation — beginning of period	$ 165,405	$ 62,416
Liabilities incurred during period	1,238	852
Liabilities incurred through acquisitions	6,771	87,265
Liabilities settled during period	(4,389)	(4,532)
Liabilities settled through divestitures	(31,844)	(8,535)
Accretion expense during period	11,183	7,613
Revisions to estimates	17,182	20,326
Asset retirement obligation — end of period	$ 165,546	$ 165,405

Asset Retirement Obligations _2

Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Current portion of asset retirement obligations	$ 10,507	$ 19,376

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current:
Federal	$ 15,877	$ 7,127	$ 0
State	3,824	883	4
Total current tax expense	19,701	8,010	4
Deferred:
Federal	264,154	(46,767)	(977)
State	31,394	(8,127)	0
Total deferred tax expense (benefit)	295,548	(54,894)	(977)
Total income tax expense (benefit)	$ 315,249	$ (46,884)	$ (973)

Income Taxes - Schedule of Effe

Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Effective Income Tax Rate Reconciliation, Percent
U.S. federal tax statutory rate	21%	21%	21%
State income taxes, net of federal income tax benefit	2.60%	2.60%	3%
Non-deductible executive compensation	0.40%	0.70%	1.30%
Change in valuation allowance	0%	(27.20%)	(71.70%)
Discharge of debt and nondeductible professional fees	0%	0%	46.30%
Other	(0.50%)	(0.50%)	(0.40%)
Annual effective tax expense (benefit)	23.50%	(3.40%)	(0.50%)
Effective Income Tax Rate Reconciliation, Amount
U.S. federal tax statutory rate	$ 281,196	$ 291,068	$ 39,477
State income taxes, net of federal income tax benefit	35,219	36,156	5,679
Non-deductible executive compensation	5,999	9,204	2,510
Change in valuation allowance	0	(377,233)	(134,713)
Discharge of debt and nondeductible professional fees	0	0	87,070
Other	(7,165)	(6,079)	(996)
Total income tax expense (benefit)	$ 315,249	$ (46,884)	$ (973)

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Deferred tax assets
Net operating loss carryforward	$ 318,145	$ 316,085
Derivative instruments	0	72,761
Bonus and equity-based compensation	14,324	9,806
Other deferred tax assets	17,469	7,863
Total deferred tax assets	349,938	406,515
Less: Valuation allowance	(9,266)	(9,617)
Total deferred tax assets, net	340,672	396,898
Deferred tax liabilities
Oil and natural gas properties	367,046	117,995
Derivative instruments	3,638	0
Investment in partnerships	54,452	69,867
Other deferred tax liabilities	10,858	8,810
Total deferred tax liabilities	435,994	196,672
Total deferred tax assets (liabilities), net	$ (95,322)
Total deferred tax assets (liabilities), net		$ 200,226

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Contingency [Line Items]
Effective tax rate (as a percent)	23.50%	(3.40%)	(0.50%)
Valuation allowance	$ (9,300,000)
Unrecognized tax benefits	0	$ 0
Federal
Income Tax Contingency [Line Items]
Net operating loss	1,087,000,000
Net operating loss, not subject to expiration	988,700,000
Net operating loss, subject to expiration	98,300,000
State
Income Tax Contingency [Line Items]
Net operating loss	$ 2,406,000,000

Equity-Based Compensation - Nar

Equity-Based Compensation - Narrative (Details)		12 Months Ended
	Jul. 01, 2022 USD ($) shares	Dec. 31, 2023 USD ($) $ / shares shares	Dec. 31, 2022 USD ($) $ / shares shares	Dec. 31, 2021 USD ($)
Whiting Equity Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares available for grant (in shares)	1,611,725
Whiting Equity Awards | Whiting Petroleum Corporation
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Business acquisition, equity interest issued or issuable, value assigned | $	$ 27,400,000
Employee stock ownership plan (esop), compensation expense | $	45,900,000
Equity-Classified Awards | Continuing Operations
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation | $		$ 46,100,000	$ 61,200,000	$ 14,700,000
Liability-Classified Awards | Continuing Operations
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation | $		$ 3,400,000	4,900,000	$ 500,000
Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested, shares (in shares)		310,683
Fair value of awards vested | $		$ 42,400,000	$ 62,300,000
Weighted average grant date fair value of awards granted (in usd share) | $ / shares		$ 137.43	$ 144.16
Unrecognized expense | $		$ 15,300,000
Unrecognized expense recognition period		1 year 10 months 24 days
Non-vested shares outstanding (in shares)		263,059	421,583
Restricted Stock Units | Non-Employee Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		1 year
Restricted Stock Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		3 years
Restricted Stock Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		4 years
Restricted Stock Units | Whiting Equity Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation | $	$ 73,300,000
Shares outstanding (in shares)	335,386
Performance Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested, shares (in shares)		283,925
Fair value of awards vested | $		$ 46,300,000	$ 16,600,000
Weighted average grant date fair value of awards granted (in usd share) | $ / shares		$ 0
Unrecognized expense | $		$ 1,100,000
Unrecognized expense recognition period		1 year 2 months 12 days
Awards granted (in shares)	250,016
Non-vested shares outstanding (in shares)		78,943	373,141
Additional shares granted (in shares)		0
Performance Share Units | Company's Oil and Gas Peers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Eligible to be earned, percentage		0.50
Performance Share Units | Broad Based Russell 2000 Index
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Eligible to be earned, percentage		0.50
Performance Share Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		3 years
Percentage of share awards based on shareholder return		0%
Performance Share Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		4 years
Percentage of share awards based on shareholder return		150%
Performance Share Units | OMP Merger
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Awards granted (in shares)	66,101
Non-vested shares outstanding (in shares)			183,915
Performance Share Units | Whiting Equity Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation | $	$ 73,300,000
Shares outstanding (in shares)	275,310
Restricted Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		3 years
Vested, shares (in shares)	64,920
Leveraged Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested, shares (in shares)		0
Fair value of awards vested | $		$ 0	$ 31,500,000
Weighted average grant date fair value of awards granted (in usd share) | $ / shares		$ 0
Unrecognized expense | $		$ 2,000,000
Unrecognized expense recognition period		1 year
Awards granted (in shares)	787,218
Non-vested shares outstanding (in shares)		497,037	497,037
Additional shares granted (in shares)		0
Threshold fair value ratio		10
Leveraged Stock Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		3 years
Percentage of share awards based on shareholder return		0%
Leveraged Stock Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		4 years
Percentage of share awards based on shareholder return		300%
Phantom Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		3 years
Vested, shares (in shares)		7,100
Fair value of awards vested | $		$ 1,100,000	$ 2,000,000
Weighted average grant date fair value of awards granted (in usd share) | $ / shares		$ 166.23
Unrecognized expense | $		$ 1,200,000
Unrecognized expense recognition period		2 years 1 month 6 days
Non-vested shares outstanding (in shares)		10,043	7,868
Number of shares for cash payment value (in shares)		1

Equity-Based Compensation - Sum

Equity-Based Compensation - Summarizes Information Related to Awards (Details) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Restricted Stock Units
Shares
Non-vested shares outstanding , beginning balance (in shares)	421,583
Granted, shares (in shares)	161,875
Vested, shares (in shares)	(310,683)
Forfeited, shares (in shares)	(9,716)
Non-vested shares outstanding, ending balance (in shares)	263,059	421,583
Weighted Average Grant Date Fair Value per Share
Non-vested shares outstanding, beginning balance (in usd per share)	$ 88.26
Granted (in usd per share)	137.43	$ 144.16
Vested (in usd per share)	104.24
Forfeited (in usd per share)	107.65
Non-vested shares outstanding, ending balance (in usd per share)	$ 98.94	$ 88.26
Performance Share Units
Shares
Non-vested shares outstanding , beginning balance (in shares)	373,141
Granted, shares (in shares)	0
Vested, shares (in shares)	(283,925)
Forfeited, shares (in shares)	(10,273)
Non-vested shares outstanding, ending balance (in shares)	78,943	373,141
Weighted Average Grant Date Fair Value per Share
Non-vested shares outstanding, beginning balance (in usd per share)	$ 92.53
Granted (in usd per share)	0
Vested (in usd per share)	98.28
Forfeited (in usd per share)	109.30
Non-vested shares outstanding, ending balance (in usd per share)	$ 69.67	$ 92.53
Leveraged Stock Units
Shares
Non-vested shares outstanding , beginning balance (in shares)	497,037
Granted, shares (in shares)	0
Vested, shares (in shares)	0
Forfeited, shares (in shares)	0
Non-vested shares outstanding, ending balance (in shares)	497,037	497,037
Weighted Average Grant Date Fair Value per Share
Non-vested shares outstanding, beginning balance (in usd per share)	$ 84.59
Granted (in usd per share)	0
Vested (in usd per share)	0
Forfeited (in usd per share)	0
Non-vested shares outstanding, ending balance (in usd per share)	$ 84.59	$ 84.59
Phantom Unit Awards
Shares
Non-vested shares outstanding , beginning balance (in shares)	7,868
Granted, shares (in shares)	9,919
Vested, shares (in shares)	(7,100)
Forfeited, shares (in shares)	(644)
Non-vested shares outstanding, ending balance (in shares)	10,043	7,868
Weighted Average Grant Date Fair Value per Share
Non-vested shares outstanding, beginning balance (in usd per share)	$ 135.91
Granted (in usd per share)	166.23
Vested (in usd per share)	149.26
Forfeited (in usd per share)	156.38
Non-vested shares outstanding, ending balance (in usd per share)	$ 165.87	$ 135.91

Equity-Based Compensation - Sch

Equity-Based Compensation - Schedule of Assumptions (Details) - PSUs and LSUs - $ / shares	Apr. 13, 2021	Feb. 11, 2021	Jan. 18, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock price on date of grant (in usd per share)	$ 68.07	$ 49.66	$ 44.41
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forecast period (years)	3 years	3 years	3 years
Risk-free interest rates	0.30%	0.20%	0.20%
Implied equity volatility	45%	55%	55%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Forecast period (years)	4 years	4 years	4 years
Risk-free interest rates	0.60%	0.30%	0.30%
Implied equity volatility	50%	60%	60%

Stockholders' Equity - Schedule

Stockholders' Equity - Schedule of Dividends Payable (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended								12 Months Ended
	Jul. 08, 2022	Dec. 31, 2023	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022
Dividends Payable [Line Items]
Dividends declared (in usd per share)		$ 2.500	$ 1.360	$ 3.220	$ 4.800	$ 3.670	$ 1.250	$ 18.525	$ 3.585	$ 11.880	$ 27.030
Total Dividends Declared		$ 107,867	$ 58,374	$ 137,507	$ 204,884	$ 157,673	$ 70,242	$ 379,369	$ 73,074	$ 508,632	$ 680,358
Base
Dividends Payable [Line Items]
Dividends declared (in usd per share)		$ 1.250	$ 1.250	$ 1.250	$ 1.250	$ 1.250	$ 1.250	$ 0.585	$ 0.585	$ 5	$ 3.670
Variable
Dividends Payable [Line Items]
Dividends declared (in usd per share)		1.250	0.110	1.970	3.550	2.420	0	2.940	3	6.880	8.360
Special
Dividends Payable [Line Items]
Dividends declared (in usd per share)	$ 15	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 15	$ 0	$ 0	$ 15

Stockholders' Equity - Narrativ

Stockholders' Equity - Narrative (Details) $ / shares in Units, $ in Thousands				3 Months Ended								12 Months Ended
	Feb. 21, 2024 $ / shares	Jul. 08, 2022 USD ($) $ / shares	Jul. 01, 2022 $ / shares shares	Dec. 31, 2023 USD ($) $ / shares shares	Sep. 30, 2023 $ / shares	Jun. 30, 2023 $ / shares shares	Mar. 31, 2023 $ / shares	Dec. 31, 2022 $ / shares shares	Sep. 30, 2022 $ / shares	Jun. 30, 2022 $ / shares	Mar. 31, 2022 $ / shares	Dec. 31, 2023 USD ($) $ / shares shares	Dec. 31, 2022 USD ($) $ / shares shares	Dec. 31, 2021 USD ($)	Oct. 31, 2023 USD ($)	Aug. 31, 2022 USD ($)	Jun. 29, 2022 $ / shares	Jun. 28, 2022 $ / shares	Feb. 28, 2022 USD ($)
Dividends declared (in usd per share) | $ / shares				$ 2.500	$ 1.360	$ 3.220	$ 4.800	$ 3.670	$ 1.250	$ 18.525	$ 3.585	$ 11.880	$ 27.030
Dividends paid | $												$ 500,304	$ 654,728	$ 111,905
Dividends payable, related to dividend equivalent rights | $				$ 37,600								37,600
Dividends payable, related to dividend equivalent rights, current | $				23,800								23,800
Dividends payable, related to dividend equivalent rights, noncurrent | $				13,800								$ 13,800
Share-repurchase program, authorized amount | $															$ 750,000	$ 300,000			$ 150,000
Repurchase of common stock (in shares) | shares												1,533,791	1,378,070
Repurchase of common stock (in usd per share) | $ / shares												$ 157.08	$ 110.24
Repurchase of common stock, excluding accrued excise tax | $												$ 240,900
Repurchase of common stock | $												241,339	$ 151,950	$ 100,000
Share repurchases, total cost including accrued excise tax | $												400
Stock repurchase program, remaining authorized repurchase amount | $				$ 683,000								$ 683,000
Exercise price of warrants or rights (in usd per share) | $ / shares										75.57							$ 94.57
Warrants outstanding (in shares) | shares				3,232,654								3,232,654
Warrants exercised (in shares) | shares												1,746,859
Common stock, shares authorized (in shares) | shares			120,000,000	120,000,000		60,000,000		120,000,000				120,000,000	120,000,000
Common stock, par value (in usd per share) | $ / shares				$ 0.01				$ 0.01				$ 0.01	$ 0.01					$ 0.01
Legacy Whiting - Series A
Exercise price of warrants or rights (in usd per share) | $ / shares			$ 116.37	$ 116.37								$ 116.37
Warrants outstanding (in shares) | shares				1,318,369								1,318,369
Warrants to purchase of number of shares (in shares) | shares			2,790,837
Legacy Whiting - Series B
Exercise price of warrants or rights (in usd per share) | $ / shares			$ 133.70	$ 133.70								$ 133.70
Warrants outstanding (in shares) | shares				1,338,568								1,338,568
Warrants to purchase of number of shares (in shares) | shares			1,396,634
Whiting Merger
Conversion ratio			0.5774
Share consideration (in usd per share) | $ / shares			$ 6.25
Shares issued (in shares) | shares			22,671,871
Whiting Merger | Legacy Whiting - Series A
Exercise price of warrants or rights (in usd per share) | $ / shares			$ 11.25
Warrants outstanding (in shares) | shares			4,833,455
Whiting Merger | Legacy Whiting - Series B
Exercise price of warrants or rights (in usd per share) | $ / shares			$ 10.50
Warrants outstanding (in shares) | shares			2,418,832
Dividend Equivalent Rights On Unvested Equity-Based Compensation Awards
Dividends declared associated with dividend equivalent rights on equity-based awards | $												$ 14,400	$ 41,600
Special
Dividends declared (in usd per share) | $ / shares		$ 15		$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 15	$ 0	$ 0	$ 15
Special Cash Dividend
Dividends paid | $		$ 307,400
Base-Plus-Variable Cash Dividend | Subsequent Event
Dividends declared (in usd per share) | $ / shares	$ 3.25

Stockholders' Equity - Schedu_2

Stockholders' Equity - Schedule of Warrants (Details) - $ / shares	Dec. 31, 2023	Jul. 01, 2022	Jun. 30, 2022	Jun. 29, 2022
Class of Warrant or Right [Line Items]
Warrants outstanding (in shares)	3,232,654
Exercise price of warrants or rights (in usd per share)			$ 75.57	$ 94.57
Legacy Oasis
Class of Warrant or Right [Line Items]
Warrants outstanding (in shares)	575,717
Exercise price of warrants or rights (in usd per share)	$ 75.57
Legacy Whiting - Series A
Class of Warrant or Right [Line Items]
Warrants outstanding (in shares)	1,318,369
Exercise price of warrants or rights (in usd per share)	$ 116.37	$ 116.37
Legacy Whiting - Series B
Class of Warrant or Right [Line Items]
Warrants outstanding (in shares)	1,338,568
Exercise price of warrants or rights (in usd per share)	$ 133.70	$ 133.70

Earnings Per Share - Schedule o

Earnings Per Share - Schedule of Weighted-Average Number of Shares Outstanding (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings Per Share [Abstract]
Net income from continuing operations	$ 1,023,779	$ 1,430,463	$ 188,960
Distributed and undistributed earnings from continuing operations allocated to participating securities	(3,370)	(182)	0
Net income from continuing operations attributable to common stockholders (basic)	1,020,409	1,430,281	188,960
Reallocation of distributed and undistributed earnings from continuing operations allocated to participating securities	76	6	0
Net income from continuing operations attributable to common stockholders (diluted)	$ 1,020,485	$ 1,430,287	$ 188,960
Weighted average common shares outstanding:
Basic (in shares)	41,490	30,497	19,792
Dilutive effect of share-based awards (in shares)	944	1,134	856
Dilutive effect of warrants (in shares)	964	620	0
Weighted average common shares outstanding, diluted (in shares)	43,398	32,251	20,648
Basic earnings per share from continuing operations (in usd per share)	$ 24.59	$ 46.90	$ 9.55
Diluted earnings per share from continuing operations (in usd per share)	$ 23.51	$ 44.35	$ 9.15
Antidilutive weighted average common shares (in shares)	3,709	2,901	2,144

Earnings Per Share - Narrative

Earnings Per Share - Narrative (Details) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings Per Share [Abstract]
Basic from discontinued operations (in usd per share)	$ 0	$ 13.96	$ 6.60
Diluted from discontinued operations (in usd per share)	$ 0	$ 13.20	$ 6.33

Leases - Components of lease ex

Leases - Components of lease expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Lease, Cost [Abstract]
Operating lease costs	$ 9,853	$ 11,292	$ 2,966
Variable lease cost	13,391	8,562	1,737
Short-term lease costs	56,100	25,716	8,244
Sublease income	(199)	0	0
Amortization of ROU assets	1,367	1,342	1,578
Interest on lease liabilities	126	65	86
Total lease costs	$ 80,638	$ 46,977	$ 14,611

Leases - Maturities of the Comp

Leases - Maturities of the Company's Lease Liabilities (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Operating Leases
2024	$ 14,880
2025	7,997
2026	5,100
2027	2,116
2028	2,010
Thereafter	3,425
Total future lease payments	35,528
Less: Imputed interest	3,548
Present value of future lease payments	31,980
Finance Leases
2024	1,025
2025	913
2026	684
2027	352
2028	17
Thereafter	0
Total future lease payments	2,991
Less: Imputed interest	249
Present value of future lease payments	$ 2,742

Leases - Supplemental Balance S

Leases - Supplemental Balance Sheet Information (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Lessee, Lease, Description [Line Items]
Operating right-of-use assets	$ 21,343	$ 23,875
Finance lease assets	2,748	1,803
Total lease assets	24,091	25,678
Current operating lease liabilities	13,258	9,941
Finance lease liabilities	916	1,012
Operating lease liabilities	18,667	13,266
Finance lease liabilities	1,881	789
Total lease liabilities	$ 34,722	$ 25,008
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other assets	Other assets
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other current liabilities	Other current liabilities
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other liabilities	Other liabilities
Operating lease acquired, operating lease asset		$ 14,500
Operating lease acquired, operating liability, current		2,500
Operating lease acquired, operating lease liabilities, noncurrent		11,900
Finance lease, right-of-use asset, accumulated amortization	$ (1,200)	1,600
Whiting Merger
Lessee, Lease, Description [Line Items]
Operating right-of-use assets		1,400
Finance lease liabilities		800
Finance lease liabilities		$ 600

Leases - Narrative (Details)

Leases - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)
Lessee, Lease, Description [Line Items]
Asset impairment charge	$ 17.5
Right Of Use Asset
Lessee, Lease, Description [Line Items]
Asset impairment charge	12.1
Leasehold Improvements
Lessee, Lease, Description [Line Items]
Asset impairment charge	$ 5.5

Leases - Schedule of Supplement

Leases - Schedule of Supplemental Cash Flow Information and Non-cash Transactions Related to Company's Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$ 15,627	$ 15,843	$ 3,420
Operating cash flows from finance leases	160	57	62
Financing cash flows from finance leases	1,702	1,299	1,161
ROU assets obtained in exchange for lease obligations
Operating leases	22,201	20,164	14,140
Finance leases	$ 2,307	2,659	127
Whiting Merger
ROU assets obtained in exchange for lease obligations
Business combination, operating leases - ROU assets obtained in exchange for lease obligations		15,800
Business combination, recognized identifiable assets acquired and liabilities assumed right-of-use asset obtained in exchange for finance lease liability		$ 2,100
2021 Williston Acquisition
ROU assets obtained in exchange for lease obligations
Business combination, operating leases - ROU assets obtained in exchange for lease obligations			$ 12,300

Leases - Weighted-Average Remai

Leases - Weighted-Average Remaining Lease Term and Discount Rate for the Company’s Leases (Details)	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Operating leases - Weighted average lease term	3 years 7 months 6 days	4 years 7 months 6 days
Operating leases - Weighted average discount rate (percent)	6.30%	4.90%
Finance leases - Weighted average lease term	3 years 2 months 12 days	2 years 3 months 18 days
Finance leases - Weighted average discount rate (percent)	5.70%	5.40%

Significant Concentrations (Det

Significant Concentrations (Details) - Sales - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Phillips 66 Company
Concentration Risk [Line Items]
Concentration risk (percent)	20%	17%	13%
Gunvor USA LLC
Concentration Risk [Line Items]
Concentration risk (percent)	14%
Shell Trading (US) Company
Concentration Risk [Line Items]
Concentration risk (percent)		11,000%

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details) ft³ in Millions, bbl in Millions, $ in Millions		12 Months Ended
	Nov. 01, 2022 USD ($)	Dec. 31, 2023 USD ($) bbl ft³	Dec. 31, 2022 USD ($)	Jul. 01, 2022 shares
Commitments And Contingencies [Line Items]
Warrants reserved (in shares) | shares				1,224,840
Whiting Merger
Commitments And Contingencies [Line Items]
Amount paid | $	$ 55
Surety Bond
Commitments And Contingencies [Line Items]
Off-balance sheet commitments | $		$ 27.1
Line of Credit | Credit Facility
Commitments And Contingencies [Line Items]
Outstanding letters of credit | $		$ 8.9	$ 6.4
Volume Commitment Agreement
Commitments And Contingencies [Line Items]
Term of commitment agreements		5 years
Volume Commitment Agreement | Crude Oil (MBbl)
Commitments And Contingencies [Line Items]
Minimum quantity of delivery | bbl		20.6
Volume Commitment Agreement | NGLs
Commitments And Contingencies [Line Items]
Minimum quantity of delivery | bbl		12
Volume Commitment Agreement | Natural Gas (MMcf)
Commitments And Contingencies [Line Items]
Minimum quantity of delivery | ft³		438.7
Volume Commitment Agreement, Water
Commitments And Contingencies [Line Items]
Minimum quantity of delivery | bbl		1.6

Commitments and Contingencies_2

Commitments and Contingencies - Schedule of Minimum Future Volume Commitments (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2024	$ 100,434
2025	100,966
2026	83,045
2027	62,079
2028	31,109
Thereafter	13,939
Future minimum volume commitment	$ 391,572

Subsequent Events (Details)

Subsequent Events (Details) - Enerplus Corporation - Subsequent Event	Feb. 21, 2024 $ / shares
Subsequent Event [Line Items]
Conversion ratio	0.10125
Share consideration (in usd per share)	$ 1.84

Supplemental Oil and Gas Disc_3

Supplemental Oil and Gas Disclosures - Unaudited - Capitalized Costs Related to Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved oil and gas properties	$ 6,220,766	$ 5,089,185
Less: Accumulated depletion and impairment	(1,035,393)	(461,175)
Proved oil and gas properties, net	5,185,373	4,628,010
Unproved oil and gas properties	99,477	30,936
Total oil and gas properties, net	$ 5,284,850
Previously Reported
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved oil and gas properties, net		4,628,010
Total oil and gas properties, net		$ 4,658,946

Supplemental Oil and Gas Disc_4

Supplemental Oil and Gas Disclosures - Unaudited - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Acquisition costs:
Proved oil and gas properties	$ 178,629
Unproved oil and gas properties	185,392
Exploration costs	6,366
Development costs	922,506
Asset retirement costs	18,461
Total costs incurred	$ 1,311,354
Previously Reported
Acquisition costs:
Proved oil and gas properties		$ 3,164,665	$ 605,868
Unproved oil and gas properties		43,084	85
Exploration costs		859	1
Development costs		507,961	170,178
Asset retirement costs		21,165	15,750
Total costs incurred		$ 3,737,734	$ 791,882

Supplemental Oil and Gas Disc_5

Supplemental Oil and Gas Disclosures - Unaudited - Results of Operations for Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues	$ 3,896,641	$ 3,646,794	$ 1,579,926
Oil and Gas
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues	3,132,411	2,976,296	1,200,256
Production costs	1,099,159
Depreciation, depletion and amortization	582,127
Exploration and impairment	17,830
Income tax expense	335,534
Results of operations for oil and gas producing activities	$ 1,097,761
Oil and Gas | Previously Reported
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues		2,976,296	1,200,256
Production costs		814,588	403,382
Depreciation, depletion and amortization		354,050	109,881
Exploration and impairment		2,204	2,763
Income tax expense		426,087	162,163
Results of operations for oil and gas producing activities		$ 1,379,367	$ 522,067

Supplemental Oil and Gas Rese_3

Supplemental Oil and Gas Reserve Information - Unaudited - Net Proved, Proved Developed and Proved Undeveloped Reserves (Details) ft³ in Thousands, bbl in Thousands, Boe in Thousands	12 Months Ended
	Dec. 31, 2023 Boe bbl ft³	Dec. 31, 2022 Boe bbl ft³	Dec. 31, 2021 Boe bbl ft³
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning balance | Boe	655,560	250,860	182,460
Revisions of previous estimates | Boe	(48,895)	47,110	53,871
Extensions, discoveries and other additions | Boe	78,632	51,544	10,157
Sales of reserves in place | Boe	(4,564)	0	(31,461)
Purchases of reserves in place | Boe	18,771	349,768	57,015
Production | Boe	(63,300)	(43,722)	(21,182)
Net proved reserves, closing balance | Boe	636,204	655,560	250,860
Proved developed reserves | Boe	453,762	502,698	174,347
Proved undeveloped reserves | Boe	182,442	152,862	76,513
Permian Basin
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Sales of reserves in place | Boe	(4,600)	0
Crude Oil (MBbl)
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning balance	381,288	174,317	119,765
Revisions of previous estimates	(38,073)	(8,032)	42,411
Extensions, discoveries and other additions	53,207	38,144	7,734
Sales of reserves in place	(3,999)	0	(24,760)
Purchases of reserves in place	12,375	202,316	42,656
Production	(36,427)	(25,457)	(13,489)
Net proved reserves, closing balance	368,371	381,288	174,317
Proved developed reserves	241,362	272,529	114,041
Proved undeveloped reserve	127,008	108,759	60,276
NGLs
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning balance	138,451	0	0
Revisions of previous estimates	(5,270)	64,557	0
Extensions, discoveries and other additions	15,046	7,452	0
Sales of reserves in place	(53)	0	0
Purchases of reserves in place	3,052	73,468	0
Production	(13,047)	(7,026)	0
Net proved reserves, closing balance	138,179	138,451	0
Proved developed reserves	105,702	115,227	0
Proved undeveloped reserve	32,476	23,224	0
Natural Gas (MMcf)
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Proved reserves, beginning balance | ft³	814,926	459,262	376,170
Revisions of previous estimates | ft³	(33,308)	(56,500)	68,768
Extensions, discoveries and other additions | ft³	62,273	35,689	14,539
Sales of reserves in place | ft³	(3,067)	0	(40,211)
Purchases of reserves in place | ft³	20,060	443,903	86,153
Production | ft³	(82,953)	(67,428)	(46,157)
Net proved reserves, closing balance | ft³	777,931	814,926	459,262
Proved developed reserves | ft³	640,180	689,651	361,836
Proved undeveloped reserve | ft³	137,751	125,275	97,426

Supplemental Oil and Gas Rese_4

Supplemental Oil and Gas Reserve Information - Unaudited - Narrative (Details) Boe in Thousands, MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 Boe	Dec. 31, 2023 MMBTU	Dec. 31, 2023 USD ($)	Dec. 31, 2023 $ / bbl	Dec. 31, 2023 $ / MMBTU	Dec. 31, 2022 Boe $ / bbl $ / MMBTU	Dec. 31, 2021 Boe $ / MMBTU $ / bbl
Reserve Quantities [Line Items]
Proved developed reserve, increase (decrease)							68,400
Proved developed and undeveloped reserve, production (energy)	63,300					43,722	21,182
Revisions of previous estimates	(48,895)					47,110	53,871
Extensions, discoveries and other additions	78,632					51,544	10,157
Purchases of reserves in place	18,771					349,768	57,015
Proved developed and undeveloped reserves, sale of mineral in place (energy)	4,564					0	31,461
Additional proved undeveloped reserves							7,600
Estimated extensions and discoveries of reserves associated with new wells							2,600
Discount rate	10%	10%	10%	10%	10%
Unweighted arithmetic average first-day-of-the-month prices for oil (in dollars per Bbl) | $ / bbl				78.22		93.67	66.55
Unweighted arithmetic average first-day-of-the-month prices for natural gas (in dollars per MMBtu) | $ / MMBTU					2.64	6.36	3.64
Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Revisions of previous estimates	8,198	8.2
Extensions, discoveries and other additions	74,514
Purchases of reserves in place	7,167
Proved undeveloped reserve, increase	29,600
Capital expenditures incurred but not yet paid | $			$ 545
Amount converted to proved developed reserves	43,900
PUD conversions, percent of reserve	29%	29%	29%	29%	29%
Revision of Previous Estimate Due to Realized Prices
Reserve Quantities [Line Items]
Revisions of previous estimates	41,200					26,100	37,200
Revision of Previous Estimate Due to Realized Prices | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Positive (negative) revisions of previous estimates - proved developed reserves	1,500
Revision of Previous Estimate, Due to Increase in Operating and Capital Expenses
Reserve Quantities [Line Items]
Revisions of previous estimates						(19,600)
Revision of Previous Estimate, Due to Increase in Operating and Capital Expenses | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Positive (negative) revisions of previous estimates - proved developed reserves	700
Revision of Previous Estimate, Due to Updated Expectations
Reserve Quantities [Line Items]
Revisions of previous estimates	9,900
Revision of Previous Estimate, Due to Updated Expectations | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Positive (negative) revisions of previous estimates - proved developed reserves	9,900
Revision Due to Performance
Reserve Quantities [Line Items]
Revisions of previous estimates	14,400					2,600	22,900
Revision Due to Performance | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Positive (negative) revisions of previous estimates - proved developed reserves	3,900
Revision From Change To Reporting Reserves On A Three-Stream Basis
Reserve Quantities [Line Items]
Revisions of previous estimates						30,300
Revision of Previous Estimate Due to Lower Operating Expenses
Reserve Quantities [Line Items]
Revisions of previous estimates						5,200	(6,200)
Revision of Previous Estimate Due to (Mis)Alignment With Development Plan
Reserve Quantities [Line Items]
Positive (negative) revisions of previous estimates - proved undeveloped reserves							38,600
Williston Basin
Reserve Quantities [Line Items]
Proved developed reserve, increase (decrease)	(19,400)					404,700
Purchases of reserves in place	18,800					349,800	57,000
Proved developed and undeveloped reserves, sale of mineral in place (energy)							31,500
Williston Basin | Proved Undeveloped Reserves
Reserve Quantities [Line Items]
Proved developed reserves, percent	12%	12%	12%	12%	12%
Williston Basin | Revision Due to Performance
Reserve Quantities [Line Items]
Revisions of previous estimates	7,400					6,700
Permian Basin
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, sale of mineral in place (energy)	4,600					0
Bakken or Three Forks Formations Area | Revision Due To Removal Of Midstream Operations
Reserve Quantities [Line Items]
Revisions of previous estimates							(5,200)

Supplemental Oil and Gas Rese_5

Supplemental Oil and Gas Reserve Information - Unaudited - Changes in Proved Undeveloped Reserves (Details) Boe in Thousands, MMBTU in Millions	12 Months Ended
	Dec. 31, 2023 Boe	Dec. 31, 2023 MMBTU	Dec. 31, 2022 Boe	Dec. 31, 2021 Boe
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved undeveloped reserves, beginning of period	152,862		76,513
Purchases of reserves in place	18,771		349,768	57,015
Extensions, discoveries and other additions	78,632		51,544	10,157
Revisions of previous estimates	(48,895)		47,110	53,871
Proved undeveloped reserves, end of period	182,442		152,862	76,513
Proved Undeveloped Reserves
Proved Developed and Undeveloped Reserves [Roll Forward]
Proved undeveloped reserves, beginning of period	152,862
Purchases of reserves in place	7,167
Extensions, discoveries and other additions	74,514
Revisions of previous estimates	8,198	8.2
Conversion to proved developed reserves	(43,903)
Proved undeveloped reserves, end of period	182,442		152,862

Supplemental Oil and Gas Rese_6

Supplemental Oil and Gas Reserve Information - Unaudited - Standardized Measure of Discounted Future Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 31,882,940	$ 44,544,247	$ 13,366,064
Future production costs	(13,815,882)	(15,879,712)	(6,548,794)
Future development costs	(3,055,823)	(2,553,605)	(1,322,207)
Future income tax expense	(2,573,017)	(5,283,201)	(717,721)
Future net cash flows	12,438,218	20,827,729	4,777,342
10% annual discount for estimated timing of cash flows	(5,447,578)	(9,333,254)	(2,080,404)
Standardized measure of discounted future net cash flows	$ 6,990,640	$ 11,494,475	$ 2,696,938	$ 948,877

Supplemental Oil and Gas Rese_7

Supplemental Oil and Gas Reserve Information - Unaudited - Changes in Standardized Measure of Discounted Future Net Cash Flows Applicable to Proved Oil and Natural Gas Reserves (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Standardized Measure of Discounted Future Net Cash Flows
January 1	$ 11,494,475	$ 2,696,938	$ 948,877
Net changes in prices and production costs	(6,138,846)	3,148,745	1,617,331
Net changes in future development costs	(92,072)	35,427	(36,645)
Sales of crude oil and natural gas, net	(2,033,251)	(2,161,708)	(796,874)
Purchases of reserves in place	373,913	7,441,750	780,442
Sales of reserves in place	(75,097)	0	(204,153)
Revisions of previous quantity estimates	(1,142,960)	1,434,357	639,320
Previously estimated development costs incurred	574,607	137,534	102,519
Accretion of discount	1,445,215	683,631	94,090
Net change in income taxes	1,419,851	(2,539,182)	(252,347)
Changes in timing and other	300,556	(341,941)	(293,747)
December 31	6,990,640	11,494,475	2,696,938
Extensions
Standardized Measure of Discounted Future Net Cash Flows
Extensions	$ 864,249	$ 958,924	$ 98,125