Vital Energy (VTLE) 10-K 11 Mar 24 2023 FY Annual report Financial data

Cover

Cover - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Mar. 04, 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	001-35380
Entity Registrant Name	Vital Energy, Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	45-3007926
Entity Address, Address Line One	521 E. Second Street
Entity Address, Address Line Two	Suite 1000
Entity Address, City or Town	Tulsa
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	74120
City Area Code	918
Local Phone Number	513-4570
Title of 12(b) Security	Common stock, $0.01 par value per share
Trading Symbol	VTLE
Security Exchange Name	NYSE
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	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
Entity Public Float			$ 825.5
Entity Common Stock, Shares Outstanding		36,678,051
Documents Incorporated by Reference	Portions of the registrant's definitive proxy statement for its 2024 Annual Meeting of Stockholders are incorporated by reference into Part III of this report for the year ended December 31, 2023.
Entity Central Index Key	0001528129
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Audit Information [Abstract]
Auditor Name	Ernst & Young LLP	GRANT THORNTON LLP
Auditor Location	Tulsa, Oklahoma	Tulsa, Oklahoma
Auditor Firm ID	42	248

Consolidated balance sheets

Consolidated balance sheets - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Current assets:
Cash and cash equivalents	$ 14,061	$ 44,435
Accounts receivable, net	238,773	163,369
Derivatives	99,336	24,670
Other current assets	18,749	13,317
Total current assets	370,919	245,791
Oil and natural gas properties, full cost method:
Evaluated properties	11,799,155	9,554,706
Unevaluated properties not being depleted	195,457	46,430
Less: accumulated depletion and impairment	(7,764,697)	(7,318,399)
Oil and natural gas properties, net	4,229,915	2,282,737
Property, Plant and Equipment, Other, Net	130,293	127,803
Property and equipment, net	4,360,208	2,410,540
Derivatives	51,071	24,363
Operating lease right-of-use assets	144,900	23,047
Deferred income taxes	188,836	0
Other noncurrent assets, net	33,647	22,373
Total assets	5,149,581	2,726,114
Current liabilities:
Accounts payable and accrued liabilities	159,892	102,516
Accrued capital expenditures	91,937	48,378
Undistributed revenue and royalties	194,307	160,023
Derivatives	0	5,960
Operating lease liabilities	70,651	15,449
Other current liabilities	78,802	82,950
Total current liabilities	595,589	415,276
Long-term debt, net	1,609,424	1,113,023
Asset retirement obligations	81,680	70,366
Operating lease liabilities	71,343	9,435
Other noncurrent liabilities	6,288	7,268
Total liabilities	2,364,324	1,615,368
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and 595,104 and zero issued as of December 31, 2023 and 2022, respectively	6	0
Common stock, $0.01 par value, 80,000,000 and 40,000,000 shares authorized, and 35,413,551 and 16,762,127 issued and outstanding as of December 31, 2023 and 2022, respectively	354	168
Additional paid-in capital	3,733,775	2,754,085
Accumulated deficit	(948,878)	(1,643,507)
Total stockholders' equity	2,785,257	1,110,746
Total liabilities and stockholders' equity	$ 5,149,581	$ 2,726,114

Consolidated balance sheets (Pa

Consolidated balance sheets (Parenthetical) - $ / shares	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Preferred stock, par value (in USD per share)	$ 0.01	$ 0.01
Preferred stock authorized (in shares)	50,000,000	50,000,000
Preferred stock issued (shares)	595,104	0
Common stock, par value (in USD per share)	$ 0.01	$ 0.01
Common stock authorized (in shares)	80,000,000	40,000,000
Common stock issued (shares)	35,413,551	16,762,127
Common stock outstanding (shares)	35,413,551	16,762,127

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	$ 1,547,604	$ 1,920,796	$ 1,394,075
Costs and expenses:
Lease operating expenses	261,129	173,983	101,994
Production and ad valorem taxes	93,224	110,997	68,742
General and administrative	104,819	68,082	62,801
Organizational restructuring expenses	1,654	10,420	9,800
Depletion, depreciation and amortization	463,244	311,640	215,355
Impairment expense	0	40	1,613
Other operating expenses, net	6,223	8,583	6,381
Total costs and expenses	988,655	859,555	765,663
Gain (loss) on disposal of assets, net	672	(1,079)	84,551
Operating income	$ 559,621	$ 1,060,162	$ 712,963
Non-operating income (expense):
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Total non-operating expense, net	Total non-operating expense, net	Total non-operating expense, net
Gain (loss) on derivatives, net	$ 96,230	$ (298,723)	$ (452,175)
Interest expense	(149,819)	(125,121)	(113,385)
Loss on extinguishment of debt, net	(4,039)	(1,459)	0
Other income, net	9,748	2,155	1,250
Total non-operating expense, net	(47,880)	(423,148)	(564,310)
Income before income taxes	511,741	637,014	148,653
Income tax benefit (expense):
Current	(5,723)	(6,121)	(1,324)
Deferred	189,060	619	(2,321)
Total income tax benefit (expense):	183,337	(5,502)	(3,645)
Net income	695,078	631,512	145,008
Preferred stock dividends	(449)	0	0
Net income available to common stockholders, basic	$ 694,629	$ 631,512	$ 145,008
Net income per common share:
Basic (in USD per share)	$ 34.30	$ 37.88	$ 10.18
Diluted (in USD per share)	$ 33.44	$ 37.44	$ 10.03
Weighted-average common shares outstanding:
Basic (in shares)	20,254	16,672	14,240
Diluted (in shares)	20,783	16,867	14,464
Oil sales
Revenues:
Total revenues	$ 1,328,518	$ 1,351,207	$ 805,448
NGL sales
Revenues:
Total revenues	136,901	234,613	191,591
Natural gas sales
Revenues:
Total revenues	63,214	208,554	150,104
Purchased oil
Revenues:
Total revenues	14,313	119,408	240,303
Costs and expenses:
Costs of goods and services sold	15,065	122,118	251,061
Other operating revenues
Revenues:
Total revenues	4,658	7,014	6,629
Oil transportation and marketing expenses
Costs and expenses:
Costs of goods and services sold	41,284	53,692	47,916
Gas gathering, processing and transportation expenses
Costs and expenses:
Costs of goods and services sold	$ 2,013	$ 0	$ 0

Consolidated statements of stoc

Consolidated statements of stockholders' equity - USD ($) shares in Thousands, $ in Thousands	Total	Preferred stock	Common stock	Additional paid-in capital	Treasury stock (at cost)	Accumulated deficit
Balance at beginning of year (in shares) at Dec. 31, 2020		0	12,020
Balance at beginning of year at Dec. 31, 2020	$ (21,443)	$ 0	$ 120	$ 2,398,464	$ 0	$ (2,420,027)
Balance at beginning of year (in shares) at Dec. 31, 2020					0
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (in shares)			237
Restricted stock awards	0		$ 2	(2)
Restricted stock forfeitures (in shares)			(42)
Stock exchanged for tax withholding (in shares)			(53)		53
Stock exchanged for tax withholding	0			(2,596)	$ 2,596
Retirement of treasury stock (in shares)					(53)
Retirement of treasury stock	(2,596)				$ (2,596)
Exercise of stock options (in shares)			2
Exercise of stock options	173			173
Share-settled equity-based compensation	9,258			9,258
Issuance of common stock, net of costs (in shares)			1,438
Issuance of common stock, net of costs	72,492		$ 14	72,478
Equity issued for acquisition of oil and natural gas properties (in shares)			3,467
Equity issued for acquisition of oil and natural gas properties	310,888		$ 35	310,853
Performance share conversion (in shares)			6
Performance share conversion	0
Net income (loss)	145,008					145,008
Balance at end of year (in shares) at Dec. 31, 2021		0	17,075
Balance at end of year at Dec. 31, 2021	513,780	$ 0	$ 171	2,788,628	$ 0	(2,275,019)
Balance at end of year (in shares) at Dec. 31, 2021					0
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (in shares)			255
Restricted stock awards	0		$ 3	(3)
Restricted stock forfeitures (in shares)			(58)
Restricted stock forfeitures	0		$ (1)	1
Share repurchases (in shares)			(491)		491
Share repurchases	0		$ (5)	(37,285)	$ 37,290
Stock exchanged for tax withholding (in shares)			(94)		94
Stock exchanged for tax withholding	0		$ (1)	(7,441)	$ 7,442
Retirement of treasury stock (in shares)					(585)
Retirement of treasury stock	(44,732)				$ (44,732)
Share-settled equity-based compensation	10,186			10,186
Performance share conversion (in shares)			75
Performance share conversion	0		$ 1	(1)
Net income (loss)	631,512					631,512
Balance at end of year (in shares) at Dec. 31, 2022		0	16,762
Balance at end of year at Dec. 31, 2022	1,110,746	$ 0	$ 168	2,754,085	$ 0	(1,643,507)
Balance at end of year (in shares) at Dec. 31, 2022					0
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (in shares)			340
Restricted stock awards	0		$ 3	(3)
Restricted stock forfeitures (in shares)			(47)
Restricted stock forfeitures	0
Stock exchanged for tax withholding (in shares)			(59)		59
Stock exchanged for tax withholding	0		$ (1)	(3,076)	$ 3,077
Retirement of treasury stock (in shares)					(59)
Retirement of treasury stock	(3,077)				$ (3,077)
Share-settled equity-based compensation	13,969			13,969
Issuance of common stock, net of costs (in shares)			3,163
Issuance of common stock, net of costs	161,223		$ 32	161,191
Equity issued for acquisition of oil and natural gas properties (in shares)		6,726	9,124
Equity issued for acquisition of oil and natural gas properties	807,767	$ 67	$ 91	807,609
Preferred share conversion (in shares)		(6,131)	6,131
Preferred stock conversion		$ (61)	$ 61
Preferred stock dividend paid	(449)					(449)
Net income (loss)	695,078					695,078
Balance at end of year (in shares) at Dec. 31, 2023		595	35,414
Balance at end of year at Dec. 31, 2023	$ 2,785,257	$ 6	$ 354	$ 3,733,775	$ 0	$ (948,878)
Balance at end of year (in shares) at Dec. 31, 2023					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	$ 695,078	$ 631,512	$ 145,008
Adjustments to reconcile net income to net cash provided by operating activities:
Share-settled equity-based compensation, net	10,994	8,403	7,675
Depletion, depreciation and amortization	463,244	311,640	215,355
Impairment expense	0	40	1,613
(Gain) loss on disposal of assets, net	(672)	1,079	(84,551)
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	(96,230)	298,723	452,175
Settlements paid for matured derivatives, net	(17,648)	(486,173)	(320,868)
Premiums received for commodity derivatives	0	0	9,041
Loss on extinguishment of debt, net	4,039	1,459	0
Deferred income tax (benefit) expense	(189,060)	(619)	2,321
Other, net	14,655	34,453	23,388
Changes in operating assets and liabilities:
Accounts receivable, net	(77,742)	(9,226)	(87,831)
Other current assets	(2,754)	8,370	(8,767)
Other noncurrent assets, net	484	1,837	(8,782)
Accounts payable and accrued liabilities	52,763	31,534	31,387
Undistributed revenue and royalties	(31,907)	42,085	81,201
Other current liabilities	(5,656)	(18,503)	33,331
Other noncurrent liabilities	(6,632)	(26,994)	4,975
Net cash provided by operating activities	812,956	829,620	496,671
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(849,508)	(5,581)	(763,411)
Capital expenditures:
Oil and natural gas properties	(617,397)	(566,989)	(418,362)
Midstream and other fixed assets	(14,021)	(14,147)	(8,780)
Proceeds from dispositions of capital assets, net of selling costs	2,403	108,888	393,742
Settlements received for contingent consideration	2,393	1,877	0
Net cash used in investing activities	(1,476,130)	(475,952)	(796,811)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	765,000	455,000	570,000
Payments on Senior Secured Credit Facility	(700,000)	(490,000)	(720,000)
Issuance of senior unsecured notes	897,710	0	400,000
Early repayments of long-term debt	(457,792)	(282,902)	0
Proceeds from issuance of common stock, net of offering costs	161,223	0	72,492
Share repurchases	0	(37,290)	0
Stock exchanged for tax withholding	(3,077)	(7,442)	(2,596)
Payments for debt issuance costs	(27,011)	(1,938)	(14,686)
Other, net	(3,253)	(1,459)	2,971
Net cash provided by (used in) financing activities	632,800	(366,031)	308,181
Net (decrease) increase in cash and cash equivalents	(30,374)	(12,363)	8,041
Cash and cash equivalents, beginning of period	44,435	56,798	48,757
Cash and cash equivalents, end of period	$ 14,061	$ 44,435	$ 56,798

Organization

Organization	12 Months Ended
	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	Note 1 Organization Vital Energy, Inc. ("Vital" or the "Company"), together with its wholly-owned subsidiaries, is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties in the Permian Basin of West Texas. The Company has identified one operating segment: exploration and production. In these notes, the "Company" refers to Vital and its subsidiaries collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these consolidated financial statements and the related notes are rounded and, therefore, approximate.

Basis of presentation and signi

Basis of presentation and significant accounting policies	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Basis of presentation and significant accounting policies	Note 2 Basis of presentation and significant accounting policies Basis of presentation The accompanying consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. Use of estimates in the preparation of consolidated financial statements The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ. Significant estimates include, but are not limited to, (i) volumes of the Company's reserves of oil, natural gas liquids ("NGL") and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) impairments, (iv) fair values of assets acquired and liabilities assumed in a business combination and (v) contingent assets or liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that would be used by market participants. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets may increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods. Cash and cash equivalents The Company defines cash and cash equivalents to include cash on hand, cash in bank accounts and highly liquid investments with original maturities of three months or less. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts. See Note 14 for discussion regarding the Company's exposure to credit risk. Accounts receivable The Company sells its produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company maintains an allowance for expected credit losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers significant factors such as historical losses, current receivables aging, the debtors' current ability to pay its obligation to the Company and existing industry and economic data. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote, and payments subsequently received on such balances are credited to the allowance. See Note 14 for discussion regarding the Company's exposure to credit risk. Accounts receivable consisted of the following components as of the dates presented: (in thousands) December 31, 2023 December 31, 2022 Oil, NGL and natural gas sales (1) $ 173,917 $ 111,260 Joint operations, net 60,397 35,801 Other 4,459 16,308 Total accounts receivable, net $ 238,773 $ 163,369 _____________________________________________________________________________ (1) For purchasers that the Company has netting arrangements with, the amounts presented include the net positions. Derivatives Derivatives are recorded at fair value and are presented on a net basis in "Derivatives" on the consolidated balance sheets as assets and/or liabilities. The Company records the fair value of derivatives on a net basis by counterparty where the right of offset exists. The Company determines the fair value of its derivatives using fair value hierarchy level inputs to its valuation techniques. The Company's derivatives were not designated as hedges for accounting purposes, and the Company does not enter into such instruments for speculative trading purposes. Accordingly, the changes in fair value are recognized in " Gain (loss) on derivatives, net Other current assets and liabilities Other current assets consisted of the following components as of the dates presented: (in thousands) December 31, 2023 December 31, 2022 Prepaid expenses and other $ 5,026 $ 7,247 Inventory 13,723 6,070 Total other current assets $ 18,749 $ 13,317 Other current liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2023 December 31, 2022 Accrued interest payable $ 52,837 $ 43,984 Accrued compensation and benefits 19,547 20,000 Other liabilities 6,418 18,966 Total other current liabilities $ 78,802 $ 82,950 Oil and natural gas properties The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain employee-related costs, incurred for the purpose of acquiring, exploring for or developing oil and natural gas properties, are capitalized and, once evaluated, depleted on a composite unit-of-production method based on estimates of proved oil, NGL and natural gas reserves. The depletion base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. Capitalized costs include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including employee-related costs, associated with production and general corporate activities are expensed in the period incurred. The Company excludes unevaluated property acquisition costs and exploration costs from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs to its unevaluated properties and such costs become subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated properties are assessed on a quarterly basis for possible impairment. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling capital investments to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion. Sales of oil and natural gas properties, whether or not being depleted currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas. See Note 4 for discussion of the Company's sale of oil and natural gas properties and the resulting gain recognized during the year ended December 31, 2021. See Note 6 for additional discussion of the Company's oil and natural gas properties and other property and equipment. Leases The Company recognizes operating lease right-of-use assets and operating lease liabilities on the consolidated balance sheets for operating leases with an initial term greater than 12 months. The Company determines whether a contract is or contains a lease at inception of the contract, based on answers to a series of questions that address whether an identified asset exists and whether the Company has the right to obtain substantially all of the benefit of the asset and to control its use over the full term of the agreement. Unless implicitly defined, the Company determines the present value of future lease payments using an estimated incremental borrowing rate. The Company has recognized operating lease right-of-use assets and operating lease liabilities on the consolidated balance sheets for leases of commercial real estate with lease terms extending into 2033 and drilling, completion, production and other equipment leases with lease terms extending into 2026. The Company has various other drilling, completion and production equipment leases on a short-term basis which are reflected in short-term lease costs. The Company's lease costs include those that are recognized in net income (loss) during the period and capitalized as part of the cost of another asset in accordance with other GAAP. The lease costs related to drilling, completion and production activities are reflected at the Company's net ownership, which is consistent with the principals of proportional consolidation, and lease commitments are reflected on a gross basis. Certain of the Company's operating lease right-of-use asset classes include options to renew on a month-to-month basis. The Company considers contract-based, asset-based, market-based and entity-based factors to determine the term over which it is reasonably certain to extend the lease in determining its right-of-use assets and liabilities. See Note 5 for further discussion of the Company's leases. Inventory The Company has the following types of inventory: (i) materials and supplies inventory used in production activities of oil and natural gas properties and midstream service assets, (ii) frac pit water inventory used in developing oil and natural gas properties and (iii) line-fill in third-party pipelines, which is 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 until the expiration of the transportation contract. All inventory is carried at the lower of cost or net realizable value ("NRV"), with cost determined using the weighted-average cost method, and is included in "Other current assets" and "Other noncurrent assets, net" on the consolidated balance sheets. The NRV for materials and supplies inventory and frac pit water inventory is estimated utilizing a replacement cost approach (Level 2). The NRV for line-fill in third-party pipelines is estimated utilizing a quoted market price adjusted for regional price differentials (Level 2). See Note 12 for discussion of the Company's valuation techniques. Debt issuance costs Debt issuance costs, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the straight-line method. See Note 7 for additional discussion of the Company's debt issuance costs. Asset retirement obligations Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is expensed through depletion, or for midstream service assets through depreciation. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and accretion expense. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment or removal and remediation cost per well and related facilities or midstream service asset based on Company experience, if any, in accordance with applicable state laws, (ii) estimated remaining life per well or midstream service asset, (iii) future inflation factors and (iv) the Company's average credit-adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in technology, regulatory, political, environmental, safety and public relations matters. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, an adjustment will be made to the asset balance. The Company is obligated by contractual and regulatory requirements to remove certain midstream service assets and perform other remediation of the sites where such midstream service assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for midstream service assets in the periods in which settlement dates are reasonably determinable. The following table presents changes to the Company's asset retirement obligations liability for the periods presented: Years ended December 31, (in thousands) 2023 2022 Liability at beginning of year $ 74,081 $ 72,003 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 7,648 362 Accretion expense (1) 3,703 3,879 Liabilities settled due to plugging and abandonment or removed due to sale (1,108) (2,163) Liability at end of year 84,324 74,081 Less: current asset retirement obligations (2) 2,644 3,715 Non-current asset retirement obligations $ 81,680 $ 70,366 ______________________________________________________________________________ (1) Accretion expense is included in "Other operating expenses, net" on the consolidated statements of operations. (2) Current asset retirement obligations is included in "Other current liabilities" on the consolidated balance sheets. Fair value measurements The carrying amounts reported on the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values. See Inventory in Note 2 for the fair value assumptions used in estimating the NRV of inventory, which is used to determine the necessity for any inventory impairment. See Note 4 for the fair value assumptions used in estimating the fair values of assets acquired and liabilities assumed in the Company's acquisitions. See Note 12 for further discussion of fair value measurements. Treasury stock Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result of (i) stock exchanged to satisfy tax withholding that arises upon the lapse of restrictions on share-settled equity-based awards at the awardee's election, (ii) stock exchanged for the cost of exercise of stock options at the awardee's election, or (iii) the Company's open market repurchases of its common stock. Revenue recognition Oil, NGL and natural gas sales and sales of purchased oil are generally recognized at the point in time that control of the product is transferred to the customer. Oil sales and sales of purchased oil Under its oil sales contracts, the Company sells produced or purchased oil at the delivery point specified in the contract and collects an agreed-upon index price, net of pricing differentials. The delivery point may be at the wellhead, the inlet of the purchaser's pipeline or nominated pipeline or the Company's truck unloading facility. At the delivery point, the purchaser typically takes custody, title and risk of loss of the product and, therefore, control as defined under applicable GAAP, typically passes at the delivery point. The Company recognizes revenue at the net price received when control transfers to the purchaser. The Company engages in transactions in which it sells oil at the lease and subsequently repurchases the same volume of oil from that customer at a downstream delivery point under a separate agreement ("Repurchase Agreement") for use in the sale to the final customer. The commercial reasoning for such transactions may vary. Where a Repurchase Agreement exists, the Company must evaluate whether the customer obtains control of the oil at the lease and therefore whether it is appropriate to recognize revenue for the lease sale. Where the Company has an obligation or a right to repurchase the oil, the customer does not obtain control of the oil because it is limited in its ability to direct the use of, and obtain substantially all of the remaining benefits from the oil even though it may have physical possession of the oil. When the Company repurchases the oil for equal to or more than the original selling price, then the transaction represents a financing arrangement unless there is only a short passage of time between the sale and repurchase, in which case any excess amount paid represents an expense associated with the sale of oil to the final customer. The Company recognizes such repurchase expense and any transportation expenses incurred for the delivery of the oil to the final customer in the "Transportation and marketing expenses" line item in the accompanying consolidated statements of operations. In certain situations, the Company enters into purchase and sale transactions of oil inventory with the same counterparty in contemplation with one another, and these transactions are presented on the consolidated statements of operations on a net basis in accordance with GAAP. The following table presents the net effect of these transactions for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Sales of purchased oil inventory $ 494,860 $ 104,403 $ 327,839 Purchased oil inventory 495,697 104,039 326,625 Net effect on earnings (1) $ (837) $ 364 $ 1,214 ______________________________________________________________________________ (1) Amounts presented are recorded in "Sales of purchased oil" in the consolidated statements of operations. Under certain of its customer contracts, the Company is subject to contractual penalties if it fails to deliver contractual minimum volumes to its customers. Such amounts are recorded as a reduction to the transaction price as these amounts do not represent payments to the customer for distinct goods or services and instead relate specifically to the failure to perform under the specific customer contract. Such amounts are recorded as a reduction to the transaction price when payment is determined as probable, typically when such a deficiency occurs. NGL and natural gas sales Under its natural gas processing contracts, the Company delivers produced natural gas to a midstream processing entity at the wellhead or the inlet of the processing entity's system. The processing entity processes the natural gas, sells the resulting NGL and residue gas to third parties and pays the Company for the NGL and residue gas with deductions that may include gathering, compression, processing and transportation fees. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For contracts where the Company has concluded that it is the agent in the ultimate sale to the third party and the midstream processing entity is the principal and that the Company has transferred control of unprocessed natural gas to the midstream processing entity, the Company recognizes revenue based on the net amount of the proceeds received from the midstream processing entity who represents the Company's customer. For contracts where the Company has concluded that it is the principal with the ultimate third party being the customer, the Company recognizes revenue for those contracts on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense. Significant judgments The Company engages in various types of transactions in which unaffiliated midstream entities process the Company's liquids-rich natural gas and, in some scenarios, subsequently market resulting NGL and residue gas to third-party customers on the Company's behalf. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. For existing contracts, the Company has determined that it serves as the agent in the sale of products under certain natural gas processing and marketing agreements with unaffiliated midstream entities in accordance with the control model under applicable GAAP. As a result, the Company presents revenue on a net basis for amounts expected to be received from third-party customers through the marketing process, with expenses and deductions incurred subsequent to control of the product(s) transferring to the unaffiliated midstream entity being netted against revenue. Transaction price allocated to remaining performance obligations A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient under applicable GAAP that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company's product sales that have a contract term greater than one year, the Company has utilized the practical expedient under applicable GAAP that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company's product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied. Under these contracts each unit of service represents a separate performance obligation and therefore performance obligations in respect of future services are wholly unsatisfied. Contract balances Under the Company's customer contracts, invoicing occurs once the Company's performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's contracts do not give rise to contract assets or contract liability balances. Prior-period performance obligations For sales of oil, NGL, natural gas and purchased oil, the Company records revenue in the month production is delivered to the purchaser. However, settlement statements and payment may not be received for 30 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 records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. Such differences have historically not been significant. The Company uses knowledge of its properties, its properties' historical performance, spot market prices and other factors as the basis for these estimates. For the years ended December 31, 2023, 2022 and 2021, revenue recognized related to performance obligations satisfied in prior reporting periods was not material. Equity-based compensation awards Equity-based compensation expense is included in "General and administrative" on the consolidated statements of operations, and includes expense for (i) restricted stock awards, stock option awards and performance share awards, which are accounted for as equity awards and are generally based on the awards' grant date or modification date fair value less an expected forfeiture rate and (ii) performance unit awards and phantom unit awards, which are accounted for as liability awards and are re-measured at each quarterly reporting period until settlement. The Company capitalizes a portion of equity-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized equity-based compensation is included in "Evaluated properties" on the consolidated balance sheets. See Note 9 for further discussion of the Company's Equity Incentive Plan. Income taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carryforwards. Under this method, 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 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 or loss in the period that includes the enactment date. The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company has no unrecognized tax benefits related to uncertain tax positions in the consolidated financial statements at December 31, 2023 or 2022. See Note 13 for additional information regarding the Company's income taxes. Supplemental cash flow and non-cash information The following table presents supplemental cash flow and non-cash information for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Supplemental cash flow information: Cash paid for interest, net of $2,892, $3,872 and $5,866 of capitalized interest, respectively (1) $ 132,986 $ 131,867 $ 94,867 Supplemental non-cash operating information: Right-of-use assets obtained in exchange for operating lease liabilities (2) $ 176,027 $ 34,532 $ 7,742 Supplemental non-cash investing information: Fair value of contingent consideration asset on transaction closing date (3) $ — $ — $ 33,832 Change in accrued capital expenditures $ 43,559 $ (2,207) $ 22,310 Equity issued for acquisition of oil and natural gas properties (4) $ 807,767 $ — $ 310,888 Liabilities assumed in acquisitions of oil and natural gas properties (4) $ 86,478 $ — $ 11,653 Capitalized asset retirement cost $ 7,648 $ 362 $ 14,610 ______________________________________________________________________________ (1) See Note 7 for additional discussion of the Company's interest expense. (2) See Note 5 for additional discussion of the Company's leases. (3) See Note 4 for additional discussion of the Company's divestiture of oil and natural gas properties that includes contingent consideration. See Note 12 for discussion of the quarterly remeasurement of the contingent consideration. (4) See Notes 4 and 8 for additional discussion of the Company's acquisitions of oil and natural gas properties and equity issued in connection with such acquisitions, respectively.

New accounting standards

New accounting standards	12 Months Ended
	Dec. 31, 2023
Accounting Standards Update and Change in Accounting Principle [Abstract]
New accounting standards	Note 3 New accounting standards The Company considered the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the Accounting Standards Codification. The Company did not adopt any new ASUs during the year ended December 31, 2023. In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which sets forth improvements to the current segment disclosure requirements in accordance with Topic 280 "Segment Reporting," including clarifying that entities with a single reportable segment are subject to both new and existing segment reporting requirements. ASU 2023-07 will be effective retrospectively for fiscal years beginning after December 15, 2023 and interim periods beginning after December 15, 2024. Early adoption is permitted. Adoption of this ASU will result in additional disclosure, but will not impact the Company’s consolidated financial position, results of operations or cash flows.

Acquisitions and divestitures

Acquisitions and divestitures	12 Months Ended
	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
Acquisitions and divestitures	Note 4 Acquisitions and divestitures 2023 business combination Henry Acquisition On September 13, 2023, the Company entered into a purchase and sale agreement (the “Henry PSA”) with Henry Resources, LLC, Henry Energy LP and Moriah Henry Partners LLC (collectively, “Henry”), pursuant to which the Company agreed to purchase (the “Henry Acquisition”) Henry’s oil and gas properties in the Midland and Delaware Basin, including approximately 15,900 net acres located in Midland, Reeves and Upton Counties, equity interests in certain subsidiaries and related assets and contracts. On November 5, 2023 ("Henry Closing Date"), the Company closed the Henry Acquisition for an aggregate purchase price of $434.1 million. The following table presents components of the consideration paid in the Henry Acquisition, which is inclusive of customary closing adjustments and subject to post-closing adjustments: (in thousands, except for share and share price data) As of November 5, 2023 Shares of Company common stock issued 2,145,725 Company common stock price on Henry Closing Date $ 52.25 Fair value of Company common stock issued $ 112,114 Shares of Company preferred stock issued 6,131,381 Company preferred stock price on Henry Closing Date $ 52.25 Fair value of Company preferred stock issued (before dividends) $ 320,365 Fair value of preferred stock dividends 446 Fair value of Company preferred stock issued $ 320,811 Cash consideration for working capital closing adjustments 1,154 Total consideration $ 434,079 The Henry Acquisition was accounted for as a business combination, with all associated transaction costs of $10.5 million included in "General and administrative expense" on the consolidated statements of operations. The Company's preliminary allocation of the purchase price is substantially complete as of December 31, 2023, however there may be further adjustments to the fair values of assets acquired and liabilities assumed, including but not limited to the Company's oil and natural gas properties. The following table presents the preliminary purchase price allocation of the Henry Acquisition to the assets acquired and liabilities assumed, based on their fair values on the Henry Closing Date: (in thousands) As of November 5, 2023 Fair value of assets acquired: Oil and natural gas properties: Evaluated properties $ 381,739 Unevaluated properties (1) 69,541 Operating lease right-of-use assets 3,366 Fair value of liabilities assumed: Asset retirement obligations (1,155) Operating lease liabilities (3,366) Revenue suspense liabilities (16,046) Total purchase price $ 434,079 ______________________________________________________________________________ (1) As of December 31, 2023, $27.3 million remained in unevaluated properties. The Company conducted assessments of recognized amounts for identifiable assets acquired and liabilities assumed in the Henry Acquisition at the estimated acquisition date fair values. The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair values of evaluated and unevaluated oil and natural gas properties. The fair values of these properties were measured using an income approach utilizing the discounted cash flow model that converts future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) forecasted oil, NGL and natural gas reserve quantities; (ii) future commodity strip prices as of the closing dates adjusted for transportation and regional price differentials; (iii) forecasted ad valorem taxes, production taxes, income taxes, operating expenses and development costs; and (iv) a peer group weighted-average cost of capital rate subject to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of proved undeveloped and probable reserves are reduced by additional reserve adjustment factors. These assumptions represent Level 3 inputs under the fair value hierarchy, as described in Note 12. The Company's consolidated statement of operations for the year ended December 31, 2023 includes revenues of $28.8 million and net income of $13.8 million attributable to the Henry Acquisition, subsequent to the Henry Closing Date. Pro forma financial information (unaudited) The following unaudited summary financial information for the years ended December 31, 2023 and 2022 gives effect to the Henry Acquisition as if they had been completed on January 1, 2022. The unaudited pro forma financial information is provided for illustrative purposes only and does not purport to represent what the actual consolidated results of operations or the consolidated financial position of Vital would have been had the Henry Acquisition and related financing occurred on the date noted above, nor are they necessarily indicative of future consolidated results of operations or consolidated financial position. The below information reflects pro forma adjustments for the issuance of the Company's common stock and preferred stock as consideration for the Henry Acquisition, as well as pro forma adjustments based on available information and certain assumptions the Company believes are reasonable, including adjustments to depreciation, depletion and amortization based on the full cost method of accounting and estimated impacts of the pro forma adjustments to income tax and valuation allowance. Years ended December 31, (in thousands) 2023 2022 Total revenues $ 1,701,019 $ 2,206,570 Operating income $ 632,666 $ 1,225,218 Net income $ 716,775 $ 791,740 Net income available to common shareholders $ 710,560 $ 785,001 Net income per common share: Basic $ 31.72 $ 41.72 Diluted $ 25.51 $ 31.49 2023 asset acquisitions Grey Rock Acquisition On December 21, 2023 (the "Grey Rock Closing Date"), the Company purchased additional working interests in producing assets associated with the Henry Acquisition, with an effective date of December 21, 2023 (the "Grey Rock Acquisition") through Granite Ridge Holdings LLC, GREP IV-A Permian, LLC and GREP IV-B Permian, LLC (collectively, “Grey Rock”). The aggregate purchase price of $56.3 million consisted of (i) 627,026 shares of the Company's common stock, par value $0.01 per shares ("Common Stock") based upon the share price as of the Grey Rock Closing Date, ii) 595,104 shares of the Company's 2.0% Cumulative Mandatorily Convertible Series A Preferred Stock, par value $0.01 per shares ("Preferred Stock") based upon the share price as of the Grey Rock Closing Date and (iii) $1.0 million in transaction related expenses, inclusive of customary closing price adjustments and subject to post-closing adjustments. The Grey Rock Acquisition was accounted for as an asset acquisition, as substantially all the gross assets acquired are concentrated in a group of similar identifiable assets. Based on the relative fair values on Grey Rock Closing Date, the acquired assets and liabilities assumed were allocated as follows: i) $53.1 million to evaluated properties, ii) $3.3 million to unevaluated properties, all of which remained as of December 31, 2023 and iii) $0.1 million to asset retirement obligation liabilities. Tall City Acquisition On November 6, 2023 ("Tall City Closing Date"), the Company purchased certain oil and gas properties in the Delaware Basin, including approximately 21,450 net acres located in Reeves County and related assets and contracts, with an effective date September 13, 2023 (the "Tall City Acquisition") from Tall City Property Holdings III LLC and Tall City Operations III LLC (collectively, "Tall City"). The aggregate purchase price of $358.9 million consisted of (i) $280.3 million in cash, (ii) 1,402,258 shares of Common Stock based upon the share price as of the Tall City Closing Date and (iii) $7.8 million in transaction related expenses, inclusive of customary closing price adjustments and subject to post-closing adjustments. Upon entering into the purchase and sale agreement with Tall City (the "Tall City PSA"), the Company issued Common Stock as a deposit to be held in escrow until closing of the Tall City Acquisition, of which certain shares remain in escrow to satisfy potential indemnification claims under the Tall City PSA. See Note 8 for additional information. The Tall City Acquisition was accounted for as an asset acquisition, as substantially all the gross assets acquired are concentrated in a group of similar identifiable assets. Based on the relative fair values on Tall City Closing Date, the acquired assets and liabilities assumed were allocated as follows: i) $335.9 million to evaluated properties, ii) $58.7 million to unevaluated properties, of which $4.4 million remained as of December 31, 2023, iii) $2.7 million to operating lease right-of-use assets, iv) $2.7 million to operating lease liabilities, v) $1.2 million to property tax liabilities, vi) $32.7 million to revenue suspense liabilities and vii) $1.8 million to asset retirement obligation liabilities. Maple Acquisition On October 31, 2023 ("Maple Closing Date"), the Company purchased certain oil and gas properties in the Delaware Basin, including approximately 15,500 net acres located in Reeves County and related assets and contracts, with an effective date of September 13, 2023 (the "Maple Acquisition") from Maple Energy Holdings, LLC ("Maple"). The aggregate purchase price of $175.1 million consisted of i) 3,370,497 shares of Common Stock based upon the share price as of the Maple Closing Date, inclusive of customary closing price adjustments, subject to post-closing adjustments, and ii) $6.4 million in transaction related expenses. Upon entering into the purchase and sale agreement with Maple (the "Maple PSA"), the Company issued Common Stock as a deposit to be held in escrow until closing of the Maple Acquisition, of which certain shares remain in escrow post-closing to satisfy potential indemnification claims under the Maple PSA. See Note 8 for additional information. The Maple Acquisition was accounted for as an asset acquisition, as substantially all the gross assets acquired are concentrated in a group of similar identifiable assets. Based on the relative fair values on Maple Closing Date, the acquired assets and liabilities assumed were allocated as follows: i) $150.1 million to evaluated properties, ii) $31.7 million to unevaluated properties, all of which remained as of December 31, 2023, iii) $1.9 million to property tax liabilities, iv) $3.3 million to revenue suspense liabilities and v) $1.5 million to asset retirement obligation liabilities. Forge Acquisition On June 30, 2023 ("Forge Closing Date"), the Company purchased certain oil and natural gas properties located in the Delaware Basin, including approximately 24,000 net acres in Pecos, Reeves and Ward Counties, and related assets and contracts, with an effective date of March 1, 2023 (the "Forge Acquisition") from Forge Energy II Delaware, LLC ("Forge"). The aggregate purchase price of $397.5 million consisted of (i) $389.9 million in cash, inclusive of customary post-closing adjustments, and (ii) $7.6 million in transaction related expenses. The Forge Acquisition was accounted for as an asset acquisition, as substantially all the gross assets acquired are concentrated in a group of similar identifiable assets. Based on the relative fair values on the Forge Closing Date, the acquired assets and liabilities assumed were allocated as follows: i) $278.5 million to evaluated properties, ii) $125.5 million to unevaluated properties, of which $50.6 million remained as of December 31, 2023, iii) $8.9 million to equipment inventory, iv) $13.7 million to revenue suspense liabilities and v) $1.7 million to asset retirement obligation liabilities. Driftwood Acquisition On April 3, 2023 ("Driftwood Closing Date"), the Company purchased certain oil and natural gas properties in the Midland Basin, including approximately 11,200 net acres located in Upton and Reagan Counties and related assets and contracts, inclusive of derivatives (the "Driftwood Assets") with an effective date of January 1, 2023 (the "Driftwood Acquisition") from Driftwood Energy Operating, LLC ("Driftwood"). The aggregate purchase price of $201.7 million consisted of (i) $117.4 million of cash, inclusive of post-closing adjustments, (ii) 1,578,948 shares of Common Stock based upon the share price as of the Driftwood Closing Date and (iii) $4.2 million in transaction related expenses. The Driftwood Acquisition was accounted for as an asset acquisition, as substantially all the gross assets acquired are concentrated in a group of similar identifiable assets. Based on the relative fair values on the Driftwood Closing Date, the acquired assets and liabilities assumed were allocated as follows: i) $207.1 million to evaluated properties, ii) $0.5 million to revenue suspense liabilities, iii) $4.2 million to derivative liabilities and iv) $0.7 million to asset retirement obligation liabilities. During the second quarter of 2023, in connection with the Driftwood Acquisition, the Company acquired additional interests in the Driftwood Assets through additional sellers that exercised their "tag-along" sales rights, for total cash consideration of $8.6 million, excluding customary purchase price adjustments. These acquisitions were accounted for as asset acquisitions. 2022 divestiture On August 16, 2022, the Company entered into a purchase and sale agreement with Northern Oil and Gas, Inc. ("NOG"), pursuant to which the Company agreed to sell to NOG the Company’s working interests in certain specified non-operated oil and gas properties (the "NOG Working Interest Sale"). On October 3, 2022, the Company closed the NOG Working Interest Sale for an aggregate sales price of $106.1 million, inclusive of customary closing adjustments, subject to post-closing adjustments. 2021 asset acquisitions and divestiture Pioneer Acquisition On October 18, 2021 ("Pioneer Closing Date"), the Company purchased certain oil and natural gas properties in the Midland Basin, including approximately 20,000 net acres located in western Glasscock County and related assets and contracts (the "Pioneer Assets"), with an effective date of July 1, 2021 (the "Pioneer Acquisition") from Pioneer Natural Resources USA, Inc, DE Midland III, LLC , Parsley Minerals, LLC and Parsley Energy, L.P. The aggregate purchase price of $210.1 million consisted of (i) $135.3 million in cash, (ii) 959,691 shares of Common Stock based upon the share price as of the Pioneer Closing Date and (iii) $3.9 million in transaction related expenses, inclusive of post-closing adjustments. The Pioneer Acquisition was accounted for as an asset acquisition, as substantially all the gross assets acquired are concentrated in a group of similar identifiable assets. Based on the relative fair values on the Pioneer Closing Date, the acquired assets and liabilities assumed were allocated as follows: i) $143.0 million to evaluated properties, ii) $74.5 million to unevaluated properties and iii) $7.4 million to revenue suspense liabilities. During the year ended December 31, 2021, in connection with the Pioneer Acquisition, the Company acquired additional interests in the Pioneer Assets through additional sellers that exercised their "tag-along" sales rights, for total cash consideration of $2.9 million, excluding customary purchase price adjustments. These acquisitions were accounted for as asset acquisitions. Sabalo/Shad Acquisition On July 1, 2021 ("Sabalo/Shad Closing Date"), the Company purchased certain oil and natural gas properties in the Midland Basin, including approximately 21,000 net acres located in Howard and Borden counties and related assets and contracts with an effective date of April 1, 2021 (the "Sabalo/Shad Acquisition") from Sabalo Energy, LLC and its subsidiary, Sabalo Operating, LLC (collectively, "Sabalo") and from with Shad Permian, LLC ("Shad"). The Company entered into two separate purchase and sale agreements, one with Sabalo and the other with Shad (together, the "Sabalo/Shad PSAs"). Sabalo and Shad are unaffiliated, but owned interest in the same assets. The aggregate purchase price of $863.1 million consisted of (i) $606.1 million in cash (ii) 2,506,964 shares of Common Stock based upon the share price as of the Sabalo/Shad Closing Date, and (iii) $17.0 million in transaction related expenses, inclusive of customary post-closing adjustments. The Sabalo/Shad Acquisition was accounted for as a single transaction because the Sabalo/Shad PSAs were entered into at the same time and in contemplation of one another to form a single transaction designed to achieve an overall economic effect. The Company determined that the Sabalo/Shad Acquisition was an asset acquisition, as substantially all of the gross assets acquired are concentrated in a group of similar identifiable assets. Accordingly, the consideration paid was allocated to the individual assets acquired and liabilities assumed based on their relative fair values and all transaction costs associated were capitalized. Based on the relative fair values on the Sabalo/Shad Closing Date, the acquired assets and liabilities assumed were allocated as follows: i) $503.0 million to evaluated properties, ii) $363.0 million to unevaluated properties, iii) $1.4 million to inventory and iv) $4.3 million to revenue suspense liabilities. Working Interest Sale On May 7, 2021, the Company entered into a purchase and sale agreement (the "Sixth Street PSA") with Piper Investments Holdings, LLC, an affiliate of Sixth Street Partners, LLC ("Sixth Street"), to sell 37.5% of the Company's working interest in certain producing wellbores and the related properties primarily located within Glasscock and Reagan Counties, Texas, subject to certain excluded assets and title diligence procedures (the "Working Interest Sale"). On July 1, 2021 (the "Sixth Street Closing Date") the Company closed the Working Interest Sale for cash proceeds of $405.0 million. In addition to such proceeds, the Sixth Street PSA also provided the Company with the right to receive up to a maximum of $93.7 million in additional cash consideration if certain cash flow targets related to divested oil and natural gas property operations are met ("Sixth Street Contingent Consideration"). The Sixth Street Contingent Consideration is made up of quarterly payments through June 2027 totaling up to $38.7 million and a potential balloon payment of $55.0 million in June 2027. On the Sixth Street Closing Date, the fair value of the Sixth Street Contingent Consideration was determined to be $33.8 million. The Sixth Street Contingent Consideration is accounted for as a contingent consideration derivative, with all gains and losses as a result of changes in the fair value of the contingent consideration derivative recognized in earnings in the period in which the changes occur. See Notes 11 and 12 for further discussion of the Sixth Street Contingent Consideration. Subsequent to the Sixth Street Closing Date, the Company continues to own and operate its remaining working interest in the properties sold to Sixth Street; however, the results of operations and cash flows related to the 37.5% working interests sold were eliminated from the Company's financial statements. This divestiture did not represent a strategic shift and will not have a major effect on the Company's future operations or financial results. Pursuant to the rules governing full cost accounting, the Company recorded a gain on the Working Interest Sale of $94.3 million, net of transaction expenses of $11.6 million, on the Company's consolidated statements of operations, inclusive of post-closing adjustments, as this divestment represented more than 25% of the Company's June 30, 2021 proved reserves. For the purposes of calculating the gain, total capitalized costs were allocated between reserves sold and reserves retained as of the Sixth Street Closing Date. Exchange of unevaluated oil and natural gas properties From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.

Leases

Leases	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Leases	Note 5 Leases Lease costs The following table presents components of total lease costs, net for the periods presented: Years ended December 31, (in thousands) 2023 2022 Operating lease costs (1) $ 71,706 $ 24,174 Short-term lease costs (2) 56,685 110,442 Variable lease costs (3) 97,383 11,328 Sublease income (1,198) (990) Total lease costs, net $ 224,576 $ 144,954 _____________________________________________________________________________ (1) Amounts represent straight-line costs associated with the Company's operating lease right-of-use assets. (2) Amounts include costs associated with the Company's short-term leases that are not included in the calculation of lease liabilities and right-of-use assets and, therefore, are not recorded on the consolidated balance sheets as such. (3) Amounts are primarily comprised of the non-lease service component of drilling rig and completions commitments above the minimum required payments, and are not included in the calculation of lease liabilities and right-of-use assets. Both the minimum required payments and the non-lease service component of the drilling rig and completions commitments are capitalized as additions to oil and natural gas properties. Operating leases Supplemental cash flow information The following table presents cash paid for amounts included in the measurement of operating lease liabilities, which may not agree to operating lease costs due to timing of cash payments and incurred capital expenditures for the periods presented: Years ended December 31, (in thousands) 2023 2022 Operating cash flows from operating leases $ 4,595 $ 3,892 Investing cash flows from operating leases (1) $ 65,305 $ 20,398 _____________________________________________________________________________ (1) Amounts associated with drilling and completions operations are capitalized as additions to oil and natural gas properties. Lease terms and discount rates The following table presents the weighted-average remaining lease term and weighted-average discount rate for operating leases as of the dates presented: December 31, 2023 December 31, 2022 Weighted-average remaining lease term 2.54 years 1.91 years Weighted-average discount rate 8.26 % 5.84 % Maturities The following table reconciles the undiscounted cash flows for recognized operating lease liabilities for each of the first five years and the total remaining years to the operating lease liabilities recorded on the consolidated balance sheet as of the date presented: (in thousands) December 31, 2023 2024 $ 79,663 2025 61,157 2026 3,905 2027 2,788 2028 2,153 Thereafter 10,466 Total minimum lease payments 160,132 Less: imputed interest (18,138) Present value of future minimum lease payments $ 141,994 Other information See Note 2 for disclosure of supplemental non-cash adjustments information related to operating leases.

Property and equipment

Property and equipment	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Property and equipment	Note 6 Property and equipment Oil and natural gas properties The following table presents capitalized employee-related incurred capital expenditures in the acquisition, exploration and development of oil and natural gas properties for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Capitalized employee-related costs $ 22,179 $ 17,026 $ 18,255 See Unaudited Supplementary Information included elsewhere in this Annual Report for total incurred capital expenditures in the acquisition, exploration and development of oil and natural gas properties, which includes the aforementioned capitalized employee-related costs. The following table presents depletion expense, which is included in "Depletion, depreciation and amortization" on the consolidated statements of operations, and depletion expense per BOE sold of evaluated oil and natural gas properties for the periods presented: Years ended December 31, (in thousands except per BOE data) 2023 2022 2021 Depletion expense of evaluated oil and natural gas properties $ 446,611 $ 298,259 $ 201,691 Depletion expense per BOE sold $ 12.67 $ 9.92 $ 6.76 The full cost ceiling is based principally on the estimated future net cash flows from proved oil, NGL and natural gas reserves, which exclude the effect of the Company's commodity derivative transactions, discounted at 10%. SEC guidelines require companies to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point ("Realized Prices") without giving effect to the Company's commodity derivative transactions. The Realized Prices are utilized to calculate the estimated future net cash flows in the full cost ceiling calculation. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of proved reserves and other relevant data. In the event the unamortized cost of evaluated oil and natural gas properties being depleted exceeds the full cost ceiling, as defined by the SEC, the excess is expensed in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible. The unamortized cost of evaluated oil and natural gas properties being depleted did not exceed the full cost ceiling during any of the quarterly periods in 2023, 2022 and 2021. Accordingly, the Company had no full cost ceiling impairment expense, which would be included in "Impairment expense" on the consolidated statements of operations for the years ended December 31, 2023, 2022 and 2021. The following table presents the Benchmark Prices and the Realized Prices as of the dates presented: December 31, 2023 December 31, 2022 December 31, 2021 Benchmark Prices: Oil ($/Bbl) $ 78.22 $ 90.15 $ 63.04 NGL ($/Bbl) (1)(2) $ 78.22 $ 41.77 $ 34.51 Natural gas ($/MMBtu) $ 2.64 $ 5.20 $ 3.35 Realized Prices: Oil ($/Bbl) $ 79.52 $ 96.21 $ 66.37 NGL ($/Bbl) $ 16.46 $ 29.84 $ 22.90 Natural gas ($/Mcf) $ 1.17 $ 4.24 $ 2.61 _____________________________________________________________________________ (1) Based on the Company's average composite NGL barrel. (2) During 2023, the Company began utilizing WTI NYMEX in the calculation of its NGL Benchmark Prices. Midstream and other fixed assets Midstream assets consist of oil and natural gas pipeline gathering assets, related equipment, oil delivery stations, water storage and treatment facilities and their related asset retirement cost. Midstream and other fixed assets are recorded at cost, net of any impairment, and are subject to depreciation and amortization. Land is recorded at cost and is not subject to depreciation. Depreciation of assets is recorded using the straight-line method based on estimated useful lives of 3 to 20 years, as applicable. Leasehold improvements are capitalized and amortized over the shorter of the estimated useful lives of the assets or the terms of the related leases. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation are removed from the accounts and any gain or loss is recognized in "Gain (loss) on disposal of assets, net" in the consolidated statements of operations. Midstream and other fixed assets consisted of the following components as of the dates presented: (in thousands) December 31, 2023 December 31, 2022 Midstream service assets $ 158,749 $ 151,157 Computer hardware and software 29,007 21,758 Vehicles 5,046 7,934 Leasehold improvements 7,136 7,136 Buildings 7,039 7,039 Other 7,710 6,087 Depreciable total 214,687 201,111 Less accumulated depreciation, amortization and impairment (107,541) (96,383) Depreciable total, net $ 107,146 $ 104,728 Land 23,147 23,075 Total midstream and other fixed assets, net $ 130,293 $ 127,803 During the year ended December 31, 2022, the Company retired $15.6 million in midstream service assets, resulting in the removal of $11.4 million in accumulated depreciation and the recognition of an associated loss of $4.2 million. No such retirements occurred during the year ended December 31, 2023.

Debt

Debt	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Debt	Note 7 Debt Long-term debt, net The following table presents the Company's long-term debt and debt issuance costs, net included in "Long-term debt, net" on the consolidated balance sheets as of the dates presented: (in thousands) December 31, 2023 December 31, 2022 January 2025 Notes — 455,628 January 2028 Notes 700,309 300,309 July 2029 Notes 298,214 298,214 September 2030 Notes 500,000 — Senior Secured Credit Facility (1) 135,000 70,000 Total long-term debt 1,633,523 $ 1,124,151 Unamortized debt issuance costs (21,800) (11,128) Unamortized discounts (6,068) — Unamortized premiums 3,769 — Total long-term debt, net $ 1,609,424 $ 1,113,023 _____________________________________________________________________________ (1) Unamortized debt issuance costs related to the Senior Secured Credit Facility of $14.1 million and $7.3 million as of December 31, 2023 and 2022, respectively, are included in "Other noncurrent assets, net" on the consolidated balance sheets. Senior unsecured notes repurchases The following table presents the Company's repurchases of its senior unsecured notes under authorized bond purchase programs and the related gain or loss on extinguishment of debt during the period presented: (in thousands) Year ended January 2025 Notes $ 122,285 January 2028 Notes 60,735 July 2029 Notes 101,786 Total principal amount repurchased $ 284,806 Less: Consideration paid $ 282,902 Write off of debt issuance costs 3,363 Loss on extinguishment of debt, net (1) $ (1,459) _____________________________________________________________________________ (1) Amounts are included in "Loss on extinguishment of debt, net" on the consolidated statements of operations. No senior unsecured notes were repurchased during the years ended December 31, 2023 and 2021. Senior Secured Credit Facility On September 13, 2023 (the "Eleventh Amendment Effective Date"), the Company entered into the Limited Consent and Eleventh Amendment to the Senior Secured Credit Facility (the "Eleventh Amendment"). The Eleventh Amendment, among other things, (i) provided consent for the Acquisitions and (ii) provided for increases to the borrowing base and revolving elected commitments upon consummation of the Henry, Maple, and Tall City Acquisitions (as so amended, the "Amended Senior Secured Credit Facility"). The Amended Senior Secured Credit Facility will mature on September 13, 2027. After consummation of the Henry, Maple, and Tall City Acquisitions, the Amended Senior Secured Credit Facility has a maximum credit amount of $3.0 billion, a borrowing base of up to $1.5 billion and an aggregate revolving elected commitment of up to $1.25 billion. As of December 31, 2023, the Senior Secured Credit Facility, which matures on September 13, 2027, had a maximum credit amount of $3.0 billion, a borrowing base and an aggregate elected commitment of $1.5 billion and $1.25 billion, respectively, with a $135.0 million balance outstanding, and was subject to an interest rate of 7.706%. The borrowing base is subject to a semi-annual redetermination occurring by May 1 and November 1 of each year based on the lenders' evaluation of the Company's oil, NGL and natural gas reserves. As defined in the Senior Secured Credit Facility, (i) the Adjusted Base Rate advances under the facility bear interest payable quarterly at an Adjusted Base Rate plus applicable margin, which ranges from 1.25% to 2.25%, based on the ratio of outstanding revolving credit to the borrowing base under the Senior Secured Credit Facility; and (ii) the SOFR advances under the facility bear interest, at the Company's election, at the end of one-month, three-month or six-month interest periods (and in the case of six-month interest periods, every three months prior to the end of such interest period) at a Secured Overnight Financing Rate ("SOFR") plus an applicable margin, which ranges from 2.25% to 3.25%, based on the ratio of outstanding revolving credit to the borrowing base under the Senior Secured Credit Facility. Vital is required to pay a quarterly commitment fee on the unused portion of the financial institutions' commitment, which ranges from 0.375% of 0.500%. The Senior Secured Credit Facility is secured by a first-priority lien on the assets and stock of Vital and Vital Midstream Services, LLC ("VMS") (the "Guarantor"), including oil and natural gas properties constituting at least 85% of the present value of the Company's proved reserves. Further, the Company is subject to various financial and non-financial covenants on a consolidated basis, including a current ratio at the end of each calendar quarter, of not less than 1.00 to 1.00. As defined by the Senior Secured Credit Facility, the current ratio represents the ratio of current assets to current liabilities, inclusive of available capacity and exclusive of current balances associated with derivative positions. Additionally, the Company must maintain as of the last day of each calendar quarter a ratio of (a) its total debt (excluding reimbursement obligations in respect of undrawn letters of credit, if no loans are outstanding under the Senior Secured Credit Facility) minus a maximum of $50.0 million of unrestricted and unencumbered cash and cash equivalents, to (b) "Consolidated EBITDAX," as defined in the Senior Secured Credit Facility, for any period of four consecutive calendar quarters ending on the last day of such applicable calendar quarter of not greater than 3.50 to 1.00. The Company was in compliance with these covenants as of December 31, 2023 and 2022, as then in effect. Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $80.0 million. As of December 31, 2023 and 2022, the Company had no letters of credit outstanding under the Senior Secured Credit Facility. See Note 18 for discussion of additional borrowings on the Senior Secured Credit Facility subsequent to December 31, 2023. September 2030 Notes On September 25, 2023, the Company completed an offering and sale of $500.0 million in aggregate principal amount of 9.750% senior unsecured notes due 2030. Interest for the September 2030 Notes is payable semi-annually, in cash in arrears on April 15 and October 15 of each year, commencing October 15, 2023 with interest from closing to that date. The September 2030 Notes were issued at 98.742% of par value, which resulted in a discount upon issuance of $6.3 million. The Company received net proceeds of approximately $484.7 million from the September 2030 Notes, after deducting issuance discounts, underwriting discounts and commissions and offering costs. The proceeds from the offering were used to redeem the entire principal amount outstanding of its January 2025 Notes and for general corporate purposes, including repaying a portion of the borrowings outstanding under the Company's Senior Secured Credit Facility. July 2029 Notes On July 16, 2021, the Company completed a private offering and sale of $400.0 million in aggregate principal amount of 7.750% senior unsecured notes due 2029 (the "July 2029 Notes"). Interest for the July 2029 Notes is payable semi-annually, in cash in arrears on January 31 and July 31 of each year, commencing January 31, 2022 with interest from closing to that date. The Company received net proceeds of approximately $392.0 million from the July 2029 Notes, after deducting underwriting discounts and commissions and estimated offering expenses. The proceeds from the offering were used for general corporate purposes, including repaying a portion of the borrowings outstanding under the Senior Secured Credit Facility. January 2025 Notes and January 2028 Notes On January 24, 2020, the Company completed an offer and sale (the "Offering") of $600.0 million in aggregate principal amount of 9.500% senior unsecured notes due 2025 (the "January 2025 Notes") and $400.0 million in aggregate principal amount of 10.125% senior unsecured notes due 2028 (the "Original January 2028 Notes"). Interest for both the January 2025 Notes and Original January 2028 Notes is payable semi-annually, in cash in arrears on January 15 and July 15 of each year. The Company received net proceeds of $982.0 million from the Offering, after deducting underwriting discounts and commissions and estimated offering expenses. The proceeds from the Offering were used (i) to fund cash tender offers and consent solicitations for any or all of the Company's outstanding 5 5/8% senior unsecured notes due 2022 and 6 1/4% senior unsecured notes due 2023 (ii) to repay the Company's 5 5/8% senior unsecured notes due 2022 and 6 1/4% senior unsecured notes due 2023 that remained outstanding after settling the Tender Offers and (iii) for general corporate purposes, including repayment of a portion of the borrowings outstanding under the Company's Senior Secured Credit Facility. On September 25, 2023, the Company completed an offering and sale of $400.0 million in aggregate principal amount of new 10.125% senior unsecured notes due 2028 (the "New January 2028 Notes" and, together with the Original January 2028 Notes, the "January 2028 Notes") as additional notes under, and subject to the terms of, the indenture governing the January 2028 Notes. The New January 2028 Notes were issued at 101.000% of par value, which resulted in a premium upon issuance of $4.0 million. The Company received net proceeds of approximately $396.7 million from the New January 2028 Notes, after issuance premiums and deducting underwriting discounts and commissions and offering costs. On December 27, 2023, the Company issued a notice to redeem the entire $455.6 million principal amount outstanding of its January 2025 Notes using the proceeds from the offering of the September 2030 Notes and New January 2028 Notes. As a result, the Company incurred a $2.2 million charge related to the early redemption and a write-off of debt issuance costs of $1.5 million, both of which are included in "Loss on extinguishment of debt, net" on the consolidated statements of operation Senior unsecured notes covenants The terms of each of the Company's senior unsecured notes include covenants, which are in addition to but different than similar covenants in the Senior Secured Credit Facility, which limit the Company's ability to incur indebtedness, make restricted payments, grant liens and dispose of assets. The Company was in compliance with these covenants as of December 31, 2023 and 2022. Each of the Company's senior unsecured notes are fully and unconditionally guaranteed on a senior unsecured basis by Vital Midstream Services, LLC and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the applicable indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the applicable indenture, release from guarantee under the Senior Secured Credit Facility, or liquidation or dissolution. On February 3, 2023, Garden City Minerals, LLC ("GCM") was merged with and into Vital Energy, Inc. and is therefore no longer a guarantor under any of the Company's debt arrangements as of December 31, 2023. Interest expense The following table presents amounts that have been incurred and charged to interest expense: Years ended December 31, (in thousands) 2023 2022 2021 Interest expense on borrowings $ 144,731 $ 123,255 $ 114,800 Amortization of debt issuance costs and other adjustments 7,980 5,738 4,451 Less capitalized interest 2,892 3,872 5,866 Total interest expense $ 149,819 $ 125,121 $ 113,385

Stockholders' equity

Stockholders' equity	12 Months Ended
	Dec. 31, 2023
Equity [Abstract]
Stockholders' equity	Note 8 Stockholders' equity Equity offering On September 19, 2023, the Company completed the sale of 2,750,000 shares of its common stock for net proceeds of $140.2 million, after underwriting discounts, commissions and offering expenses. On September 29, 2023, the underwriters exercised their option to purchase an additional 412,500 shares of common stock, which resulted in net proceeds to the Company of $21.0 million, after underwriting discounts, commissions and offering expenses. Equity issued for acquisitions of oil and natural gas properties During the year ended December 31, 2023, the Company issued shares of its common stock and Preferred Stock in connection with the closing of various acquisitions of oil and gas properties, as shown in the table below. Acquisition Closing date Common stock issued (1) Preferred stock issued (2) Grey Rock 12/21/2023 627,026 595,104 Tall City 11/6/2023 1,402,258 N/A Henry 11/5/2023 2,145,725 6,131,381 Maple 10/31/2023 3,370,497 N/A Driftwood 4/3/2023 1,578,948 N/A _____________________________________________________________________________ (1) As of December 31, 2023, 773,290 of the common shares issued for the Tall City Acquisition and 357,500 of the common shares issued for the Maple Acquisition remain in escrow pending post-close settlements. (2) On November 29, 2023, the Preferred Stock issued in connection with the Henry Acquisition were converted to common shares. See "Preferred Stock" below for additional discussion. See Note 4 for additional information on each of the acquisitions. See Note 18 for shares issued in an acquisition occurring subsequent to December 31, 2023. Preferred Stock The Company's non-voting Preferred Stock is entitled to cumulative preferred cash dividends at an initial rate of 2.0% per annum of the liquidation preference per share of $54.96, as defined in the Certificate of Designations, provided that such rate shall automatically increase to (i) 5.0% on September 15, 2024, and (ii) 8.0% on September 15, 2025, payable quarterly in arrears, if, and when, declared. If the Company fails to pay in full any distribution on the Preferred Stock, the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full. The Company may, at any time and from time to time, elect to redeem all outstanding shares of Preferred Stock, in accordance with the terms of the Certificate of Designations. Upon stockholder approval, the Preferred Stock is to be converted to an equal number of shares of common stock. On November 21, 2023, upon recommendation of the Company's board of directors, stockholders approved the conversion of the 6,131,381 shares of Preferred Stock issued in connection with the Henry Acquisition to an equal number of shares of common stock. The conversion occurred on November 29, 2023. As a result of the conversion, the Company paid a dividend of $0.4 million for the period for which the Preferred Stock was outstanding. Authorized shares increase Upon recommendation of the Company's board of directors, stockholders approved amendments to the Company's Amended and Restated Certificate of Incorporation to increase the number of authorized shares of its common stock as follows: • On May 26, 2022, from 22,500,000 shares to 40,000,000 shares. • On November 21, 2023, from 40,000,000 shares to 80,000,000 shares. Share repurchase program On May 31, 2022, the Company's board of directors authorized a $200.0 million share repurchase program. The repurchase program commenced in May 2022 and expires in May 2024. Share repurchases under the program may be made through a variety of methods, which may include open market purchases, including under plans complying with Rule 10b5-1 of the Exchange Act, and privately negotiated transactions. The timing and actual number of share repurchases will depend upon several factors, including market conditions, business conditions, the trading price of the Company's common stock and the nature of other investment opportunities available to the Company. The following table presents the Company's open market repurchases of its common stock during the periods presented: (in thousands, except for share and share price data) Year ended Shares of Company common stock repurchased 490,536 Average share price (1) $ 76.02 Total $ 37,290 ______________________________________________________________________________ (1) Average share price includes any commissions paid to repurchase stock. All shares were retired upon repurchase. No shares were repurchased during the years ended December 31, 2023 and 2021. ATM Program On February 23, 2021, the Company entered into an equity distribution agreement with Wells Fargo Securities, LLC acting as sales agent and/or principal (the "Sales Agent"), pursuant to which the Company was able to offer and sell, through the Sales Agent, shares of its common stock having an aggregate gross sales price of up to $75.0 million through an "at-the-market" equity program (the "ATM Program"). As of December 31, 2021, the Company had sold 1,438,105 shares of its common stock pursuant to the ATM Program for net proceeds of approximately $72.5 million, after underwriting commissions and other related expenses, thus completing the ATM Program. Proceeds from the share sales were utilized to reduce borrowings on the Senior Secured Credit Facility.

Compensation plans

Compensation plans	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Compensation plans	Note 9 Compensation plans Equity Incentive Plan The Equity Incentive Plan provides for the granting of incentive awards in the form of restricted stock awards, stock option awards, performance share awards, outperformance share awards, performance unit awards, phantom unit awards and other awards. On May 20, 2021, the Company's stockholders approved an amendment to the Equity Incentive Plan to, among other things, increase the maximum number of shares of the Company's common stock issuable under the Equity Incentive Plan from 1,492,500 to 2,432,500 shares. As of December 31, 2023, the Company had outstanding restricted stock awards, performance share awards, performance unit awards, phantom unit awards and an immaterial amount of stock option awards. Equity Awards Restricted stock awards and restricted stock unit awards All service vesting restricted stock awards are treated as issued and outstanding in the consolidated financial statements. If the termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to employees vest in a variety of schedules that mainly include (i) 33%, 33% and 34% vesting per year beginning on the first anniversary of the grant date and (ii) full vesting on the third anniversary of the grant date. Non-employee directors are granted restricted stock unit awards which are 100% vested on the date of grant, with the option to defer settlement of some or all of such awards in shares until the director's separation from service if the director timely elects in accordance with the terms of the Nonqualified Director Deferred Compensation Plan. If a director elects to defer settlement of their restricted stock units, we refer to them as deferred stock units or DSUs. Performance share awards Performance share awards, which the Company has determined are equity awards, are subject to a combination of market, performance and service vesting criteria. For portions of awards with market criteria, a Monte Carlo simulation prepared by an independent third party is utilized to determine the grant-date (or modification date) fair value, and the associated expense is recognized on a straight-line basis over the three-year requisite service period of the awards. For portions of awards with performance criteria, the fair value is equal to the Company's closing stock price on the grant date (or modification date), and for each reporting period, the associated expense fluctuates and is adjusted based on an estimated payout of the number of shares of common stock to be delivered on the payment date for the three-year performance period, which begins either at the start of the calendar year in which the award is granted or on December 1 of the year prior to the Calendar year in which the award is granted. For performance share awards granted in 2022, the market criteria consists of: (i) annual relative stockholder return comparing the Company's stockholder return to the stockholder return of the exploration and production companies listed in the Russell 2000 index and (ii) annual absolute total stockholder return, together the "PSU Matrix." The performance criteria for these awards consists of: (i) earnings before interest, taxes, depreciation, amortization and exploration expense ("EBITDAX") and three-year total debt reduction (the "EBITDAX/Total Debt Component") (ii) growth in inventory (the "Inventory Growth Component") and (iii) emissions reduction (the "ESG Component"). Any shares earned are expected to be issued in the first quarter following the completion of the respective requisite service periods based on the achievement of certain market and performance criteria, and the payout can range from 0% to 225%. Equity award activity The following table presents activity for equity compensation awards for the year ended December 31, 2023: (in thousands) Restricted Stock Awards Weighted-average grant-date fair value (per share) Stock Option Awards Weighted-average exercise price (per share) Performance Share Awards Weighted-average grant-date fair value (per share) Outstanding as of December 31, 2022 362 $52.90 3 $235.08 48 $89.76 Granted 340 $54.68 — — Forfeited (47) $57.39 — — Vested (1) (183) $44.86 — — Expired or canceled — (1) $346.80 — Outstanding as of December 31, 2023 (2) 472 $56.87 2 $136.83 48 $101.48 _____________________________________________________________________________ (1) The aggregate intrinsic value of vested restricted stock awards for the year ended December 31, 2023 was $9.3 million. (2) The vested and exercisable stock option awards as of December 31, 2023 had no intrinsic value. As of December 31, 2023, total unrecognized cost related to equity compensation awards was $18.3 million, which will be settled in shares. Such cost will be recognized on a straight-line basis over an expected weighted-average period of 1.73 years. Equity-based liability awards Performance unit awards Performance unit awards, which the Company has determined are liability awards since they are settled in cash, are subject to a combination of market, performance and service vesting criteria. For portions of awards with market criteria, a Monte Carlo simulation prepared by an independent third party is utilized to determine the fair value, and is re-measured at each reporting period until settlement. For portions of awards with performance criteria, the Company's closing stock price is utilized to determine the fair value and is re-measured on the last trading day of each reporting period until settlement and, additionally, the associated expense fluctuates based on an estimated payout for the three-year performance period. The expense related to the performance unit awards is recognized on a straight-line basis over the three-year requisite service period of the awards, and the life-to-date recognized expense is adjusted accordingly at each reporting period based on the quarterly fair value re-measurements and redetermination of the estimated payout for the performance criteria. For each performance unit award, the three-year performance period begins at the start of the calendar year in which the award is granted. For performance unit awards granted in 2023, the market criteria consists of the PSU Matrix. The performance criteria for these awards consists of: (i) the EBITDAX/Total Debt Component, (ii) the Inventory Growth Component and (iii) the ESG Component. Any units earned are expected to be paid in cash during the first quarter following the completion of the requisite service period, based on the achievement of certain market and performance criteria, and the payout can range from 0% to 250% for the market criteria and 0% to 200% for the performance criteria. For performance unit awards granted in 2021, the market criteria consists of the PSU Matrix. The performance criteria for these awards consists of: (i) the EBITDAX/Total Debt Component and (ii) the Inventory Growth Component. Any units earned are expected to be paid in cash during the first quarter following the completion of the requisite service period, based on the achievement of certain market and performance criteria, and the payout range was 0% to 250% for the market criteria and 0% to 200% for the performance criteria. The performance units granted March 9, 2021 had a performance period of January 1, 2021 to December 31, 2023. Certain of the market and performance criteria were satisfied, resulting in a 146% payout, which will be paid in cash during the first quarter of 2024. For performance unit awards granted in 2020, the market criteria consists of: (i) the RTSR Performance Percentage and (ii) the ATSR Appreciation. The performance criteria for these awards consists of the ROACE Percentage. Potential payout of these awards ranged from 0% to 200%, but was capped at 100% if the ATSR Appreciation was zero or less. In the first quarter of 2023, following the completion of the requisite service period and achievement of certain market and performance criteria, the granted awards were issued at a 151% payout. Phantom unit awards Phantom unit awards, which the Company has determined are liability awards, represent the holder's right to receive the cash equivalent of one share of common stock of the Company for each phantom unit as of the applicable vesting date, subject to withholding requirements. Phantom unit awards granted to employees vest 33%, 33% and 34% per year beginning on the first anniversary of the grant date. Equity-based liability award activity The following table presents activity for equity-based liability awards for the year ended December 31, 2023: (in thousands) Performance Unit Awards Phantom Unit Awards Outstanding as of December 31, 2022 150 18 Granted 75 — Forfeited — — Vested (1)(2) (67) (16) Outstanding as of December 31, 2023 158 2 _____________________________________________________________________________ (1) The performance unit awards granted on March 5, 2020 had a performance period of January 1, 2020 to December 31, 2022 and, as their market and performance criteria were satisfied, resulted in a 151% payout, or 101,368 units. As such, the granted awards vested and were paid out in cash on March 3, 2023 at $57.06 based on the Company's closing stock price on the vesting date. (2) On March 1, 2023 and March 3, 2023, the vested phantom unit awards were settled and paid out in cash at a fair value of $52.56 and $57.06 based on the Company's closing stock price on the respective vesting dates. The fair value per unit of outstanding phantom unit awards as of December 31, 2023 was $45.49. As of December 31, 2023, total unrecognized cost related to equity-based liability awards was $2.8 million, which will be settled in cash rather than shares. Such cost will be recognized on a straight-line basis over an expected weighted-average period of 1.88 years. Fair value assumptions The Company utilizes the closing stock price on the grant date to determine the fair value of restricted stock awards. The following table presents (i) the assumptions used to estimate the fair values per performance share or unit and (ii) the expense per performance share or unit, which is the fair value per performance share or unit adjusted for the estimated payout of the performance criteria, for the outstanding performance share and unit awards as of December 31, 2023 for the grant dates presented: Performance Share Awards Performance February 22, 2022 February 15, 2023 Remaining performance period on grant date 2.86 years n/a Remaining performance period n/a 2 years Risk-free interest rate (1) 1.71 % 4.13 % Dividend yield — % — % Expected volatility (2) 119.25 % 66.40 % Expense per performance share or unit as of December 31, 2023 $101.48 $45.17 ______________________________________________________________________________ (1) The remaining performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on the grant date for each respective award. (2) The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility. The performance unit awards granted on March 9, 2021 had a performance period of January 1, 2021 to December 31, 2023. As of December 31, 2023, their expense per performance unit was $66.33 The Company utilizes the closing stock price on the last day of each reporting period to determine the fair value of phantom unit awards and the life-to-date recognized expense is adjusted accordingly. Equity-based compensation The following table reflects equity-based compensation expense for the years presented: Years ended December 31, (in thousands) 2023 2022 2021 Equity awards: Restricted stock awards $ 12,114 $ 8,596 $ 7,594 Performance share awards 1,855 1,590 1,657 Stock option awards — — 7 Total share-settled equity-based compensation, gross $ 13,969 $ 10,186 $ 9,258 Less amounts capitalized (2,975) (1,783) (1,583) Total share-settled equity-based compensation, net $ 10,994 $ 8,403 $ 7,675 Liability awards: Performance unit awards $ 2,932 $ 741 $ 7,480 Phantom unit awards 270 1,186 1,238 Total cash-settled equity-based compensation, gross $ 3,202 $ 1,927 $ 8,718 Less amounts capitalized (50) (272) (365) Total cash-settled equity-based compensation, net $ 3,152 $ 1,655 $ 8,353 Total equity-based compensation, net $ 14,146 $ 10,058 $ 16,028 See Note 17 for discussion of the Company's organizational restructurings and the related equity-based compensation reversals during the years ended December 31, 2023, 2022, and 2021.

Net income per common share

Net income per common share	12 Months Ended
	Dec. 31, 2023
Earnings Per Share [Abstract]
Net income per common share	Note 10 Net income per common share Basic net income per common share is computed by first subtracting preferred stock dividends from net income to arrive at net income available to common stockholders, and then dividing net income available to common stockholders by the basic weighted-average common shares outstanding for the period. Diluted net income per common share is computed by dividing net income by the diluted weighted average common shares outstanding for the period, which reflects the potential dilution of preferred stock and non-vested equity-based compensation awards. See Notes 8 and 9 for additional discussion of the Company's preferred stock and equity-based compensation awards. The following table reflects the calculations of basic and diluted (i) weighted-average common shares outstanding and (ii) net income per common share for the periods presented: Years ended December 31, (in thousands, except for per share data) 2023 2022 2021 Net income $ 695,078 $ 631,512 $ 145,008 Less: Preferred stock dividends 449 — — Net income available to common stockholders $ 694,629 $ 631,512 $ 145,008 Weighted-average common shares outstanding: Basic 20,254 16,672 14,240 Dilutive non-vested restricted stock awards 106 183 181 Dilutive non-vested performance share awards (1) 2 12 43 Dilutive preferred stock 421 — — Diluted 20,783 16,867 14,464 Net income per common share: Basic $ 34.30 $ 37.88 $ 10.18 Diluted $ 33.44 $ 37.44 $ 10.03 _____________________________________________________________________________ (1) The dilutive effect of the non-vested performance shares for the year ended December 31, 2023 was calculated as of the end of the performance period on December 31, 2023.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Note 11 Derivatives The Company has two types of derivative instruments as of December 31, 2023: (i) commodity derivatives and (ii) a contingent consideration derivative. In previous periods, the Company also engaged in an interest rate swap derivative, which concluded during the quarterly period ended June 30, 2022. See Note 2 for the Company's significant accounting policies for derivatives and presentation in the consolidated financial statements and Note 12 for fair value measurement of derivatives on a recurring basis. The following table summarizes components the Company's gain (loss) on derivatives, net by type of derivative instrument for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Commodity $ 89,951 $ (291,973) $ (453,784) Contingent consideration 6,279 (6,764) 1,639 Interest rate — 14 (30) Gain (loss) on derivatives, net $ 96,230 $ (298,723) $ (452,175) Commodity Due to the inherent volatility in oil, NGL and natural gas prices and the sometimes wide pricing differentials between where the Company produces and where the Company sells such commodities, the Company engages in commodity derivative transactions, such as puts, swaps, collars and basis swaps to hedge price risk associated with a portion of the Company's anticipated sales volumes. By removing a portion of the price volatility associated with future sales volumes, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations. During the year ended December 31, 2023, the Company's derivatives were settled based on reported prices on commodity exchanges, with (i) oil derivatives settled based on WTI NYMEX, Argus WTI Midland and Argus WTI Formula Basis pricing, and (ii) natural gas derivatives settled based on Henry Hub NYMEX and Waha Inside FERC pricing. The following table summarizes open commodity derivative positions as of December 31, 2023, for commodity derivatives that were entered into through December 31, 2023, for the settlement periods presented: Year 2024 Year 2025 Oil: WTI NYMEX - Swaps: Volume (Bbl) 18,835,950 3,445,000 Weighted-average price ($/Bbl) $ 75.37 $ 75.52 WTI NYMEX - Three-way Collars: Volume (Bbl) 217,350 — Weighted-average sold put price ($/Bbl) $ 50.00 $ — Weighted-average floor price ($/Bbl) $ 66.51 $ — Weighted-average ceiling price ($/Bbl) $ 87.09 $ — Argus WTI Midland to Argus WTI Formula Basis - Basis Swaps: Volume (Bbl) 293,300 — Weighted-average differential ($/Bbl) $ 0.11 $ — Natural gas: Henry Hub NYMEX - Swaps: Volume (MMBtu) 26,075,700 — Weighted-average price ($/MMBtu) $ 3.47 $ — Henry Hub NYMEX - Collars: Volume (MMBtu) 776,292 — Weighted-average floor price ($/MMBtu) $ 3.40 $ — Weighted-average ceiling price ($/MMBtu) $ 6.11 $ — Waha Inside FERC to Henry Hub NYMEX - Basis Swaps: Volume (MMBtu) 26,851,992 — Weighted-average differential ($/MMBtu) $ (0.74) $ — Contingent consideration The Sixth Street PSA provided for potential contingent payments to be paid to the Company if certain cash flow targets are met related to divested oil and natural gas property operations. The Sixth Street Contingent Consideration provides the Company with the right to receive up to a maximum of $93.7 million in additional cash consideration, comprised of potential quarterly payments through June 2027 totaling up to $38.7 million and a potential balloon payment of $55.0 million in June 2027. As of December 31, 2023, the maximum remaining additional cash consideration of the contingent consideration was $84.2 million. The fair value of the Sixth Street Contingent Consideration was determined to be $31.1 million as of December 31, 2023 and $26.6 million as of December 31, 2022. See Note 4 for further discussion of the Working Interest Sale associated with the Sixth Street Contingent Consideration. Interest rate swap In previous periods, the Company was engaged in an interest rate derivative swap to hedge interest rate risk associated with a portion of the Company's anticipated outstanding debt under the Senior Secured Credit Facility. The Company paid a fixed rate over the contract term for that portion. During the year ended December 31, 2022, the Company's interest rate swap derivative, which concluded during the quarterly period ended June 30, 2022, was settled based on LIBOR rates. By removing

Fair value measurements

Fair value measurements	12 Months Ended
	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Fair value measurements	Note 12 Fair value measurements The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation techniques, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on inputs to the valuation techniques as follows: Level 1— Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2— Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Level 3— Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability. Fair value measurement on a recurring basis For further discussion of the Company's derivatives, see Notes (i) 2 for the Company's significant accounting policies for derivatives and (ii) 11 for derivatives. Balance sheet presentation The following tables present the Company's derivatives by (i) balance sheet classification, (ii) derivative type and (iii) fair value hierarchy level, and provide a total, on a gross basis and a net basis reflected in "Derivatives" on the consolidated balance sheets as of the dates presented: December 31, 2023 (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets Assets: Current: Commodity $ — $ 106,067 $ — $ 106,067 $ (9,032) $ 97,035 Contingent consideration — — 2,301 2,301 — 2,301 Noncurrent: Commodity — 22,266 — 22,266 — 22,266 Contingent consideration — — 28,805 28,805 — 28,805 Liabilities: Current: Commodity — (9,032) — (9,032) 9,032 — Net derivative asset positions $ — $ 119,301 $ 31,106 $ 150,407 $ — $ 150,407 December 31, 2022 (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets Assets: Current: Commodity $ — $ 35,586 $ — $ 35,586 $ (13,193) $ 22,393 Contingent consideration — — 2,277 2,277 — 2,277 Noncurrent: Contingent consideration — — 24,363 24,363 — 24,363 Liabilities: Current: Commodity — (19,153) — (19,153) 13,193 (5,960) Net derivative asset positions $ — $ 16,433 $ 26,640 $ 43,073 $ — $ 43,073 Commodity Significant Level 2 inputs associated with the calculation of discounted cash flows used in the fair value mark-to-market analysis of commodity derivatives include each commodity derivative contract's corresponding commodity index price(s), forward price curve models for substantially similar instruments and counterparty risk-adjusted discount rates generated from a compilation of data gathered by a third-party valuation specialist. The Company reviewed the third-party specialist's valuations of commodity derivatives, including the related inputs, and analyzed changes in fair values between reporting dates. Contingent consideration The Working Interest Sale provided for potential contingent payments to be paid to the Company. The Sixth Street Contingent Consideration associated with the Working Interest Sale was categorized as Level 3, as the Company utilized its own cash flow projections along with a risk-adjusted discount rate generated by a third-party valuation specialist to determine the valuation. The Company reviewed the third-party specialist's valuation, including the related inputs, and analyzed changes in fair values between the divestiture closing date and the reporting dates. The fair value of the Sixth Street Contingent Consideration was recorded as part of the basis in the oil and natural gas properties divested and as a contingent consideration asset. At each quarterly reporting period, the Company remeasures contingent consideration with the change in fair values recognized in " Gain (loss) on derivatives, net The following table summarizes the changes in contingent consideration derivatives classified as Level 3 measurements for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Balance of Level 3 at beginning of year $ 26,640 $ 35,861 $ — Sixth Street Contingent Consideration valuation as of Sixth Street Closing Date — — 33,832 Change in Sixth Street Contingent Consideration fair value 6,279 (6,764) 2,029 Settlements realized (1) (1,813) (2,457) — Balance of Level 3 at end of year $ 31,106 $ 26,640 $ 35,861 _____________________________________________________________________________ (1) For the years ended December 31, 2023 and 2022, the settlements included in "Settlements received for contingent consideration" in cash flows from investing activities on the consolidated statements of cash flows. See Note 4 for further discussion of the Company's acquisitions and divestitures associated with the potential contingent consideration payments. Items not accounted for at fair value The carrying amounts reported on the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values. The Company has not elected to account for its debt instruments at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented: December 31, 2023 December 31, 2022 (in thousands) Long-term debt Fair value (1) Long-term debt Fair value (1) January 2025 Notes $ — $ — $ 455,628 $ 449,122 January 2028 Notes 700,309 719,617 300,309 292,846 July 2029 Notes 298,214 285,099 298,214 268,416 September 2030 Notes 500,000 518,875 — — Senior Secured Credit Facility 135,000 135,095 70,000 69,945 Total $ 1,633,523 $ 1,658,686 $ 1,124,151 $ 1,080,329 _____________________________________________________________________________ (1) The fair values of the outstanding notes were determined using the Level 2 fair value hierarchy quoted market prices for each respective instrument as of December 31, 2023 and 2022. The fair values of the outstanding debt under the Senior Secured Credit Facility were estimated utilizing the Level 2 fair value hierarchy pricing model for similar instruments as of December 31, 2023 and 2022.

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Income taxes	Note 13 Income taxes The Company is subject to federal and state income taxes and the Texas franchise tax. The following table presents the "Current" and "Deferred" income tax benefit (expense) reported on the consolidated statements of operations for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Current income tax benefit (expense): Federal $ — $ — $ — State (5,723) (6,121) (1,324) Deferred income tax benefit (expense): Federal 190,341 — — State (1,281) 619 (2,321) Total income tax benefit (expense): $ 183,337 $ (5,502) $ (3,645) Total income tax benefit (expense) differed from amounts computed by applying the applicable federal income tax rate of 21% for the years ended December 31, 2023, 2022 and 2021 to pre-tax earnings as a result of the following: Years ended December 31, (in thousands) 2023 2022 2021 Income tax expense computed by applying the statutory rate $ (107,466) $ (133,773) $ (31,217) Change in deferred tax valuation allowance 297,658 144,480 45,717 Non-deductible equity-based compensation — (19,301) (13,640) State income tax and change in valuation allowance (5,803) 8,058 (3,274) Other items (1,052) (4,966) (1,231) Total income tax benefit (expense) $ 183,337 $ (5,502) $ (3,645) The Company is required to estimate the federal and state income taxes in each of the jurisdictions it operates in. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items for tax and financial accounting purposes. These differences and the Company's net operating loss carryforwards result in deferred tax assets and liabilities. The following table presents significant components of the Company's net deferred tax asset and liability as of the dates presented: (in thousands) December 31, 2023 December 31, 2022 Deferred tax assets: Net operating loss carryforwards $ 264,114 $ 307,357 Equity-based compensation 232 2,933 Interest expense limitation 3,908 — Other 4,117 1,110 Total deferred tax asset 272,371 311,400 Valuation allowance (20,145) (298,184) Deferred tax assets, net of valuation allowance 252,226 13,216 Deferred tax liabilities: Oil and natural gas properties, midstream service assets and other fixed assets (36,524) (11,105) Derivatives (25,353) (2,331) Other (1,513) — Total deferred tax liabilities (63,390) (13,436) Total net deferred tax asset (liability) (1) $ 188,836 $ (220) ___________________________________________________________________________ (1) The net deferred tax asset as of December 31, 2023 is included in "Deferred income taxes" on the consolidated balance sheet and the net deferred tax liability as of December 31, 2022 is included in "Other noncurrent liabilities" on the consolidated balance sheet. As of December 31, 2023, the Company had federal net operating loss ("NOL") carryforwards totaling $1.2 billion, of which $789.8 million is subject to expiration and will begin to expire in 2034 and $366.8 million of which will not expire but may be limited in future periods, and state of Oklahoma NOL carryforwards totaling $523.7 million, of which $34.6 million will begin expiring in 2032 and $489.1 million will not expire. As of December 31, 2023, the Company’s deferred tax assets were primarily the result of U.S. net operating loss carryforwards. A valuation allowance of $298.2 million was recorded against the gross deferred tax asset balance as of December 31, 2022, on the basis of management’s assessment that its deferred tax assets did not meet the standard for recognition. As of each reporting date, the Company considers new evidence, both positive and negative, that could affect its view of the future realization of deferred tax assets. During the year ended December 31, 2023, the Company determined that there was sufficient positive evidence to conclude that it is more likely than not its federal deferred tax assets are realizable. For the year ended December 31, 2023, the Company recorded $183.3 million of tax benefit, which is primarily attributable to the release of the valuation allowance. The Company's effective tax rate is affected by changes in valuation allowances, recurring permanent differences and discrete items that may occur in any given year, but are not consistent from year to year. For the year ended December 31, 2023, the Company's effective tax rate was not meaningful due to the release of its valuation allowance. For the years ended December 31, 2022 and 2021, the Company had recorded a full valuation allowance against its federal and Oklahoma net deferred tax position and the only tax expense was related to Texas franchise tax. For the years ended December 31, 2022 and 2021, the Company’s items of discrete income tax expense or benefit were not material. If the Company were to experience an "ownership change" as determined under Section 382 of the Internal Revenue Code, the Company's ability to offset taxable income arising after the ownership change with net operating losses arising prior to the ownership change could be significantly limited. Based on information available as of December 31, 2023, no such ownership change has occurred. On August 16, 2022, the U.S. Inflation Reduction Act of 2022 (the "IRA") was signed into U.S. law. The IRA includes various tax provisions, including a 1% excise tax on stock repurchases made by publicly traded U.S. corporations and a 15% corporate alternative minimum tax ("CAMT") that applies to certain corporations with adjusted financial statement income in excess of $1.0 billion. Based on the Company's interpretation of the IRA, CAMT and related guidance, the Company does not expect the CAMT to impact its tax obligation for the 2023 taxable year; however, the 1% excise tax on stock repurchases will apply to the share repurchase program. The Company continues to evaluate the IRA and its effect on the Company's financial results and operating cash flows.

Credit risk

Credit risk	12 Months Ended
	Dec. 31, 2023
Risks and Uncertainties [Abstract]
Credit risk	Note 14 Credit risk Financial instruments that potentially subject the Company to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and commodity derivatives. The Company places its cash and cash equivalents with high credit quality financial institutions. The Company currently uses commodity derivatives to hedge its exposure to commodity prices. These transactions expose the Company to potential credit risk from its counterparties. The Company has entered into International Swaps and Derivatives Association Master Agreements ("ISDA Agreements") with each of its commodity derivative counterparties, each of whom is also a lender in its Senior Secured Credit Facility, which, together with hedge agreements with lenders under such facility, is secured by its oil, NGL and natural gas reserves; therefore, the Company is not required to post any additional collateral. The Company did not require collateral from its commodity derivative counterparties. The terms of the ISDA Agreements provide the non-defaulting or non-affected party the right to terminate the agreement upon the occurrence of certain events of default and termination events by a party and also provide for the marking to market of outstanding positions and the offset of the mark to market amounts owed to and by the parties (and in certain cases, the affiliates of the non-defaulting or non-affected party) upon termination; therefore, the credit risk associated with its commodity derivative counterparties is somewhat mitigated. The Company minimizes the credit risk in commodity derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into commodity derivatives only with counterparties that meet its minimum credit quality standard or have a guarantee from an affiliate that meets its minimum credit quality standard and (iii) monitoring the creditworthiness of its counterparties on an ongoing basis. As of December 31, 2023, the Company had a net asset position of $119.3 million from the fair values of its open commodity derivative contracts. See "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk" located elsewhere in this Annual Report and Notes 2, 11 and 12 for additional information regarding the Company's derivatives. The Company typically sells production to a relatively limited number of customers, as is customary in the exploration, development and production business. The Company's sales of purchased oil are generally made to a few customers. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The majority of the Company's accounts receivable are unsecured. On occasion the Company requires its customers to post collateral, and the inability or failure of the Company's significant customers to meet their obligations to the Company or their insolvency or liquidation may adversely affect the Company's financial results. In the current market environment, the Company believes that it could sell its production to numerous companies, so that the loss of any one of its major purchasers would not have a material adverse effect on its financial condition and results of operations solely by reason of such loss. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability. See Note 2 for additional information regarding the Company's accounts receivable and revenue recognition. The following table presents purchasers that individually accounted for 10% or more of the Company's oil, NGL and natural gas sales in at least one of the years presented: Years ended December 31, 2023 2022 2021 Purchaser A (1) 32 % 33 % 29 % Purchaser B 21 % n/a (2) n/a (2) Purchaser C 12 % n/a (2) n/a (2) Purchaser D (1) n/a (2) 18 % 14 % Purchaser E n/a (2) 17 % 24 % Purchaser F (1) n/a (2) n/a (2) 17 % _____________________________________________________________________________ (1) This purchaser of the Company's oil, NGL and natural gas sales is also a purchaser of the Company's sales of purchased oil included in the table below. (2) This purchaser did not account for 10% or greater of the Company's oil, NGL and natural gas sales. The following table presents purchasers that individually accounted for 10% or more of the Company's sales of purchased oil for the year ended December 31, 2021: Year ended December 31, 2021 Purchaser A (1) 47 % Purchaser B (1) 31 % Purchaser C (1) 22 % _____________________________________________________________________________ (1) This purchaser of the Company's sales of purchased oil is also a purchaser of the Company's oil, NGL and natural gas sales included in the table above. For the years ended December 31, 2023 and 2022, the Company's sales of purchased oil represented less than 10% of total oil, NGL and natural gas sales.

Commitments and contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Commitments and contingencies	Note 15 Commitments and contingencies From time to time, the Company is subject to various legal proceedings arising in the ordinary course of business, including those that arise from interpretation of federal, state and local laws and regulations affecting the oil and natural gas industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of the Company's current operations. The Company may not have insurance coverage for some of these proceedings and failure to comply with applicable laws and regulations can result in substantial penalties. While many of these matters involve inherent uncertainty, as of the date hereof, the Company believes that any such legal proceedings, if ultimately decided adversely, will not have a material adverse effect on the Company's business, financial position, results of operations or liquidity. The Company has committed to deliver, for sale or transportation, fixed volumes of product under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to firm transportation payments on excess pipeline capacity and other contractual penalties. These commitments are normal and customary for the Company's business. In certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. A portion of the Company's commitments are related to transportation commitments with a certain pipeline pertaining to the gathering of the Company's production from established acreage that extends into 2024. The Company was unable to satisfy a portion of this particular commitment with produced or purchased oil. Therefore, the Company expensed firm transportation payments on excess capacity of $5.8 million, $13.2 million and $4.4 million during the years ended December 31, 2023, 2022 and 2021, respectively, which is recorded in "Oil

Related parties

Related parties	12 Months Ended
	Dec. 31, 2023
Related Party Transactions [Abstract]
Related parties	Note 16 Related parties Halliburton The Chairman of the Company's board of directors is on the board of directors of Halliburton Company ("Halliburton"). Halliburton provides drilling and completions services to the Company. The Company has entered into a lease agreement with Halliburton, which became effective during the first quarter of 2023 and extends through 2025, to provide an electric fracture stimulation crew and the related services. Under the agreement, the Company had a lease liability of $59.7 million as of December 31, 2023 which is included in both current and noncurrent "Operating lease liabilities" on the consolidated balance sheets. Services provided under the lease agreement do not differ substantially from historical services provided by Halliburton, which were previously not subject to a long-term agreement. Payments to Halliburton are included in capital expenditures for oil and natural gas properties in cash flows from investing activities on the consolidated statements of cash flows. The following table presents the capital expenditures for oil and natural gas properties paid to Halliburton included in the consolidated statements of cash flows for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Capital expenditures for oil and natural gas properties $ 113,291 $ 103,152 $ 69,670

Organizational restructurings

Organizational restructurings	12 Months Ended
	Dec. 31, 2023
Restructuring and Related Activities [Abstract]
Organizational restructurings	Note 17 Organizational restructurings In November 2023, the Company made certain changes to its leadership and organizational structure, which included the departure of the Company's Vice President of Drilling, Completions and Environment, Health and Safety, effective December 22, 2023. Their responsibilities were absorbed by other members of the Company's management team. On August 24, 2022, the Company announced the departure of the Company's Senior Vice President and Chief Operating Officer. Their responsibilities were absorbed by other members of the Company's management team. On June 29, 2021, (the "Effective Date"), the Company committed to a company-wide reorganization effort (the “Plan”) that included a workforce reduction of 14 individuals, or approximately 5% of the workforce. The reduction in workforce was communicated to employees on the Effective Date and implemented immediately, subject to certain administrative procedures. The Plan was put in place in order to better position the Company for the future. In connection with each of these organizational restructurings, the Company incurred one-time charges comprised of compensation, tax, professional, outplacement and insurance-related expenses, which are recorded as "Organizational restructuring expenses" on the consolidated statements of operations. All equity-based compensation awards held by the affected employees were forfeited and the corresponding equity-based compensation was reversed. The following table reflects the aggregate of gross equity-based compensation expense reversals in connection with the Company's respective organizational restructurings, which are included in "General and administrative" on the consolidated statements of operations, for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Gross equity-based compensation expense reversals $ (283) $ (4,908) $ (1,088)

Subsequent events

Subsequent events	12 Months Ended
	Dec. 31, 2023
Subsequent Events [Abstract]
Subsequent events	Note 18 Subsequent events 2024 acquisition On February 2, 2024 (the "PEP Closing Date"), the Company purchased additional working interests in producing properties associated with the Henry Acquisition, with an effective date of August 1, 2023 (the "PEP Acquisition") through PEP Henry Production Partners LP, PEP HPP Jubilee SPV LP, PEP PEOF Dropkick SPV, LLC, PEP HPP Dropkick SPV LP and HPP Acorn SPV LP. The aggregate purchase price of $79.7 million consisted of (i) 878,690 shares of the Company's Common Stock, (ii) 980,272 shares of the Company's Preferred Stock based upon the share price as of the PEP Closing Date plus the fair value of anticipated dividends and (iii) $1.0 million in estimated transaction-related expenses, inclusive of customary closing price adjustments and subject to post-closing adjustments. Senior Secured Credit Facility On January 4, 2024 and February 15, 2024, the Company borrowed an additional $100.0 million and $30.0 million, respectively, on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $265.0 million as of March 4, 2024. See Note 7 for additional discussion of the Senior Secured Credit Facility.

Supplemental oil, NGL and natur

Supplemental oil, NGL and natural gas disclosures (unaudited)	12 Months Ended
	Dec. 31, 2023
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental oil, NGL and natural gas disclosures (unaudited)	Supplemental oil, NGL and natural gas disclosures Costs incurred in oil and natural gas property acquisition, exploration and development activities The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Property acquisition costs: Evaluated $ 1,328,571 $ 8,295 $ 899,128 Unevaluated 401,533 3,470 198,770 Exploration costs 29,612 26,384 33,482 Development costs 633,413 540,447 410,855 Total oil and natural gas properties costs incurred $ 2,393,129 $ 578,596 $ 1,542,235 Aggregate capitalized oil, NGL and natural gas costs The following table presents the aggregate capitalized costs related to oil, NGL and natural gas production activities with applicable accumulated depletion and impairment as of the dates presented: (in thousands) December 31, 2023 December 31, 2022 Gross capitalized costs: Evaluated properties $ 11,799,155 $ 9,554,706 Unevaluated properties not being depleted 195,457 46,430 Total gross capitalized costs 11,994,612 9,601,136 Less accumulated depletion and impairment (7,764,697) (7,318,399) Net capitalized costs $ 4,229,915 $ 2,282,737 The following table presents a summary of the unevaluated property costs not being depleted as of December 31, 2023, by year in which such costs were incurred: (in thousands) 2023 2022 2021 2020 and prior Total Unevaluated properties not being depleted $ 167,192 $ 3,124 $ 24,618 $ 523 $ 195,457 Unevaluated properties, which are not subject to depletion, are not individually significant and consist of costs for acquiring oil and natural gas leasehold where no evaluated reserves have been identified, including costs of wells being evaluated. The evaluation process associated with these properties has not been completed and therefore, the Company is unable to estimate when these costs will be included in the depletion calculation. Results of operations of oil, NGL and natural gas producing activities The following table presents the results of operations of oil, NGL and natural gas producing activities (excluding corporate overhead and interest costs) for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Revenues: Oil, NGL and natural gas sales $ 1,528,633 $ 1,794,374 $ 1,147,143 Production costs: Lease operating expenses 261,129 173,983 101,994 Production and ad valorem taxes 93,224 110,997 68,742 Oil transportation and marketing expenses 41,284 53,692 47,916 Gas gathering, processing and transportation expenses 2,013 — — Total production costs 397,650 338,672 218,652 Other costs: Depletion 446,611 298,259 201,691 Accretion of asset retirement obligation 3,518 3,653 4,018 Income tax expense (1) 149,788 11,538 14,456 Total other costs 599,917 313,450 220,165 Results of operations $ 531,066 $ 1,142,252 $ 708,326 _____________________________________________________________________________ (1) During the years ended December 31, 2022 and 2021, the Company recorded a full valuation allowance against its deferred tax assets related to its oil, NGL and natural gas producing activities. Accordingly, the income tax expense was computed utilizing the Company's effective tax rate of 1% for the year ended December 31, 2022 and 2% for the year ended December 31, 2021. During 2023, the Company determined that there was sufficient positive evidence to conclude that it is more likely than not its federal deferred tax assets are realizable and released the valuation allowance. As such, the income tax expense for the year ended December 31, 2023 is calculated using the statutory rate of 22%. Net proved oil, NGL and natural gas reserves Ryder Scott Company, L.P. ("Ryder Scott"), the Company's independent reserve engineers, estimated 100% of the Company's proved reserves as of December 31, 2023, 2022 and 2021. In accordance with SEC regulations, the reserves as of December 31, 2023, 2022 and 2021 were estimated using the Realized Prices, which reflect adjustments to the Benchmark Prices for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point. See Note 6 for these Realized Prices. The Company's reserves are reported in three streams: oil, NGL and natural gas. The SEC has defined proved reserves as the estimated quantities of oil, NGL and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil, NGL and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material. The following tables provide an analysis of the changes in estimated proved reserve quantities of oil, NGL and natural gas for the years ended December 31, 2023, 2022 and 2021, all of which are located within the U.S.: Oil NGL Natural gas MBOE (1) Proved developed and undeveloped reserves: As of December 31, 2020 67,759 100,922 657,284 278,228 Revisions of previous estimates 4,740 16,952 102,080 38,709 Extensions, discoveries and other additions 10,354 5,269 22,479 19,369 Acquisitions of reserves in place 65,572 19,711 90,023 100,286 Divestitures of reserves in place (15,904) (34,129) (228,546) (88,125) Production (11,619) (8,678) (57,175) (29,827) As of December 31, 2021 120,902 100,047 586,145 318,640 Revisions of previous estimates (9,792) (4,561) (14,694) (16,802) Extensions, discoveries and other additions 21,351 7,162 33,767 34,141 Divestitures of reserves in place (2,165) (808) (3,671) (3,585) Production (13,838) (8,028) (49,259) (30,076) As of December 31, 2022 116,458 93,812 552,288 302,318 Revisions of previous estimates (28,564) (20,823) (55,284) (58,601) Extensions, discoveries and other additions 11,175 10,281 56,329 30,844 Acquisitions of reserves in place 77,609 47,261 244,253 165,578 Production (16,895) (9,128) (55,404) (35,256) As of December 31, 2023 159,783 121,403 742,182 404,883 Proved developed reserves: December 31, 2020 51,751 96,251 633,503 253,586 December 31, 2021 70,727 78,908 494,476 232,048 December 31, 2022 70,333 75,156 464,567 222,917 December 31, 2023 104,993 89,449 555,472 287,021 Proved undeveloped reserves: December 31, 2020 16,008 4,671 23,781 24,642 December 31, 2021 50,175 21,139 91,669 86,592 December 31, 2022 46,125 18,656 87,721 79,401 December 31, 2023 54,790 31,954 186,710 117,862 _____________________________________________________________________________ (1) BOE is calculated using a conversion rate of six Mcf per one Bbl. The following discussion is for the year ended December 31, 2023. The Company's negative revision of 58,601 MBOE of previously estimated quantities consisted of (i) 16,240 MBOE of negative revisions from performance of proved developed producing wells, (ii) 4,470 MBOE of positive revisions from an increase in previously estimated quantities of proved undeveloped locations, (iii) 8,679 MBOE of negative revisions from a decrease in the Realized Prices for oil, NGL and natural gas, (iv) 12,030 MBOE of negative revisions from changes to economic assumptions on proved wells and (v) 26,122 MBOE of negative revisions due to 45 proved undeveloped locations that removed from the development plan. Extensions, discoveries and other additions of 30,844 MBOE consisted of (i) 598 MBOE that resulted from new wells drilled and (ii) 30,246 MBOE that resulted from new horizontal proved undeveloped locations added in the Company's acreage in Howard County, Texas and Western Glasscock Counties, Texas. Acquisitions of reserves in place of 165,578 MBOE consisted of (i) 104,323 MBOE from new proved developed producing wells and (ii) 61,255 MBOE from new proved undeveloped locations. The following discussion is for the year ended December 31, 2022. The Company's negative revision of 16,802 MBOE of previously estimated quantities consisted of (i) 9,531 MBOE of negative revisions from performance of proved developed producing wells, (ii) 1,837 MBOE of negative revisions from a decrease in previously estimated quantities of proved undeveloped locations, (iii) 4,351 MBOE of positive revisions from an increase in the Realized Prices for oil, NGL and natural gas and other changes to proved wells and (iv) 9,785 MBOE of negative revisions due to 16 proved undeveloped locations that were removed from the development plan. Extensions, discoveries and other additions of 34,141 MBOE consisted of (i) 3,850 MBOE that resulted from new wells drilled and (ii) 30,291 MBOE that resulted from new horizontal proved undeveloped locations added in the Company's acreage in Howard and western Glasscock Counties. Sales of reserves of 3,585 MBOE attributed to the divestment of non-operated properties in Howard County. The following discussion is for the year ended December 31, 2021. The Company's positive revision of 38,709 MBOE of previously estimated quantities consisted of (i) 3,622 MBOE of negative revisions from performance of proved developed producing wells, (ii) 2,885 MBOE of negative revisions from a decrease in previously estimated quantities of proved undeveloped locations, (iii) 37,341 MBOE of positive revisions from an increase in the Realized Prices for oil, NGL and natural gas and other changes to proved wells and (iv) 7,875 MBOE of positive revisions due to proved undeveloped locations that were removed from the development plan in prior years. Six of these locations became proved developed producing wells in 2021 and twelve were revised back to proved undeveloped reserves as they became economically producible due to increased commodity prices and increases in lateral lengths. Extensions, discoveries and other additions of 19,369 MBOE consisted of (i) 6,724 MBOE that resulted from new wells drilled and (ii) 12,645 MBOE that resulted from new horizontal proved undeveloped locations added in the Company's acreage in Howard and western Glasscock Counties. Sales of reserves of 88,125 MBOE attributed to the divestment of 37.5% interest of certain proved developed producing wells in Reagan and Glasscock counties. Acquisitions of reserves in place of 100,286 MBOE consisted of (i) 47,310 MBOE from new proved developed wells and (ii) 52,976 MBOE from new proved undeveloped locations in Howard and western Glasscock Counties. Standardized measure of discounted future net cash flows The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil, NGL and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of proved properties and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2023, 2022 and 2021 are based on the Realized Prices, which reflect adjustments to the Benchmark Prices for quality, certain transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the delivery point. All Realized Prices are held flat over the forecast period for all reserve categories in calculating the discounted future net cash flows. Any effect from the Company's commodity hedges is excluded. In accordance with SEC regulations, the proved reserves were anticipated to be economically producible from the "as of date" forward based on existing economic conditions, including prices and costs at which economic producibility from a reservoir was determined. These costs, held flat over the forecast period, include development costs, operating costs, ad valorem and production taxes and abandonment costs after salvage. Future income tax expenses are computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil, NGL and natural gas reserves, less the tax basis of the Company's oil and natural gas properties. The estimated future net cash flows are then discounted at a rate of 10%. No full cost ceiling impairment was recorded for the years ended December 31, 2023, 2022 and 2021. See Note 6 for discussion of the Benchmark Prices and Realized Prices. The following table presents the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Future cash inflows $ 15,570,267 $ 16,343,468 $ 11,846,148 Future production costs (5,543,237) (4,136,380) (3,595,524) Future development costs (1,904,597) (1,403,721) (1,064,527) Future income tax expenses (669,158) (1,587,677) (774,461) Future net cash flows 7,453,275 9,215,690 6,411,636 10% discount for estimated timing of cash flows (3,302,437) (4,461,114) (2,986,324) Standardized measure of discounted future net cash flows $ 4,150,838 $ 4,754,576 $ 3,425,312 It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market value of the Company's proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, prices and costs as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves. The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Standardized measure of discounted future net cash flows, beginning of year $ 4,754,576 $ 3,425,312 $ 1,014,854 Changes in the year resulting from: Sales, less production costs (1,136,735) (1,468,946) (934,440) Revisions of previous quantity estimates (964,416) (99,512) 426,060 Extensions, discoveries and other additions 125,875 667,859 293,511 Net change in prices and production costs (2,560,883) 2,565,963 1,572,662 Changes in estimated future development costs 137,310 (165,579) 134,091 Previously estimated development costs incurred during the period 368,688 260,475 169,376 Acquisitions of reserves in place 2,211,370 — 1,509,087 Divestitures of reserves in place — (96,222) (369,601) Accretion of discount 624,819 371,625 102,607 Net change in income taxes 371,962 (418,537) (279,722) Timing differences and other 218,272 (287,862) (213,173) Standardized measure of discounted future net cash flows, end of year $ 4,150,838 $ 4,754,576 $ 3,425,312 Estimates of economically recoverable oil, NGL and natural gas reserves and of future net cash flows are based upon a number of variable factors and assumptions, all of which are, to some degree, subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil, NGL and natural gas may differ materially from the amounts estimated.

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	$ 695,078	$ 631,512	$ 145,008

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

Basis of presentation and sig_2

Basis of presentation and significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Basis of presentation	The accompanying consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts.
Use of estimates in the preparation of consolidated financial statements	The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ.
Cash and cash equivalents	The Company defines cash and cash equivalents to include cash on hand, cash in bank accounts and highly liquid investments with original maturities of three months or less. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts.
Accounts receivable	The Company sells its produced oil, NGL and natural gas and purchased oil to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company maintains an allowance for expected credit losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers significant factors such as historical losses, current receivables aging, the debtors' current ability to pay its obligation to the Company and existing industry and economic data. Account balances are
Derivatives	Derivatives are recorded at fair value and are presented on a net basis in "Derivatives" on the consolidated balance sheets as assets and/or liabilities. The Company records the fair value of derivatives on a net basis by counterparty where the right of offset exists. The Company determines the fair value of its derivatives using fair value hierarchy level inputs to its valuation techniques. The Company's derivatives were not designated as hedges for accounting purposes, and the Company does not enter into such instruments for speculative trading purposes. Accordingly, the changes in fair value are recognized in " Gain (loss) on derivatives, net
Oil and natural gas properties	The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain employee-related costs, incurred for the purpose of acquiring, exploring for or developing oil and natural gas properties, are capitalized and, once evaluated, depleted on a composite unit-of-production method based on estimates of proved oil, NGL and natural gas reserves. The depletion base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. Capitalized costs include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including employee-related costs, associated with production and general corporate activities are expensed in the period incurred. The Company excludes unevaluated property acquisition costs and exploration costs from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs to its unevaluated properties and such costs become subject to depletion when proved reserves can be assigned to the associated properties. All items classified as unevaluated properties are assessed on a quarterly basis for possible impairment. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling capital investments to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion.
Leases	The Company recognizes operating lease right-of-use assets and operating lease liabilities on the consolidated balance sheets for operating leases with an initial term greater than 12 months. The Company determines whether a contract is or contains a lease at inception of the contract, based on answers to a series of questions that address whether an identified asset exists and whether the Company has the right to obtain substantially all of the benefit of the asset and to control its use over the full term of the agreement. Unless implicitly defined, the Company determines the present value of future lease payments using an estimated incremental borrowing rate. The Company has recognized operating lease right-of-use assets and operating lease liabilities on the consolidated balance sheets for leases of commercial real estate with lease terms extending into 2033 and drilling, completion, production and other equipment leases with lease terms extending into 2026. The Company has various other drilling, completion and production equipment leases on a short-term basis which are reflected in short-term lease costs. The Company's lease costs include those that are recognized in net income (loss) during the period and capitalized as part of the cost of another asset in accordance with other GAAP. The lease costs related to drilling, completion and production activities are reflected at the Company's net ownership, which is consistent with the principals of proportional consolidation, and lease commitments are reflected on a gross basis. Certain of the Company's operating lease right-of-use asset classes include options to renew on a month-to-month basis. The Company considers contract-based, asset-based, market-based and entity-based factors to determine the term over which it is reasonably certain to extend the lease in determining its right-of-use assets and liabilities.
Inventory	The Company has the following types of inventory: (i) materials and supplies inventory used in production activities of oil and natural gas properties and midstream service assets, (ii) frac pit water inventory used in developing oil and natural gas properties and (iii) line-fill in third-party pipelines, which is 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 until the expiration of the transportation contract. All inventory is carried at the lower of cost or net realizable value ("NRV"), with cost determined using the weighted-average cost method, and is included in "Other current assets" and "Other noncurrent assets, net" on the consolidated balance sheets. The NRV for materials and supplies inventory and frac pit water inventory is estimated utilizing a replacement cost approach (Level 2). The NRV for line-fill in third-party pipelines is estimated utilizing a quoted market price adjusted for regional price differentials (Level 2).
Debt issuance costs	Debt issuance costs, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the straight-line method.
Asset retirement obligations	Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is expensed through depletion, or for midstream service assets through depreciation. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and accretion expense. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment or removal and remediation cost per well and related facilities or midstream service asset based on Company experience, if any, in accordance with applicable state laws, (ii) estimated remaining life per well or midstream service asset, (iii) future inflation factors and (iv) the Company's average credit-adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in technology, regulatory, political, environmental, safety and public relations matters. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, an adjustment will be made to the asset balance. The Company is obligated by contractual and regulatory requirements to remove certain midstream service assets and perform other remediation of the sites where such midstream service assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for midstream service assets in the periods in which settlement dates are reasonably determinable.
Fair value measurements	The carrying amounts reported on the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, accrued capital expenditures, undistributed revenue and royalties and other accrued assets and liabilities approximate their fair values. The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation techniques, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on inputs to the valuation techniques as follows: Level 1— Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2— Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Level 3— Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.
Treasury stock	Treasury stock is recorded at cost, which includes incremental direct transaction costs, and is retired upon acquisition as a result of (i) stock exchanged to satisfy tax withholding that arises upon the lapse of restrictions on share-settled equity-based awards at the awardee's election, (ii) stock exchanged for the cost of exercise of stock options at the awardee's election, or (iii) the Company's open market repurchases of its common stock.
Revenue recognition	Oil, NGL and natural gas sales and sales of purchased oil are generally recognized at the point in time that control of the product is transferred to the customer. Oil sales and sales of purchased oil Under its oil sales contracts, the Company sells produced or purchased oil at the delivery point specified in the contract and collects an agreed-upon index price, net of pricing differentials. The delivery point may be at the wellhead, the inlet of the purchaser's pipeline or nominated pipeline or the Company's truck unloading facility. At the delivery point, the purchaser typically takes custody, title and risk of loss of the product and, therefore, control as defined under applicable GAAP, typically passes at the delivery point. The Company recognizes revenue at the net price received when control transfers to the purchaser. The Company engages in transactions in which it sells oil at the lease and subsequently repurchases the same volume of oil from that customer at a downstream delivery point under a separate agreement ("Repurchase Agreement") for use in the sale to the final customer. The commercial reasoning for such transactions may vary. Where a Repurchase Agreement exists, the Company must evaluate whether the customer obtains control of the oil at the lease and therefore whether it is appropriate to recognize revenue for the lease sale. Where the Company has an obligation or a right to repurchase the oil, the customer does not obtain control of the oil because it is limited in its ability to direct the use of, and obtain substantially all of the remaining benefits from the oil even though it may have physical possession of the oil. When the Company repurchases the oil for equal to or more than the original selling price, then the transaction represents a financing arrangement unless there is only a short passage of time between the sale and repurchase, in which case any excess amount paid represents an expense associated with the sale of oil to the final customer. The Company recognizes such repurchase expense and any transportation expenses incurred for the delivery of the oil to the final customer in the "Transportation and marketing expenses" line item in the accompanying consolidated statements of operations. In certain situations, the Company enters into purchase and sale transactions of oil inventory with the same counterparty in contemplation with one another, and these transactions are presented on the consolidated statements of operations on a net basis in accordance with GAAP. The following table presents the net effect of these transactions for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Sales of purchased oil inventory $ 494,860 $ 104,403 $ 327,839 Purchased oil inventory 495,697 104,039 326,625 Net effect on earnings (1) $ (837) $ 364 $ 1,214 ______________________________________________________________________________ (1) Amounts presented are recorded in "Sales of purchased oil" in the consolidated statements of operations. Under certain of its customer contracts, the Company is subject to contractual penalties if it fails to deliver contractual minimum volumes to its customers. Such amounts are recorded as a reduction to the transaction price as these amounts do not represent payments to the customer for distinct goods or services and instead relate specifically to the failure to perform under the specific customer contract. Such amounts are recorded as a reduction to the transaction price when payment is determined as probable, typically when such a deficiency occurs. NGL and natural gas sales Under its natural gas processing contracts, the Company delivers produced natural gas to a midstream processing entity at the wellhead or the inlet of the processing entity's system. The processing entity processes the natural gas, sells the resulting NGL and residue gas to third parties and pays the Company for the NGL and residue gas with deductions that may include gathering, compression, processing and transportation fees. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For contracts where the Company has concluded that it is the agent in the ultimate sale to the third party and the midstream processing entity is the principal and that the Company has transferred control of unprocessed natural gas to the midstream processing entity, the Company recognizes revenue based on the net amount of the proceeds received from the midstream processing entity who represents the Company's customer. For contracts where the Company has concluded that it is the principal with the ultimate third party being the customer, the Company recognizes revenue for those contracts on a gross basis, with gathering, compression, processing, and transportation fees presented as an expense. Significant judgments The Company engages in various types of transactions in which unaffiliated midstream entities process the Company's liquids-rich natural gas and, in some scenarios, subsequently market resulting NGL and residue gas to third-party customers on the Company's behalf. These types of transactions require judgment to determine whether the Company is the principal or the agent in the contract and, as a result, whether revenues are recorded gross or net. For existing contracts, the Company has determined that it serves as the agent in the sale of products under certain natural gas processing and marketing agreements with unaffiliated midstream entities in accordance with the control model under applicable GAAP. As a result, the Company presents revenue on a net basis for amounts expected to be received from third-party customers through the marketing process, with expenses and deductions incurred subsequent to control of the product(s) transferring to the unaffiliated midstream entity being netted against revenue. Transaction price allocated to remaining performance obligations A significant number of the Company's product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient under applicable GAAP that exempts the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company's product sales that have a contract term greater than one year, the Company has utilized the practical expedient under applicable GAAP that states that it is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company's product sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied. Under these contracts each unit of service represents a separate performance obligation and therefore performance obligations in respect of future services are wholly unsatisfied. Contract balances Under the Company's customer contracts, invoicing occurs once the Company's performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company's contracts do not give rise to contract assets or contract liability balances. Prior-period performance obligations
Equity-based compensation awards	Equity-based compensation expense is included in "General and administrative" on the consolidated statements of operations, and includes expense for (i) restricted stock awards, stock option awards and performance share awards, which are accounted for as equity awards and are generally based on the awards' grant date or modification date fair value less an expected forfeiture rate and (ii) performance unit awards and phantom unit awards, which are accounted for as liability awards and are re-measured at each quarterly reporting period until settlement. The Company capitalizes a portion of equity-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and Equity Awards Restricted stock awards and restricted stock unit awards All service vesting restricted stock awards are treated as issued and outstanding in the consolidated financial statements. If the termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to employees vest in a variety of schedules that mainly include (i) 33%, 33% and 34% vesting per year beginning on the first anniversary of the grant date and (ii) full vesting on the third anniversary of the grant date. Non-employee directors are granted restricted stock unit awards which are 100% vested on the date of grant, with the option to defer settlement of some or all of such awards in shares until the director's separation from service if the director timely elects in accordance with the terms of the Nonqualified Director Deferred Compensation Plan. If a director elects to defer settlement of their restricted stock units, we refer to them as deferred stock units or DSUs. Performance share awards Performance share awards, which the Company has determined are equity awards, are subject to a combination of market, performance and service vesting criteria. For portions of awards with market criteria, a Monte Carlo simulation prepared by an independent third party is utilized to determine the grant-date (or modification date) fair value, and the associated expense is recognized on a straight-line basis over the three-year requisite service period of the awards. For portions of awards with performance criteria, the fair value is equal to the Company's closing stock price on the grant date (or modification date), and for each reporting period, the associated expense fluctuates and is adjusted based on an estimated payout of the number of shares of common stock to be delivered on the payment date for the three-year performance period, which begins either at the start of the calendar year in which the award is granted or on December 1 of the year prior to the Calendar year in which the award is granted. For performance share awards granted in 2022, the market criteria consists of: (i) annual relative stockholder return comparing the Company's stockholder return to the stockholder return of the exploration and production companies listed in the Russell 2000 index and (ii) annual absolute total stockholder return, together the "PSU Matrix." The performance criteria for these awards consists of: (i) earnings before interest, taxes, depreciation, amortization and exploration expense ("EBITDAX") and three-year total debt reduction (the "EBITDAX/Total Debt Component") (ii) growth in inventory (the "Inventory Growth Component") and (iii) emissions reduction (the "ESG Component"). Any shares earned are expected to be issued in the first quarter following the completion of the respective requisite service periods based on the achievement of certain market and performance criteria, and the payout can range from 0% to 225%. Equity-based liability awards Performance unit awards Performance unit awards, which the Company has determined are liability awards since they are settled in cash, are subject to a combination of market, performance and service vesting criteria. For portions of awards with market criteria, a Monte Carlo simulation prepared by an independent third party is utilized to determine the fair value, and is re-measured at each reporting period until settlement. For portions of awards with performance criteria, the Company's closing stock price is utilized to determine the fair value and is re-measured on the last trading day of each reporting period until settlement and, additionally, the associated expense fluctuates based on an estimated payout for the three-year performance period. The expense related to the performance unit awards is recognized on a straight-line basis over the three-year requisite service period of the awards, and the life-to-date recognized expense is adjusted accordingly at each reporting period based on the quarterly fair value re-measurements and redetermination of the estimated payout for the performance criteria. For each performance unit award, the three-year performance period begins at the start of the calendar year in which the award is granted. For performance unit awards granted in 2023, the market criteria consists of the PSU Matrix. The performance criteria for these awards consists of: (i) the EBITDAX/Total Debt Component, (ii) the Inventory Growth Component and (iii) the ESG Component. Any units earned are expected to be paid in cash during the first quarter following the completion of the requisite service period, based on the achievement of certain market and performance criteria, and the payout can range from 0% to 250% for the market criteria and 0% to 200% for the performance criteria. For performance unit awards granted in 2021, the market criteria consists of the PSU Matrix. The performance criteria for these awards consists of: (i) the EBITDAX/Total Debt Component and (ii) the Inventory Growth Component. Any units earned are expected to be paid in cash during the first quarter following the completion of the requisite service period, based on the achievement of certain market and performance criteria, and the payout range was 0% to 250% for the market criteria and 0% to 200% for the performance criteria. The performance units granted March 9, 2021 had a performance period of January 1, 2021 to December 31, 2023. Certain of the market and performance criteria were satisfied, resulting in a 146% payout, which will be paid in cash during the first quarter of 2024. For performance unit awards granted in 2020, the market criteria consists of: (i) the RTSR Performance Percentage and (ii) the ATSR Appreciation. The performance criteria for these awards consists of the ROACE Percentage. Potential payout of these awards ranged from 0% to 200%, but was capped at 100% if the ATSR Appreciation was zero or less. In the first quarter of 2023, following the completion of the requisite service period and achievement of certain market and performance criteria, the granted awards were issued at a 151% payout. Phantom unit awards Phantom unit awards, which the Company has determined are liability awards, represent the holder's right to receive the cash equivalent of one share of common stock of the Company for each phantom unit as of the applicable vesting date, subject to withholding requirements. Phantom unit awards granted to employees vest 33%, 33% and 34% per year beginning on the first anniversary of the grant date.
Income taxes	Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carryforwards. Under this method, 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 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 or loss in the period that includes the enactment date.
Recently issued or adopted accounting pronouncements	The Company considered the applicability and impact of all accounting standard updates ("ASU") issued by the Financial Accounting Standards Board ("FASB") to the Accounting Standards Codification. The Company did not adopt any new ASUs during the year ended December 31, 2023. In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which sets forth improvements to the current segment disclosure requirements in accordance with Topic 280 "Segment Reporting," including clarifying that entities with a single reportable segment are subject to both new and existing segment reporting requirements. ASU 2023-07 will be effective retrospectively for fiscal years beginning after December 15, 2023 and interim periods beginning after December 15, 2024. Early adoption is permitted. Adoption of this ASU will result in additional disclosure, but will not impact the Company’s consolidated financial position, results of operations or cash flows.

Basis of presentation and sig_3

Basis of presentation and significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Schedule of components of accounts receivable	Accounts receivable consisted of the following components as of the dates presented: (in thousands) December 31, 2023 December 31, 2022 Oil, NGL and natural gas sales (1) $ 173,917 $ 111,260 Joint operations, net 60,397 35,801 Other 4,459 16,308 Total accounts receivable, net $ 238,773 $ 163,369 _____________________________________________________________________________ (1) For purchasers that the Company has netting arrangements with, the amounts presented include the net positions.
Schedule of components of other current assets	Other current assets consisted of the following components as of the dates presented: (in thousands) December 31, 2023 December 31, 2022 Prepaid expenses and other $ 5,026 $ 7,247 Inventory 13,723 6,070 Total other current assets $ 18,749 $ 13,317
Schedule of components of other current liabilities	Other current liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2023 December 31, 2022 Accrued interest payable $ 52,837 $ 43,984 Accrued compensation and benefits 19,547 20,000 Other liabilities 6,418 18,966 Total other current liabilities $ 78,802 $ 82,950
Schedule of asset retirement obligation liability	The following table presents changes to the Company's asset retirement obligations liability for the periods presented: Years ended December 31, (in thousands) 2023 2022 Liability at beginning of year $ 74,081 $ 72,003 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 7,648 362 Accretion expense (1) 3,703 3,879 Liabilities settled due to plugging and abandonment or removed due to sale (1,108) (2,163) Liability at end of year 84,324 74,081 Less: current asset retirement obligations (2) 2,644 3,715 Non-current asset retirement obligations $ 81,680 $ 70,366 ______________________________________________________________________________ (1) Accretion expense is included in "Other operating expenses, net" on the consolidated statements of operations. (2) Current asset retirement obligations is included in "Other current liabilities" on the consolidated balance sheets.
Schedule of principal transactions revenue	The following table presents the net effect of these transactions for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Sales of purchased oil inventory $ 494,860 $ 104,403 $ 327,839 Purchased oil inventory 495,697 104,039 326,625 Net effect on earnings (1) $ (837) $ 364 $ 1,214 ______________________________________________________________________________ (1) Amounts presented are recorded in "Sales of purchased oil" in the consolidated statements of operations.
Schedule of non-cash investing and supplemental cash flow information	The following table presents supplemental cash flow and non-cash information for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Supplemental cash flow information: Cash paid for interest, net of $2,892, $3,872 and $5,866 of capitalized interest, respectively (1) $ 132,986 $ 131,867 $ 94,867 Supplemental non-cash operating information: Right-of-use assets obtained in exchange for operating lease liabilities (2) $ 176,027 $ 34,532 $ 7,742 Supplemental non-cash investing information: Fair value of contingent consideration asset on transaction closing date (3) $ — $ — $ 33,832 Change in accrued capital expenditures $ 43,559 $ (2,207) $ 22,310 Equity issued for acquisition of oil and natural gas properties (4) $ 807,767 $ — $ 310,888 Liabilities assumed in acquisitions of oil and natural gas properties (4) $ 86,478 $ — $ 11,653 Capitalized asset retirement cost $ 7,648 $ 362 $ 14,610 ______________________________________________________________________________ (1) See Note 7 for additional discussion of the Company's interest expense. (2) See Note 5 for additional discussion of the Company's leases. (3) See Note 4 for additional discussion of the Company's divestiture of oil and natural gas properties that includes contingent consideration. See Note 12 for discussion of the quarterly remeasurement of the contingent consideration. (4) See Notes 4 and 8 for additional discussion of the Company's acquisitions of oil and natural gas properties and equity issued in connection with such acquisitions, respectively.

Acquisitions and divestitures (

Acquisitions and divestitures (Tables)	12 Months Ended
	Dec. 31, 2023
Business Combination and Asset Acquisition [Abstract]
Schedule of purchase price consideration	The following table presents components of the consideration paid in the Henry Acquisition, which is inclusive of customary closing adjustments and subject to post-closing adjustments: (in thousands, except for share and share price data) As of November 5, 2023 Shares of Company common stock issued 2,145,725 Company common stock price on Henry Closing Date $ 52.25 Fair value of Company common stock issued $ 112,114 Shares of Company preferred stock issued 6,131,381 Company preferred stock price on Henry Closing Date $ 52.25 Fair value of Company preferred stock issued (before dividends) $ 320,365 Fair value of preferred stock dividends 446 Fair value of Company preferred stock issued $ 320,811 Cash consideration for working capital closing adjustments 1,154 Total consideration $ 434,079
Schedule of assets acquired and liabilities assumed	The following table presents the preliminary purchase price allocation of the Henry Acquisition to the assets acquired and liabilities assumed, based on their fair values on the Henry Closing Date: (in thousands) As of November 5, 2023 Fair value of assets acquired: Oil and natural gas properties: Evaluated properties $ 381,739 Unevaluated properties (1) 69,541 Operating lease right-of-use assets 3,366 Fair value of liabilities assumed: Asset retirement obligations (1,155) Operating lease liabilities (3,366) Revenue suspense liabilities (16,046) Total purchase price $ 434,079 ______________________________________________________________________________ (1) As of December 31, 2023, $27.3 million remained in unevaluated properties.
Schedule of business acquisition, pro forma information	The below information reflects pro forma adjustments for the issuance of the Company's common stock and preferred stock as consideration for the Henry Acquisition, as well as pro forma adjustments based on available information and certain assumptions the Company believes are reasonable, including adjustments to depreciation, depletion and amortization based on the full cost method of accounting and estimated impacts of the pro forma adjustments to income tax and valuation allowance. Years ended December 31, (in thousands) 2023 2022 Total revenues $ 1,701,019 $ 2,206,570 Operating income $ 632,666 $ 1,225,218 Net income $ 716,775 $ 791,740 Net income available to common shareholders $ 710,560 $ 785,001 Net income per common share: Basic $ 31.72 $ 41.72 Diluted $ 25.51 $ 31.49

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Schedule of lease costs, supplemental cash flow information, lease terms and discount rates	The following table presents components of total lease costs, net for the periods presented: Years ended December 31, (in thousands) 2023 2022 Operating lease costs (1) $ 71,706 $ 24,174 Short-term lease costs (2) 56,685 110,442 Variable lease costs (3) 97,383 11,328 Sublease income (1,198) (990) Total lease costs, net $ 224,576 $ 144,954 _____________________________________________________________________________ (1) Amounts represent straight-line costs associated with the Company's operating lease right-of-use assets. (2) Amounts include costs associated with the Company's short-term leases that are not included in the calculation of lease liabilities and right-of-use assets and, therefore, are not recorded on the consolidated balance sheets as such. (3) Amounts are primarily comprised of the non-lease service component of drilling rig and completions commitments above the minimum required payments, and are not included in the calculation of lease liabilities and right-of-use assets. Both the minimum required payments and the non-lease service component of the drilling rig and completions commitments are capitalized as additions to oil and natural gas properties. The following table presents cash paid for amounts included in the measurement of operating lease liabilities, which may not agree to operating lease costs due to timing of cash payments and incurred capital expenditures for the periods presented: Years ended December 31, (in thousands) 2023 2022 Operating cash flows from operating leases $ 4,595 $ 3,892 Investing cash flows from operating leases (1) $ 65,305 $ 20,398 _____________________________________________________________________________ (1) Amounts associated with drilling and completions operations are capitalized as additions to oil and natural gas properties. The following table presents the weighted-average remaining lease term and weighted-average discount rate for operating leases as of the dates presented: December 31, 2023 December 31, 2022 Weighted-average remaining lease term 2.54 years 1.91 years Weighted-average discount rate 8.26 % 5.84 %
Schedule of maturities of operating lease liabilities	The following table reconciles the undiscounted cash flows for recognized operating lease liabilities for each of the first five years and the total remaining years to the operating lease liabilities recorded on the consolidated balance sheet as of the date presented: (in thousands) December 31, 2023 2024 $ 79,663 2025 61,157 2026 3,905 2027 2,788 2028 2,153 Thereafter 10,466 Total minimum lease payments 160,132 Less: imputed interest (18,138) Present value of future minimum lease payments $ 141,994

Property and equipment (Tables)

Property and equipment (Tables)	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Schedule of employee-related costs capitalized to oil and natural gas properties	The following table presents capitalized employee-related incurred capital expenditures in the acquisition, exploration and development of oil and natural gas properties for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Capitalized employee-related costs $ 22,179 $ 17,026 $ 18,255
Schedule of property and equipment	The following table presents depletion expense, which is included in "Depletion, depreciation and amortization" on the consolidated statements of operations, and depletion expense per BOE sold of evaluated oil and natural gas properties for the periods presented: Years ended December 31, (in thousands except per BOE data) 2023 2022 2021 Depletion expense of evaluated oil and natural gas properties $ 446,611 $ 298,259 $ 201,691 Depletion expense per BOE sold $ 12.67 $ 9.92 $ 6.76 Midstream and other fixed assets consisted of the following components as of the dates presented: (in thousands) December 31, 2023 December 31, 2022 Midstream service assets $ 158,749 $ 151,157 Computer hardware and software 29,007 21,758 Vehicles 5,046 7,934 Leasehold improvements 7,136 7,136 Buildings 7,039 7,039 Other 7,710 6,087 Depreciable total 214,687 201,111 Less accumulated depreciation, amortization and impairment (107,541) (96,383) Depreciable total, net $ 107,146 $ 104,728 Land 23,147 23,075 Total midstream and other fixed assets, net $ 130,293 $ 127,803
Schedule of Benchmark Prices and Realized Prices used in the full cost ceiling calculation	The following table presents the Benchmark Prices and the Realized Prices as of the dates presented: December 31, 2023 December 31, 2022 December 31, 2021 Benchmark Prices: Oil ($/Bbl) $ 78.22 $ 90.15 $ 63.04 NGL ($/Bbl) (1)(2) $ 78.22 $ 41.77 $ 34.51 Natural gas ($/MMBtu) $ 2.64 $ 5.20 $ 3.35 Realized Prices: Oil ($/Bbl) $ 79.52 $ 96.21 $ 66.37 NGL ($/Bbl) $ 16.46 $ 29.84 $ 22.90 Natural gas ($/Mcf) $ 1.17 $ 4.24 $ 2.61 _____________________________________________________________________________ (1) Based on the Company's average composite NGL barrel. (2) During 2023, the Company began utilizing WTI NYMEX in the calculation of its NGL Benchmark Prices.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Schedule of net presentation of the Company's long-term debt and debt issuance cost	The following table presents the Company's long-term debt and debt issuance costs, net included in "Long-term debt, net" on the consolidated balance sheets as of the dates presented: (in thousands) December 31, 2023 December 31, 2022 January 2025 Notes — 455,628 January 2028 Notes 700,309 300,309 July 2029 Notes 298,214 298,214 September 2030 Notes 500,000 — Senior Secured Credit Facility (1) 135,000 70,000 Total long-term debt 1,633,523 $ 1,124,151 Unamortized debt issuance costs (21,800) (11,128) Unamortized discounts (6,068) — Unamortized premiums 3,769 — Total long-term debt, net $ 1,609,424 $ 1,113,023 _____________________________________________________________________________ (1) Unamortized debt issuance costs related to the Senior Secured Credit Facility of $14.1 million and $7.3 million as of December 31, 2023 and 2022, respectively, are included in "Other noncurrent assets, net" on the consolidated balance sheets.
Schedule of Extinguishment of Debt	The following table presents the Company's repurchases of its senior unsecured notes under authorized bond purchase programs and the related gain or loss on extinguishment of debt during the period presented: (in thousands) Year ended January 2025 Notes $ 122,285 January 2028 Notes 60,735 July 2029 Notes 101,786 Total principal amount repurchased $ 284,806 Less: Consideration paid $ 282,902 Write off of debt issuance costs 3,363 Loss on extinguishment of debt, net (1) $ (1,459) _____________________________________________________________________________ (1)
Schedule of amounts incurred and charged to interest expenses	The following table presents amounts that have been incurred and charged to interest expense: Years ended December 31, (in thousands) 2023 2022 2021 Interest expense on borrowings $ 144,731 $ 123,255 $ 114,800 Amortization of debt issuance costs and other adjustments 7,980 5,738 4,451 Less capitalized interest 2,892 3,872 5,866 Total interest expense $ 149,819 $ 125,121 $ 113,385

Stockholders' equity (Tables)

Stockholders' equity (Tables)	12 Months Ended
	Dec. 31, 2023
Equity [Abstract]
Schedule of equity issued for acquisitions of oil and natural gas properties	During the year ended December 31, 2023, the Company issued shares of its common stock and Preferred Stock in connection with the closing of various acquisitions of oil and gas properties, as shown in the table below. Acquisition Closing date Common stock issued (1) Preferred stock issued (2) Grey Rock 12/21/2023 627,026 595,104 Tall City 11/6/2023 1,402,258 N/A Henry 11/5/2023 2,145,725 6,131,381 Maple 10/31/2023 3,370,497 N/A Driftwood 4/3/2023 1,578,948 N/A _____________________________________________________________________________ (1) As of December 31, 2023, 773,290 of the common shares issued for the Tall City Acquisition and 357,500 of the common shares issued for the Maple Acquisition remain in escrow pending post-close settlements. (2) On November 29, 2023, the Preferred Stock issued in connection with the Henry Acquisition were converted to common shares. See "Preferred Stock" below for additional discussion.
Schedule of share repurchases program	The following table presents the Company's open market repurchases of its common stock during the periods presented: (in thousands, except for share and share price data) Year ended Shares of Company common stock repurchased 490,536 Average share price (1) $ 76.02 Total $ 37,290 ______________________________________________________________________________ (1) Average share price includes any commissions paid to repurchase stock.

Compensation plans (Tables)

Compensation plans (Tables)	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Schedule of activity for equity compensation awards	The following table presents activity for equity compensation awards for the year ended December 31, 2023: (in thousands) Restricted Stock Awards Weighted-average grant-date fair value (per share) Stock Option Awards Weighted-average exercise price (per share) Performance Share Awards Weighted-average grant-date fair value (per share) Outstanding as of December 31, 2022 362 $52.90 3 $235.08 48 $89.76 Granted 340 $54.68 — — Forfeited (47) $57.39 — — Vested (1) (183) $44.86 — — Expired or canceled — (1) $346.80 — Outstanding as of December 31, 2023 (2) 472 $56.87 2 $136.83 48 $101.48 _____________________________________________________________________________ (1) The aggregate intrinsic value of vested restricted stock awards for the year ended December 31, 2023 was $9.3 million. (2) The vested and exercisable stock option awards as of December 31, 2023 had no intrinsic value.
Schedule of equity-based liability awards	The following table presents activity for equity-based liability awards for the year ended December 31, 2023: (in thousands) Performance Unit Awards Phantom Unit Awards Outstanding as of December 31, 2022 150 18 Granted 75 — Forfeited — — Vested (1)(2) (67) (16) Outstanding as of December 31, 2023 158 2 _____________________________________________________________________________ (1) The performance unit awards granted on March 5, 2020 had a performance period of January 1, 2020 to December 31, 2022 and, as their market and performance criteria were satisfied, resulted in a 151% payout, or 101,368 units. As such, the granted awards vested and were paid out in cash on March 3, 2023 at $57.06 based on the Company's closing stock price on the vesting date. (2)
Schedule of valuation assumptions for fair value of performance share and unit awards	The following table presents (i) the assumptions used to estimate the fair values per performance share or unit and (ii) the expense per performance share or unit, which is the fair value per performance share or unit adjusted for the estimated payout of the performance criteria, for the outstanding performance share and unit awards as of December 31, 2023 for the grant dates presented: Performance Share Awards Performance February 22, 2022 February 15, 2023 Remaining performance period on grant date 2.86 years n/a Remaining performance period n/a 2 years Risk-free interest rate (1) 1.71 % 4.13 % Dividend yield — % — % Expected volatility (2) 119.25 % 66.40 % Expense per performance share or unit as of December 31, 2023 $101.48 $45.17 ______________________________________________________________________________ (1) The remaining performance period matched zero-coupon risk-free interest rate was derived from the U.S. Treasury constant maturities yield curve on the grant date for each respective award. (2) The Company utilized its own remaining performance period matched historical volatility in order to develop the expected volatility.
Schedule of stock-based compensation expense	The following table reflects equity-based compensation expense for the years presented: Years ended December 31, (in thousands) 2023 2022 2021 Equity awards: Restricted stock awards $ 12,114 $ 8,596 $ 7,594 Performance share awards 1,855 1,590 1,657 Stock option awards — — 7 Total share-settled equity-based compensation, gross $ 13,969 $ 10,186 $ 9,258 Less amounts capitalized (2,975) (1,783) (1,583) Total share-settled equity-based compensation, net $ 10,994 $ 8,403 $ 7,675 Liability awards: Performance unit awards $ 2,932 $ 741 $ 7,480 Phantom unit awards 270 1,186 1,238 Total cash-settled equity-based compensation, gross $ 3,202 $ 1,927 $ 8,718 Less amounts capitalized (50) (272) (365) Total cash-settled equity-based compensation, net $ 3,152 $ 1,655 $ 8,353 Total equity-based compensation, net $ 14,146 $ 10,058 $ 16,028

Net income per common share (Ta

Net income per common share (Tables)	12 Months Ended
	Dec. 31, 2023
Earnings Per Share [Abstract]
Schedule of calculation of basic and diluted weighted average shares outstanding and net income per share	The following table reflects the calculations of basic and diluted (i) weighted-average common shares outstanding and (ii) net income per common share for the periods presented: Years ended December 31, (in thousands, except for per share data) 2023 2022 2021 Net income $ 695,078 $ 631,512 $ 145,008 Less: Preferred stock dividends 449 — — Net income available to common stockholders $ 694,629 $ 631,512 $ 145,008 Weighted-average common shares outstanding: Basic 20,254 16,672 14,240 Dilutive non-vested restricted stock awards 106 183 181 Dilutive non-vested performance share awards (1) 2 12 43 Dilutive preferred stock 421 — — Diluted 20,783 16,867 14,464 Net income per common share: Basic $ 34.30 $ 37.88 $ 10.18 Diluted $ 33.44 $ 37.44 $ 10.03 _____________________________________________________________________________ (1) The dilutive effect of the non-vested performance shares for the year ended December 31, 2023 was calculated as of the end of the performance period on December 31, 2023.

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of gain (loss) on derivatives	The following table summarizes components the Company's gain (loss) on derivatives, net by type of derivative instrument for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Commodity $ 89,951 $ (291,973) $ (453,784) Contingent consideration 6,279 (6,764) 1,639 Interest rate — 14 (30) Gain (loss) on derivatives, net $ 96,230 $ (298,723) $ (452,175)
Schedule of open positions and derivatives in place	The following table summarizes open commodity derivative positions as of December 31, 2023, for commodity derivatives that were entered into through December 31, 2023, for the settlement periods presented: Year 2024 Year 2025 Oil: WTI NYMEX - Swaps: Volume (Bbl) 18,835,950 3,445,000 Weighted-average price ($/Bbl) $ 75.37 $ 75.52 WTI NYMEX - Three-way Collars: Volume (Bbl) 217,350 — Weighted-average sold put price ($/Bbl) $ 50.00 $ — Weighted-average floor price ($/Bbl) $ 66.51 $ — Weighted-average ceiling price ($/Bbl) $ 87.09 $ — Argus WTI Midland to Argus WTI Formula Basis - Basis Swaps: Volume (Bbl) 293,300 — Weighted-average differential ($/Bbl) $ 0.11 $ — Natural gas: Henry Hub NYMEX - Swaps: Volume (MMBtu) 26,075,700 — Weighted-average price ($/MMBtu) $ 3.47 $ — Henry Hub NYMEX - Collars: Volume (MMBtu) 776,292 — Weighted-average floor price ($/MMBtu) $ 3.40 $ — Weighted-average ceiling price ($/MMBtu) $ 6.11 $ — Waha Inside FERC to Henry Hub NYMEX - Basis Swaps: Volume (MMBtu) 26,851,992 — Weighted-average differential ($/MMBtu) $ (0.74) $ —

Fair value measurements (Tables

Fair value measurements (Tables)	12 Months Ended
	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Schedule of fair value hierarchy for assets and liabilities measured at fair value on a recurring basis	The following tables present the Company's derivatives by (i) balance sheet classification, (ii) derivative type and (iii) fair value hierarchy level, and provide a total, on a gross basis and a net basis reflected in "Derivatives" on the consolidated balance sheets as of the dates presented: December 31, 2023 (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets Assets: Current: Commodity $ — $ 106,067 $ — $ 106,067 $ (9,032) $ 97,035 Contingent consideration — — 2,301 2,301 — 2,301 Noncurrent: Commodity — 22,266 — 22,266 — 22,266 Contingent consideration — — 28,805 28,805 — 28,805 Liabilities: Current: Commodity — (9,032) — (9,032) 9,032 — Net derivative asset positions $ — $ 119,301 $ 31,106 $ 150,407 $ — $ 150,407 December 31, 2022 (in thousands) Level 1 Level 2 Level 3 Total gross fair value Amounts offset Net fair value presented on the consolidated balance sheets Assets: Current: Commodity $ — $ 35,586 $ — $ 35,586 $ (13,193) $ 22,393 Contingent consideration — — 2,277 2,277 — 2,277 Noncurrent: Contingent consideration — — 24,363 24,363 — 24,363 Liabilities: Current: Commodity — (19,153) — (19,153) 13,193 (5,960) Net derivative asset positions $ — $ 16,433 $ 26,640 $ 43,073 $ — $ 43,073
Schedule of changes in assets classified as Level 3 measurements	The following table summarizes the changes in contingent consideration derivatives classified as Level 3 measurements for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Balance of Level 3 at beginning of year $ 26,640 $ 35,861 $ — Sixth Street Contingent Consideration valuation as of Sixth Street Closing Date — — 33,832 Change in Sixth Street Contingent Consideration fair value 6,279 (6,764) 2,029 Settlements realized (1) (1,813) (2,457) — Balance of Level 3 at end of year $ 31,106 $ 26,640 $ 35,861 _____________________________________________________________________________ (1) For the years ended December 31, 2023 and 2022, the settlements included in "Settlements received for contingent consideration" in cash flows from investing activities on the consolidated statements of cash flows.
Schedule of carrying amounts and fair values of debt	The following table presents the carrying amounts and fair values of the Company's debt as of the dates presented: December 31, 2023 December 31, 2022 (in thousands) Long-term debt Fair value (1) Long-term debt Fair value (1) January 2025 Notes $ — $ — $ 455,628 $ 449,122 January 2028 Notes 700,309 719,617 300,309 292,846 July 2029 Notes 298,214 285,099 298,214 268,416 September 2030 Notes 500,000 518,875 — — Senior Secured Credit Facility 135,000 135,095 70,000 69,945 Total $ 1,633,523 $ 1,658,686 $ 1,124,151 $ 1,080,329 _____________________________________________________________________________ (1) The fair values of the outstanding notes were determined using the Level 2 fair value hierarchy quoted market prices for each respective instrument as of December 31, 2023 and 2022. The fair values of the outstanding debt under the Senior Secured Credit Facility were estimated utilizing the Level 2 fair value hierarchy pricing model for similar instruments as of December 31, 2023 and 2022.

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Schedule of income tax (expense) benefit	The following table presents the "Current" and "Deferred" income tax benefit (expense) reported on the consolidated statements of operations for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Current income tax benefit (expense): Federal $ — $ — $ — State (5,723) (6,121) (1,324) Deferred income tax benefit (expense): Federal 190,341 — — State (1,281) 619 (2,321) Total income tax benefit (expense): $ 183,337 $ (5,502) $ (3,645)
Schedule of reconciliation of income tax (expense) benefit computed by applying the federal income tax rate of 34% to pre-tax income from operations	Total income tax benefit (expense) differed from amounts computed by applying the applicable federal income tax rate of 21% for the years ended December 31, 2023, 2022 and 2021 to pre-tax earnings as a result of the following: Years ended December 31, (in thousands) 2023 2022 2021 Income tax expense computed by applying the statutory rate $ (107,466) $ (133,773) $ (31,217) Change in deferred tax valuation allowance 297,658 144,480 45,717 Non-deductible equity-based compensation — (19,301) (13,640) State income tax and change in valuation allowance (5,803) 8,058 (3,274) Other items (1,052) (4,966) (1,231) Total income tax benefit (expense) $ 183,337 $ (5,502) $ (3,645)
Schedule of net deferred tax assets (liabilities)	The following table presents significant components of the Company's net deferred tax asset and liability as of the dates presented: (in thousands) December 31, 2023 December 31, 2022 Deferred tax assets: Net operating loss carryforwards $ 264,114 $ 307,357 Equity-based compensation 232 2,933 Interest expense limitation 3,908 — Other 4,117 1,110 Total deferred tax asset 272,371 311,400 Valuation allowance (20,145) (298,184) Deferred tax assets, net of valuation allowance 252,226 13,216 Deferred tax liabilities: Oil and natural gas properties, midstream service assets and other fixed assets (36,524) (11,105) Derivatives (25,353) (2,331) Other (1,513) — Total deferred tax liabilities (63,390) (13,436) Total net deferred tax asset (liability) (1) $ 188,836 $ (220) ___________________________________________________________________________ (1)

Credit risk (Tables)

Credit risk (Tables)	12 Months Ended
	Dec. 31, 2023
Risks and Uncertainties [Abstract]
Schedule of concentration of risk	The following table presents purchasers that individually accounted for 10% or more of the Company's oil, NGL and natural gas sales in at least one of the years presented: Years ended December 31, 2023 2022 2021 Purchaser A (1) 32 % 33 % 29 % Purchaser B 21 % n/a (2) n/a (2) Purchaser C 12 % n/a (2) n/a (2) Purchaser D (1) n/a (2) 18 % 14 % Purchaser E n/a (2) 17 % 24 % Purchaser F (1) n/a (2) n/a (2) 17 % _____________________________________________________________________________ (1) This purchaser of the Company's oil, NGL and natural gas sales is also a purchaser of the Company's sales of purchased oil included in the table below. (2) This purchaser did not account for 10% or greater of the Company's oil, NGL and natural gas sales. The following table presents purchasers that individually accounted for 10% or more of the Company's sales of purchased oil for the year ended December 31, 2021: Year ended December 31, 2021 Purchaser A (1) 47 % Purchaser B (1) 31 % Purchaser C (1) 22 % _____________________________________________________________________________ (1) This purchaser of the Company's sales of purchased oil is also a purchaser of the Company's oil, NGL and natural gas sales included in the table above.

Related parties (Tables)

Related parties (Tables)	12 Months Ended
	Dec. 31, 2023
Related Party Transactions [Abstract]
Schedule of oil and gas related party transactions	The following table presents the capital expenditures for oil and natural gas properties paid to Halliburton included in the consolidated statements of cash flows for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Capital expenditures for oil and natural gas properties $ 113,291 $ 103,152 $ 69,670

Organizational restructurings (

Organizational restructurings (Tables)	12 Months Ended
	Dec. 31, 2023
Restructuring and Related Activities [Abstract]
Schedule of gross equity-based compensation expense reversals in connection with the Company's respective organizational restructurings	In connection with each of these organizational restructurings, the Company incurred one-time charges comprised of compensation, tax, professional, outplacement and insurance-related expenses, which are recorded as "Organizational restructuring expenses" on the consolidated statements of operations. The following table reflects the aggregate of gross equity-based compensation expense reversals in connection with the Company's respective organizational restructurings, which are included in "General and administrative" on the consolidated statements of operations, for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Gross equity-based compensation expense reversals $ (283) $ (4,908) $ (1,088)

Supplemental oil, NGL and nat_2

Supplemental oil, NGL and natural gas disclosures (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2023
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of incurred capital expenditures in the acquisition, exploration and development of oil and natural gas assets	The following table presents costs incurred in the acquisition, exploration and development of oil and natural gas properties, with asset retirement obligations included in evaluated property acquisition costs and development costs, for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Property acquisition costs: Evaluated $ 1,328,571 $ 8,295 $ 899,128 Unevaluated 401,533 3,470 198,770 Exploration costs 29,612 26,384 33,482 Development costs 633,413 540,447 410,855 Total oil and natural gas properties costs incurred $ 2,393,129 $ 578,596 $ 1,542,235
Schedule of aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depletion, depreciation and impairment	The following table presents the aggregate capitalized costs related to oil, NGL and natural gas production activities with applicable accumulated depletion and impairment as of the dates presented: (in thousands) December 31, 2023 December 31, 2022 Gross capitalized costs: Evaluated properties $ 11,799,155 $ 9,554,706 Unevaluated properties not being depleted 195,457 46,430 Total gross capitalized costs 11,994,612 9,601,136 Less accumulated depletion and impairment (7,764,697) (7,318,399) Net capitalized costs $ 4,229,915 $ 2,282,737
Schedule of oil and natural gas property costs not being amortized by year	The following table presents a summary of the unevaluated property costs not being depleted as of December 31, 2023, by year in which such costs were incurred: (in thousands) 2023 2022 2021 2020 and prior Total Unevaluated properties not being depleted $ 167,192 $ 3,124 $ 24,618 $ 523 $ 195,457
Schedule of results of oil and natural gas producing activities (excluding corporate overhead and interest costs)	The following table presents the results of operations of oil, NGL and natural gas producing activities (excluding corporate overhead and interest costs) for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Revenues: Oil, NGL and natural gas sales $ 1,528,633 $ 1,794,374 $ 1,147,143 Production costs: Lease operating expenses 261,129 173,983 101,994 Production and ad valorem taxes 93,224 110,997 68,742 Oil transportation and marketing expenses 41,284 53,692 47,916 Gas gathering, processing and transportation expenses 2,013 — — Total production costs 397,650 338,672 218,652 Other costs: Depletion 446,611 298,259 201,691 Accretion of asset retirement obligation 3,518 3,653 4,018 Income tax expense (1) 149,788 11,538 14,456 Total other costs 599,917 313,450 220,165 Results of operations $ 531,066 $ 1,142,252 $ 708,326 _____________________________________________________________________________ (1)
Schedule of analysis of change in estimated quantities of oil and natural gas reserves located within United States	The following tables provide an analysis of the changes in estimated proved reserve quantities of oil, NGL and natural gas for the years ended December 31, 2023, 2022 and 2021, all of which are located within the U.S.: Oil NGL Natural gas MBOE (1) Proved developed and undeveloped reserves: As of December 31, 2020 67,759 100,922 657,284 278,228 Revisions of previous estimates 4,740 16,952 102,080 38,709 Extensions, discoveries and other additions 10,354 5,269 22,479 19,369 Acquisitions of reserves in place 65,572 19,711 90,023 100,286 Divestitures of reserves in place (15,904) (34,129) (228,546) (88,125) Production (11,619) (8,678) (57,175) (29,827) As of December 31, 2021 120,902 100,047 586,145 318,640 Revisions of previous estimates (9,792) (4,561) (14,694) (16,802) Extensions, discoveries and other additions 21,351 7,162 33,767 34,141 Divestitures of reserves in place (2,165) (808) (3,671) (3,585) Production (13,838) (8,028) (49,259) (30,076) As of December 31, 2022 116,458 93,812 552,288 302,318 Revisions of previous estimates (28,564) (20,823) (55,284) (58,601) Extensions, discoveries and other additions 11,175 10,281 56,329 30,844 Acquisitions of reserves in place 77,609 47,261 244,253 165,578 Production (16,895) (9,128) (55,404) (35,256) As of December 31, 2023 159,783 121,403 742,182 404,883 Proved developed reserves: December 31, 2020 51,751 96,251 633,503 253,586 December 31, 2021 70,727 78,908 494,476 232,048 December 31, 2022 70,333 75,156 464,567 222,917 December 31, 2023 104,993 89,449 555,472 287,021 Proved undeveloped reserves: December 31, 2020 16,008 4,671 23,781 24,642 December 31, 2021 50,175 21,139 91,669 86,592 December 31, 2022 46,125 18,656 87,721 79,401 December 31, 2023 54,790 31,954 186,710 117,862 _____________________________________________________________________________ (1) BOE is calculated using a conversion rate of six Mcf per one Bbl.
Schedule of standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	The following table presents the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Future cash inflows $ 15,570,267 $ 16,343,468 $ 11,846,148 Future production costs (5,543,237) (4,136,380) (3,595,524) Future development costs (1,904,597) (1,403,721) (1,064,527) Future income tax expenses (669,158) (1,587,677) (774,461) Future net cash flows 7,453,275 9,215,690 6,411,636 10% discount for estimated timing of cash flows (3,302,437) (4,461,114) (2,986,324) Standardized measure of discounted future net cash flows $ 4,150,838 $ 4,754,576 $ 3,425,312
Schedule of changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	The following table presents the changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves for the periods presented: Years ended December 31, (in thousands) 2023 2022 2021 Standardized measure of discounted future net cash flows, beginning of year $ 4,754,576 $ 3,425,312 $ 1,014,854 Changes in the year resulting from: Sales, less production costs (1,136,735) (1,468,946) (934,440) Revisions of previous quantity estimates (964,416) (99,512) 426,060 Extensions, discoveries and other additions 125,875 667,859 293,511 Net change in prices and production costs (2,560,883) 2,565,963 1,572,662 Changes in estimated future development costs 137,310 (165,579) 134,091 Previously estimated development costs incurred during the period 368,688 260,475 169,376 Acquisitions of reserves in place 2,211,370 — 1,509,087 Divestitures of reserves in place — (96,222) (369,601) Accretion of discount 624,819 371,625 102,607 Net change in income taxes 371,962 (418,537) (279,722) Timing differences and other 218,272 (287,862) (213,173) Standardized measure of discounted future net cash flows, end of year $ 4,150,838 $ 4,754,576 $ 3,425,312

Organization (Details)

Organization (Details)	12 Months Ended
	Dec. 31, 2023 operating_segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating segments	1

Basis of presentation and sig_4

Basis of presentation and significant accounting policies - Accounts receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Accounts receivable
Oil, NGL and natural gas sales	$ 173,917	$ 111,260
Joint operations, net	60,397	35,801
Other	4,459	16,308
Total accounts receivable, net	$ 238,773	$ 163,369

Basis of presentation and sig_5

Basis of presentation and significant accounting policies - Other current assets (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Accounting Policies [Abstract]
Prepaid expenses and other	$ 5,026	$ 7,247
Inventory	13,723	6,070
Total other current assets	$ 18,749	$ 13,317

Basis of presentation and sig_6

Basis of presentation and significant accounting policies - Other current liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Accounting Policies [Abstract]
Accrued interest payable	$ 52,837	$ 43,984
Accrued compensation and benefits	19,547	20,000
Other liabilities	6,418	18,966
Total other current liabilities	$ 78,802	$ 82,950

Basis of presentation and sig_7

Basis of presentation and significant accounting policies - Asset retirement obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at beginning of year	$ 74,081	$ 72,003
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	7,648	362
Accretion expense	3,703	3,879
Liabilities settled due to plugging and abandonment or removed due to sale	(1,108)	(2,163)
Liability at end of year	84,324	74,081
Less: current asset retirement obligations	2,644	3,715
Non-current asset retirement obligations	$ 81,680	$ 70,366

Basis of presentation and sig_8

Basis of presentation and significant accounting policies - Net effect of transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Purchased oil
Disaggregation of Revenue [Line Items]
Net effect on earnings	$ (837)	$ 364	$ 1,214
Sales of purchased oil inventory
Disaggregation of Revenue [Line Items]
Net effect on earnings	494,860	104,403	327,839
Purchased oil inventory
Disaggregation of Revenue [Line Items]
Net effect on earnings	$ 495,697	$ 104,039	$ 326,625

Basis of presentation and sig_9

Basis of presentation and significant accounting policies - Revenue recognition (Details)	12 Months Ended
	Dec. 31, 2023
Minimum
Disaggregation of Revenue [Line Items]
Settlement statements and payment period	30 days
Maximum
Disaggregation of Revenue [Line Items]
Settlement statements and payment period	90 days

Basis of presentation and si_10

Basis of presentation and significant accounting policies - Income taxes (Details) - USD ($)	Dec. 31, 2023	Dec. 31, 2022
Accounting Policies [Abstract]
Unrecognized tax benefits	$ 0	$ 0

Basis of presentation and si_11

Basis of presentation and significant accounting policies - Non-cash investing and financing information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	$ 132,986	$ 131,867	$ 94,867
Supplemental non-cash operating information:
Right-of-use assets obtained in exchange for operating lease liabilities	176,027	34,532	7,742
Supplemental non-cash investing information:
Fair value of contingent consideration asset on transaction closing date	0	0	33,832
Change in accrued capital expenditures	43,559	(2,207)	22,310
Equity issued for acquisition of oil and natural gas properties	807,767	0	310,888
Liabilities assumed in acquisitions of oil and natural gas properties	86,478	0	11,653
Capitalized asset retirement cost	7,648	362	14,610
Capitalized interest	$ 2,892	$ 3,872	$ 5,866

Acquisitions and divestitures -

Acquisitions and divestitures - Narrative (Details) $ / shares in Units, $ in Thousands									3 Months Ended	12 Months Ended
	Dec. 21, 2023 USD ($) $ / shares shares	Nov. 06, 2023 USD ($) a shares	Nov. 05, 2023 USD ($)	Oct. 31, 2023 USD ($) a shares	Jun. 30, 2023 USD ($) a	Apr. 03, 2023 USD ($) a shares	Oct. 18, 2021 USD ($) a shares	Jul. 01, 2021 USD ($) a agreement shares	Jun. 30, 2022 USD ($)	Dec. 31, 2023 USD ($) $ / shares	Dec. 31, 2021 USD ($)	Sep. 13, 2023 a	Dec. 31, 2022 USD ($) $ / shares	Oct. 03, 2022 USD ($)	May 07, 2021
Business Acquisition [Line Items]
Common stock, par value (in USD per share) | $ / shares										$ 0.01			$ 0.01
Preferred stock, dividend rate, percentage										2%
Preferred stock, par value (in USD per share) | $ / shares										$ 0.01			$ 0.01
Evaluated properties										$ 11,799,155			$ 9,554,706
Unevaluated properties not being depleted										195,457			46,430
Asset retirement obligation liabilities										84,324	$ 72,003		74,081
Inventory										13,723			6,070
Disposal group, disposed of by sale, not discontinued operations | Sixth Street PSA
Business Acquisition [Line Items]
Proceeds after transaction costs								$ 405,000
Average working interest (as a percent)								37.50%							37.50%
Aggregate quarterly payments of additional cash contingent consideration								$ 38,700
Balloon payment of additional cash contingent consideration								55,000
Fair value of contingent consideration								33,800		31,100			$ 26,600
Gain (loss) on disposal of assets, net								94,300
Transaction costs associated with disposition								11,600
Disposal group, disposed of by sale, not discontinued operations | Sixth Street PSA | Maximum
Business Acquisition [Line Items]
Additional cash contingent consideration								93,700
Aggregate quarterly payments of additional cash contingent consideration								$ 38,700
Disposal group, disposed of by sale, not discontinued operations | Sixth Street PSA | Minimum
Business Acquisition [Line Items]
Pre-acquisition reserves (as a percent)								25%
Oil and Gas Properties
Business Acquisition [Line Items]
Proceeds after transaction costs														$ 106,100
Grey Rock
Business Acquisition [Line Items]
Purchase price	$ 56,300
Common stock, par value (in USD per share) | $ / shares	$ 0.01
Preferred stock, dividend rate, percentage	2%
Preferred stock, par value (in USD per share) | $ / shares	$ 0.01
Transaction related expenses	$ 1,000
Evaluated properties	53,100
Unevaluated properties not being depleted	3,300
Asset retirement obligation liabilities	$ 100
Grey Rock | Common stock
Business Acquisition [Line Items]
Stock issued in asset acquisition (in shares) | shares	627,026
Grey Rock | Preferred stock
Business Acquisition [Line Items]
Stock issued in asset acquisition (in shares) | shares	595,104
Tall City
Business Acquisition [Line Items]
Area of land (in acres) | a		21,450
Purchase price		$ 358,900
Transaction related expenses		7,800
Evaluated properties		335,900
Unevaluated properties not being depleted		58,700								4,400
Cash consideration		280,300
Operating lease right-of-use assets		2,700
Operating lease liabilities		2,700
Property tax liabilities		1,200
Revenue suspense liability		32,700
Asset retirement obligation liabilities		$ 1,800
Tall City | Common stock
Business Acquisition [Line Items]
Stock issued in asset acquisition (in shares) | shares		1,402,258
Maple
Business Acquisition [Line Items]
Area of land (in acres) | a				15,500
Purchase price				$ 175,100
Transaction related expenses				6,400
Evaluated properties				150,100
Unevaluated properties not being depleted				31,700
Property tax liabilities				1,900
Revenue suspense liability				3,300
Asset retirement obligation liabilities				$ 1,500
Maple | Common stock
Business Acquisition [Line Items]
Stock issued in asset acquisition (in shares) | shares				3,370,497
Forge
Business Acquisition [Line Items]
Area of land (in acres) | a					24,000
Purchase price					$ 397,500
Transaction related expenses					7,600
Evaluated properties					278,500
Unevaluated properties not being depleted					125,500					50,600
Cash consideration					389,900
Revenue suspense liability					13,700
Asset retirement obligation liabilities					1,700
Equipment inventory					$ 8,900
Driftwood
Business Acquisition [Line Items]
Area of land (in acres) | a						11,200
Purchase price						$ 201,700
Transaction related expenses						4,200
Evaluated properties						207,100
Cash consideration						117,400			$ 8,600
Revenue suspense liability						500
Asset retirement obligation liabilities						700
Derivative liability						$ 4,200
Driftwood | Common stock
Business Acquisition [Line Items]
Stock issued in asset acquisition (in shares) | shares						1,578,948
Pioneer
Business Acquisition [Line Items]
Area of land (in acres) | a							20,000
Purchase price							$ 210,100
Transaction related expenses							3,900
Evaluated properties							143,000
Unevaluated properties not being depleted							74,500
Cash consideration							135,300
Revenue suspense liability							$ 7,400
Pioneer | Common stock
Business Acquisition [Line Items]
Stock issued in asset acquisition (in shares) | shares							959,691
Pioneer - Tag-Along Sales Rights
Business Acquisition [Line Items]
Cash consideration											$ 2,900
Sabalo and Shad
Business Acquisition [Line Items]
Area of land (in acres) | a								21,000
Purchase price								$ 863,100
Transaction related expenses								17,000
Evaluated properties								503,000
Unevaluated properties not being depleted								363,000
Cash consideration								606,100
Revenue suspense liability								$ 4,300
Number of purchase and sale agreements | agreement								2
Inventory								$ 1,400
Sabalo and Shad | Common stock
Business Acquisition [Line Items]
Stock issued in asset acquisition (in shares) | shares								2,506,964
Henry Acquisition
Business Acquisition [Line Items]
Area of land (in acres) | a												15,900
Total consideration			$ 434,079
Business acquisition, transaction costs			10,500
Business combination, revenue of acquiree since acquisition date										28,800
Business combination, income (loss) of acquiree since acquisition date										$ 13,800
Asset retirement obligation liabilities			$ 1,155

Acquisitions and divestitures_2

Acquisitions and divestitures - Consideration (Details) - USD ($) $ / shares in Units, $ in Thousands				3 Months Ended
	Nov. 05, 2023	Jun. 30, 2023	Apr. 03, 2023	Jun. 30, 2022	Dec. 31, 2023	Dec. 31, 2022
Business Acquisition [Line Items]
Evaluated properties					$ 11,799,155	$ 9,554,706
Driftwood
Business Acquisition [Line Items]
Purchase price			$ 201,700
Cash consideration			117,400	$ 8,600
Evaluated properties			$ 207,100
Forge
Business Acquisition [Line Items]
Purchase price		$ 397,500
Cash consideration		389,900
Evaluated properties		$ 278,500
Henry Acquisition
Business Acquisition [Line Items]
Cash consideration for working capital closing adjustments	$ 1,154
Total consideration	$ 434,079
Henry Acquisition | Common stock
Business Acquisition [Line Items]
Shares of Company stock issued (in shares)	2,145,725
Company common stock price on Closing Date (in USD per share)	$ 52.25
Fair value of Company stock issued	$ 112,114
Henry Acquisition | Preferred stock
Business Acquisition [Line Items]
Shares of Company stock issued (in shares)	6,131,381
Company common stock price on Closing Date (in USD per share)	$ 52.25
Fair value of Company preferred stock issued (before dividends)	$ 320,365
Fair value of preferred stock dividends	446
Fair value of Company stock issued	$ 320,811

Acquisitions and divestitures_3

Acquisitions and divestitures - Business combination assets acquired and liabilities assumed (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Nov. 05, 2023	Dec. 31, 2022	Dec. 31, 2021
Fair value of liabilities assumed:
Asset retirement obligations	$ (84,324)		$ (74,081)	$ (72,003)
Henry Acquisition
Fair value of assets acquired:
Operating lease right-of-use assets		$ 3,366
Fair value of liabilities assumed:
Asset retirement obligations		(1,155)
Operating lease liabilities		(3,366)
Revenue suspense liabilities		(16,046)
Total purchase price		434,079
Henry Acquisition | Evaluated Properties
Fair value of assets acquired:
Oil and natural gas properties:		381,739
Henry Acquisition | Unevaluated Properties
Fair value of assets acquired:
Oil and natural gas properties:	$ 27,300	$ 69,541

Acquisitions and divestitures_4

Acquisitions and divestitures - Pro-forma information (Details) - Henry Acquisition - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Business Acquisition [Line Items]
Total revenues	$ 1,701,019	$ 2,206,570
Operating income	632,666	1,225,218
Net income	716,775	791,740
Net income available to common shareholders	$ 710,560	$ 785,001
Net income per common share, basic (in USD per share)	$ 31.72	$ 41.72
Net income per common share, diluted (in USD per share)	$ 25.51	$ 31.49

Leases - Lease costs (Details)

Leases - Lease costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Operating lease costs	$ 71,706	$ 24,174
Short-term lease costs	56,685	110,442
Variable lease costs	97,383	11,328
Sublease income	(1,198)	(990)
Total lease costs, net	$ 224,576	$ 144,954

Leases - Supplemental cash flow

Leases - Supplemental cash flow information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Operating cash flows from operating leases	$ 4,595	$ 3,892
Investing cash flows from operating leases	$ 65,305	$ 20,398

Leases - Lease terms and discou

Leases - Lease terms and discount rates (Details)	Dec. 31, 2023	Dec. 31, 2022
Operating leases:
Weighted-average remaining lease term	2 years 6 months 14 days	1 year 10 months 28 days
Weighted-average discount rate (as a percent)	8.26%	5.84%

Leases - Maturities of operatin

Leases - Maturities of operating lease liabilities (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Operating leases:
2024	$ 79,663
2025	61,157
2026	3,905
2027	2,788
2028	2,153
Thereafter	10,466
Total minimum lease payments	160,132
Less: imputed interest	(18,138)
Present value of future minimum lease payments	$ 141,994

Property and equipment - Oil an

Property and equipment - Oil and natural gas properties (Details)	12 Months Ended
	Dec. 31, 2023 USD ($) $ / Boe $ / bbl $ / MMBTU $ / MMcf	Dec. 31, 2022 USD ($) $ / bbl $ / MMBTU $ / Boe $ / MMcf	Dec. 31, 2021 USD ($) $ / Boe $ / MMcf $ / bbl $ / MMBTU
Property, Plant and Equipment [Line Items]
Capitalized employee-related costs | $	$ 22,179,000	$ 17,026,000	$ 18,255,000
Depletion expense of evaluated oil and natural gas properties | $	$ 446,611,000	$ 298,259,000	$ 201,691,000
Depletion per BOE sold (USD per BOE) | $ / Boe	12.67	9.92	6.76
Discount rate used in calculating full cost ceiling (as a percent)	10%
Non-cash full cost ceiling impairment | $	$ 0	$ 0	$ 0
Oil ($/Bbl)
Property, Plant and Equipment [Line Items]
Benchmark prices (USD per barrel or MMBtu)	78.22	90.15	63.04
Realized prices (USD per barrel or Mcf)	79.52	96.21	66.37
NGL ($/Bbl)
Property, Plant and Equipment [Line Items]
Benchmark prices (USD per barrel or MMBtu)	78.22	41.77	34.51
Realized prices (USD per barrel or Mcf)	16.46	29.84	22.90
Natural gas ($/MMBtu)
Property, Plant and Equipment [Line Items]
Benchmark prices (USD per barrel or MMBtu) | $ / MMBTU	2.64	5.20	3.35
Natural gas ($/Mcf)
Property, Plant and Equipment [Line Items]
Realized prices (USD per barrel or Mcf) | $ / MMcf	1.17	4.24	2.61

Property and equipment - Midstr

Property and equipment - Midstream and other fixed assets (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Total midstream and other fixed assets, net	$ 130,293,000	$ 127,803,000
Midstream service assets
Property, Plant and Equipment [Line Items]
Depreciable total	158,749,000	151,157,000
Retired midstream service assets	$ 0
Accumulated depreciation		11,400,000
Loss on disposal of assets, net		4,200,000
Property, Plant and Equipment, Disposals		15,600,000
Midstream service assets | Minimum
Property, Plant and Equipment [Line Items]
Useful life	3 years
Midstream service assets | Maximum
Property, Plant and Equipment [Line Items]
Useful life	20 years
Computer hardware and software
Property, Plant and Equipment [Line Items]
Depreciable total	$ 29,007,000	21,758,000
Vehicles
Property, Plant and Equipment [Line Items]
Depreciable total	5,046,000	7,934,000
Leasehold improvements
Property, Plant and Equipment [Line Items]
Depreciable total	7,136,000	7,136,000
Buildings
Property, Plant and Equipment [Line Items]
Depreciable total	7,039,000	7,039,000
Other
Property, Plant and Equipment [Line Items]
Depreciable total	7,710,000	6,087,000
Fixed Assets Excluding Land
Property, Plant and Equipment [Line Items]
Depreciable total	214,687,000	201,111,000
Less accumulated depreciation, amortization and impairment	(107,541,000)	(96,383,000)
Total midstream and other fixed assets, net	107,146,000	104,728,000
Land
Property, Plant and Equipment [Line Items]
Total midstream and other fixed assets, net	$ 23,147,000	$ 23,075,000

Debt - Long-term debt, net (Det

Debt - Long-term debt, net (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Sep. 25, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Total long-term debt	$ 1,633,523		$ 1,124,151
Unamortized debt issuance costs	(21,800)		(11,128)
Unamortized discounts	(6,068)		0
Unamortized premiums	3,769		0
Total long-term debt, net	1,609,424		1,113,023
September 2030 Notes
Debt Instrument [Line Items]
Unamortized discounts		$ (6,300)
Senior Notes | January 2025 Notes
Debt Instrument [Line Items]
Total long-term debt	0		455,628
Senior Notes | January 2028 Notes
Debt Instrument [Line Items]
Total long-term debt	700,309		300,309
Senior Notes | July 2029 Notes
Debt Instrument [Line Items]
Total long-term debt	298,214		298,214
Senior Notes | September 2030 Notes
Debt Instrument [Line Items]
Total long-term debt	500,000		0
Senior Secured Credit Facility | Line of Credit
Debt Instrument [Line Items]
Total long-term debt	135,000		70,000
Senior Secured Credit Facility | Line of Credit | Other Noncurrent Assets
Debt Instrument [Line Items]
Debt issuance costs, net	$ 14,100		$ 7,300

Debt - Senior Unsecured Notes R

Debt - Senior Unsecured Notes Repurchases under Authorized Bond Purchase Programs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Loss on extinguishment of debt, net	$ (4,039)	$ (1,459)	$ 0
Senior Notes
Debt Instrument [Line Items]
Total principal amount repurchased		284,806
Consideration paid	$ 0	282,902	$ 0
Write-off of debt issuance costs		3,363
Loss on extinguishment of debt, net		(1,459)
Senior Notes | January 2025 Notes
Debt Instrument [Line Items]
Total principal amount repurchased		122,285
Senior Notes | January 2028 Notes
Debt Instrument [Line Items]
Total principal amount repurchased		60,735
Senior Notes | July 2029 Notes
Debt Instrument [Line Items]
Total principal amount repurchased		$ 101,786

Debt - Senior Secured Credit Fa

Debt - Senior Secured Credit Facility (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Sep. 13, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Unrestricted and unencumbered cash and cash equivalents maximum	$ 50,000,000
Secured Debt
Debt Instrument [Line Items]
Borrowing capacity		$ 3,000,000,000
Current borrowing capacity		1,500,000,000
Aggregate elected commitment		$ 1,250,000,000
Secured Debt | Line of Credit
Debt Instrument [Line Items]
Collateral as a percentage of present value of proved reserves (as a percent)	85%
Current ratio requirement (not less than)	1
Consolidated interest coverage ratio (not less than)	3.50
Secured Debt | Minimum | Senior Secured Credit Facility
Debt Instrument [Line Items]
Commitment fee on unused capacity (as a percent)	0.375%
Secured Debt | Minimum | Base Rate
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	1.25%
Secured Debt | Minimum | Secured Overnight Financing Rate (SOFR) | Senior Secured Credit Facility
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	2.25%
Secured Debt | Maximum | Senior Secured Credit Facility
Debt Instrument [Line Items]
Commitment fee on unused capacity (as a percent)	0.50%
Secured Debt | Maximum | Base Rate
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	2.25%
Secured Debt | Maximum | Secured Overnight Financing Rate (SOFR) | Senior Secured Credit Facility
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	3.25%
Secured Debt | Line of Credit
Debt Instrument [Line Items]
Borrowing capacity	$ 3,000,000,000
Current borrowing capacity	1,500,000,000
Aggregate elected commitment	1,250,000,000
Line of credit	$ 135,000,000
Credit facility, interest rate at period end (as a percent)	7.706%
Secured Debt | Letters of credit
Debt Instrument [Line Items]
Borrowing capacity	$ 80,000,000
Letters of credit outstanding	$ 0		$ 0

Debt - September 2030 Notes (De

Debt - September 2030 Notes (Details) - USD ($) $ in Thousands	Sep. 25, 2023	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Unamortized discounts		$ 6,068	$ 0
September 2030 Notes
Debt Instrument [Line Items]
Face amount of debt	$ 500,000
Stated rate (as a percent)	9.75%
Debt instruments, issue price	98.742%
Unamortized discounts	$ 6,300
Proceeds from issuance of unsecured notes	$ 484,700

Debt - July 2029 Notes (Details

Debt - July 2029 Notes (Details) - July 2029 Notes $ in Millions	Jul. 16, 2021 USD ($)
Debt Instrument [Line Items]
Face amount of debt	$ 400
Stated rate (as a percent)	7.75%
Proceeds from issuance of unsecured notes	$ 392

Debt - January 2025 Notes and J

Debt - January 2025 Notes and January 2028 Notes (Details) - USD ($)				12 Months Ended
	Dec. 27, 2023	Sep. 25, 2023	Jan. 24, 2020	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Unamortized premiums				$ 3,769,000	$ 0
Interest expense				149,819,000	$ 125,121,000	$ 113,385,000
January 2025 Notes
Debt Instrument [Line Items]
Face amount of debt			$ 600,000,000
Stated rate (as a percent)			9.50%
Redeemed aggregate principal amount	$ 455,600,000
Interest expense				2,200,000
Write-off of debt issuance costs				$ 1,500,000
January 2028 Notes
Debt Instrument [Line Items]
Face amount of debt			$ 400,000,000
Stated rate (as a percent)			10.125%
January 2025 Notes & January 2028 Notes
Debt Instrument [Line Items]
Proceeds from issuance of unsecured notes			$ 982,000,000
Senior Note 10.125%, Due 2028
Debt Instrument [Line Items]
Face amount of debt		$ 400,000,000
Stated rate (as a percent)		10.125%
Proceeds from issuance of unsecured notes		$ 396,700,000
Debt instruments, issue price		10,100%
Unamortized premiums		$ 4,000,000
Senior Note 5.625%, Due 2022 | Senior Notes
Debt Instrument [Line Items]
Stated rate (as a percent)				5.625%
Senior Note 6.25%, Due 2023 | Senior Notes
Debt Instrument [Line Items]
Stated rate (as a percent)				6.25%

Debt - Interest expense (Detail

Debt - Interest expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Disclosure [Abstract]
Interest expense on borrowings	$ 144,731	$ 123,255	$ 114,800
Amortization of Debt Issuance Costs	7,980	5,738	4,451
Less capitalized interest	2,892	3,872	5,866
Total interest expense	$ 149,819	$ 125,121	$ 113,385

Stockholders' equity - Narrativ

Stockholders' equity - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions

12 Months Ended

Sep. 15, 2025

Sep. 15, 2024

Nov. 29, 2023

Sep. 29, 2023

Sep. 19, 2023

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Nov. 21, 2023

Nov. 20, 2023

May 31, 2022

May 26, 2022

May 25, 2022

Feb. 23, 2021

Class of Stock [Line Items]

Preferred stock, dividend rate, percentage

2%

Preferred stock, liquidation preference (in USD per share)

$ 54.96

Common stock authorized (in shares)

80,000,000

40,000,000

80,000,000

40,000,000

40,000,000

22,500,000

Authorized amount of share repurchase program

$ 200

Forecast

Class of Stock [Line Items]

Preferred stock, dividend rate, percentage

8%

5%

Henry

Class of Stock [Line Items]

Convertible preferred stock, shares issued (in shares)

6,131,381

Dividend paid

$ 0.4

At-the-Market Offering

Class of Stock [Line Items]

Stock issued in sale (in shares)

1,438,105

Consideration received from sale of stock

$ 72.5

Stock offering, Aggregate gross sales price

$ 75

Common stock

Class of Stock [Line Items]

Issuance of common stock, net of costs (in shares)

3,163,000

1,438,000

Common stock | Equity Offering

Class of Stock [Line Items]

Stock issued in sale (in shares)

2,750,000

Consideration received from sale of stock

$ 140.2

Common stock | Over-Allotment Option

Class of Stock [Line Items]

Consideration received from sale of stock

$ 21

Issuance of common stock, net of costs (in shares)

412,500

Treasury stock (at cost)

Class of Stock [Line Items]

Shares repurchased (shares)

0

490,536

0

Stockholders' equity - Equity i

Stockholders' equity - Equity issued for acquisitions of oil and natural gas properties (Details) - shares	Dec. 31, 2023	Dec. 21, 2023	Nov. 06, 2023	Nov. 05, 2023	Oct. 31, 2023	Apr. 03, 2023
Grey Rock | Common stock
Class of Stock [Line Items]
Stock issued in asset acquisition (in shares)		627,026
Grey Rock | Preferred stock
Class of Stock [Line Items]
Stock issued in asset acquisition (in shares)		595,104
Tall City | Common stock
Class of Stock [Line Items]
Stock issued in asset acquisition (in shares)			1,402,258
Stock issued in asset acquisition held in escrow (in shares)	773,290
Henry | Common stock
Class of Stock [Line Items]
Stock issued in asset acquisition (in shares)				2,145,725
Henry | Preferred stock
Class of Stock [Line Items]
Stock issued in asset acquisition (in shares)				6,131,381
Maple | Common stock
Class of Stock [Line Items]
Stock issued in asset acquisition (in shares)					3,370,497
Stock issued in asset acquisition held in escrow (in shares)	357,500
Driftwood | Common stock
Class of Stock [Line Items]
Stock issued in asset acquisition (in shares)						1,578,948

Stockholders' equity - Share re

Stockholders' equity - Share repurchase program (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Class of Stock [Line Items]
Total	$ 0	$ 37,290	$ 0
Treasury stock (at cost)
Class of Stock [Line Items]
Shares of Company common stock repurchased (in shares)	0	490,536	0
Average share price (in USD per share)		$ 76.02
Total		$ 37,290

Compensation plans - Narrative

Compensation plans - Narrative (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) $ / shares	Dec. 31, 2022 $ / shares	May 20, 2021 shares	May 19, 2021 shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized equity and stock-based compensation expense | $	$ 18.3
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)	1 year 8 months 23 days
Restricted Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value (USD per share)	$ 56.87	$ 52.90
Restricted Stock Awards | One Year From Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rights (as a percent)	33%
Restricted Stock Awards | Two Years from Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rights (as a percent)	33%
Restricted Stock Awards | Three Years from Grant Date
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rights (as a percent)	34%
Restricted Stock Awards | Immediate vesting on grant date | Non-employee director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rights (as a percent)	100%
Performance Share Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Requisite service period (in years)	3 years
Fair value (USD per share)	$ 101.48	$ 89.76
Expense per performance share or unit (in dollars per share)	$ 101.48
Performance Share Awards | March 22, 2022 | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout range (as a percent)	0%
Performance Share Awards | March 22, 2022 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout range (as a percent)	225%
Performance unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Requisite service period (in years)	3 years
Expense per performance share or unit (in dollars per share)	$ 45.17
Performance unit awards | March 03, 2023 | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout rate of market criteria awards (as a percent)	0%
Payout rate of performance criteria awards (as a percent)	0%
Performance unit awards | March 03, 2023 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout rate of market criteria awards (as a percent)	250%
Payout rate of performance criteria awards (as a percent)	200%
Performance unit awards | March 09, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Overall payout (as a percent)	146%
Expense per performance share or unit (in dollars per share)	$ 66.33
Performance unit awards | March 09, 2021 | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout rate of market criteria awards (as a percent)	0%
Payout rate of performance criteria awards (as a percent)	0%
Performance unit awards | March 09, 2021 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout rate of market criteria awards (as a percent)	250%
Payout rate of performance criteria awards (as a percent)	200%
Performance unit awards | March 5, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Overall payout (as a percent)	151%
Performance unit awards | March 5, 2020 | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout range (as a percent)	0%
Performance unit awards | March 5, 2020 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout range (as a percent)	200%
Payout range if ATSR Appreciation is zero or less (as a percent)	100%
Phantom unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Ratio of common stock for each phantom unit	1
Fair value (USD per share)	$ 45.49
Phantom unit awards | Tranche 1
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rights (as a percent)	33%
Phantom unit awards | Tranche 2
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rights (as a percent)	33%
Phantom unit awards | Tranche 3
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rights (as a percent)	34%
Equity-based Liability
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized equity and stock-based compensation expense | $	$ 2.8
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)	1 year 10 months 17 days
Equity Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized (in shares) | shares			2,432,500	1,492,500

Compensation plans - Activity f

Compensation plans - Activity for equity compensation awards (Details) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) $ / shares shares
Restricted Stock Awards
Restricted Stock and Performance Shares Awards
Outstanding at the beginning of the period (in shares) | shares	362
Granted (in shares) | shares	340
Forfeited (in shares) | shares	(47)
Vested (in shares) | shares	(183)
Outstanding at the end of the period (in shares) | shares	472
Weighted-average grant-date fair value (per share)
Outstanding at the beginning of the period (USD per share) | $ / shares	$ 52.90
Granted (in USD per share) | $ / shares	54.68
Forfeited (USD per share) | $ / shares	57.39
Vested (USD per share) | $ / shares	44.86
Outstanding at the end of the period (USD per share) | $ / shares	$ 56.87
Weighted-average exercise price (per share)
Intrinsic value of vested restricted stock awards | $	$ 9.3
Stock Option Awards
Stock Option Awards
Outstanding at the beginning of the period (in shares) | shares	3
Expired or canceled (in shares) | shares	(1)
Outstanding at the end of the period (in shares) | shares	2
Weighted-average exercise price (per share)
Outstanding at the end of the period (in USD per share) | $ / shares	$ 235.08
Expired or canceled (in USD per share) | $ / shares	346.80
Outstanding at end of the period (in USD per share) | $ / shares	$ 136.83
Performance Share Awards
Restricted Stock and Performance Shares Awards
Outstanding at the beginning of the period (in shares) | shares	48
Outstanding at the end of the period (in shares) | shares	48
Weighted-average grant-date fair value (per share)
Outstanding at the beginning of the period (USD per share) | $ / shares	$ 89.76
Outstanding at the end of the period (USD per share) | $ / shares	$ 101.48

Compensation plans - Performanc

Compensation plans - Performance and Phantom unit award activity (Details) - $ / shares	12 Months Ended	36 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Mar. 03, 2023	Mar. 01, 2023
Performance unit awards
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding at the beginning of the period (in shares)	150,000
Granted (in shares)	75,000
Forfeited (in shares)	0
Vested (in shares)	(67,000)
Outstanding at the end of the period (in shares)	158,000	150,000
Performance share conversion (in shares)	101,368
Performance unit awards | March 5, 2020
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Overall payout (as a percent)		151%
Settlement/payment, per share (in USD per share)			$ 57.06
Phantom unit awards
Share-Based Compensation Arrangement by Share-Based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding at the beginning of the period (in shares)	18,000
Granted (in shares)	0
Forfeited (in shares)	0
Vested (in shares)	(16,000)
Outstanding at the end of the period (in shares)	2,000	18,000
Settlement/payment, per share (in USD per share)			$ 57.06	$ 52.56

Compensation plans - Assumption

Compensation plans - Assumptions used to estimate fair value of performance share and unit awards (Details)	12 Months Ended
	Dec. 31, 2023 $ / shares
Performance Share Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining performance period (in years)	2 years 10 months 9 days
Risk-free interest rate (as a percent)	1.71%
Dividend yield (as a percent)	0%
Expected volatility (as a percent)	119.25%
Expense per performance share or unit (in dollars per share)	$ 101.48
Performance Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Remaining performance period (in years)	2 years
Risk-free interest rate (as a percent)	4.13%
Dividend yield (as a percent)	0%
Expected volatility (as a percent)	66.40%
Expense per performance share or unit (in dollars per share)	$ 45.17

Compensation plans - Equity-bas

Compensation plans - Equity-based compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total equity-based compensation, net	$ 14,146	$ 10,058	$ 16,028
Share-settled
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total equity-based compensation, gross	13,969	10,186	9,258
Less amounts capitalized	(2,975)	(1,783)	(1,583)
Total equity-based compensation, net	10,994	8,403	7,675
Restricted Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total equity-based compensation, gross	12,114	8,596	7,594
Performance Share Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total equity-based compensation, gross	1,855	1,590	1,657
Stock Option Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total equity-based compensation, gross	0	0	7
Cash-settled
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total equity-based compensation, gross	3,202	1,927	8,718
Less amounts capitalized	(50)	(272)	(365)
Total equity-based compensation, net	3,152	1,655	8,353
Performance unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total equity-based compensation, gross	2,932	741	7,480
Phantom unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total equity-based compensation, gross	$ 270	$ 1,186	$ 1,238

Net income per common share - S

Net income per common share - Summary (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Net income (numerator):
Net income	$ 695,078	$ 631,512	$ 145,008
Less: Preferred stock dividends	449	0	0
Net income available to common stockholders basic	$ 694,629	$ 631,512	$ 145,008
Weighted-average common shares outstanding (denominator):
Basic (in shares)	20,254	16,672	14,240
Dilutive preferred stock (in shares)	421	0	0
Diluted (in shares)	20,783	16,867	14,464
Net income (loss) per common share:
Basic (in USD per share)	$ 34.30	$ 37.88	$ 10.18
Diluted (in USD per share)	$ 33.44	$ 37.44	$ 10.03
Non-vested restricted stock awards
Weighted-average common shares outstanding (denominator):
Diluted non-vested awards (in shares)	106	183	181
Performance Share Awards
Weighted-average common shares outstanding (denominator):
Diluted non-vested awards (in shares)	2	12	43

Derivatives - Narrative (Detail

Derivatives - Narrative (Details) $ in Millions	Dec. 31, 2023 USD ($) derivative	Dec. 31, 2022 USD ($)	Jul. 01, 2021 USD ($)
Derivative [Line Items]
Number of types of derivative instruments | derivative	2
Disposal group, disposed of by sale, not discontinued operations | Sixth Street PSA
Derivative [Line Items]
Aggregate quarterly payments of additional cash contingent consideration			$ 38.7
Balloon payment of additional cash contingent consideration			55
Notional amount of derivative	$ 84.2
Fair value of contingent consideration	$ 31.1	$ 26.6	33.8
Maximum | Disposal group, disposed of by sale, not discontinued operations | Glasscock and Reagan County - Working Interest Sale in Oil and Gas Properties
Derivative [Line Items]
Additional cash contingent consideration			93.7
Maximum | Disposal group, disposed of by sale, not discontinued operations | Sixth Street PSA
Derivative [Line Items]
Additional cash contingent consideration			93.7
Aggregate quarterly payments of additional cash contingent consideration			$ 38.7

Derivatives - Gain (Loss) on De

Derivatives - Gain (Loss) on Derivatives (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Gain (loss) on derivatives, net	$ 96,230	$ (298,723)	$ (452,175)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Nonoperating Income (Expense)	Nonoperating Income (Expense)	Nonoperating Income (Expense)
Commodity
Derivative [Line Items]
Gain (loss) on derivatives, net	$ 89,951	$ (291,973)	$ (453,784)
Contingent consideration
Derivative [Line Items]
Gain (loss) on derivatives, net	6,279	(6,764)	1,639
Interest rate
Derivative [Line Items]
Gain (loss) on derivatives, net	$ 0	$ 14	$ (30)

Derivatives - Summary (Details)

Derivatives - Summary (Details) - Outstanding at End of Period - Forecast - Derivatives not designated as hedges	12 Months Ended
	Dec. 31, 2025 MMBTU $ / bbl $ / MMBTU bbl	Dec. 31, 2024 MMBTU $ / bbl $ / MMBTU bbl
WTI NYMEX | Oil | Swap
Derivative [Line Items]
Volume (Bbl) | bbl	3,445,000	18,835,950
Weighted-average price/differential (in USD per unit)	75.52	75.37
WTI NYMEX | Oil | Three-way Collar
Derivative [Line Items]
Volume (Bbl) | bbl	0	217,350
Weighted-average price/differential (in USD per unit)	0	50
WTI NYMEX | Oil | Three-way Collar | Minimum
Derivative [Line Items]
Weighted-average price/differential (in USD per unit)	0	66.51
WTI NYMEX | Oil | Three-way Collar | Maximum
Derivative [Line Items]
Weighted-average price/differential (in USD per unit)	0	87.09
Argus WTI Midland to Argus WTI Formula Basis | Oil | Basis Swap
Derivative [Line Items]
Volume (Bbl) | bbl	0	293,300
Weighted-average price/differential (in USD per unit)	0	0.11
Henry Hub NYMEX | Natural gas | Swap
Derivative [Line Items]
Weighted-average price/differential (in USD per unit) | $ / MMBTU	0	3.47
Volume (MMBtu) | MMBTU	0	26,075,700
Henry Hub NYMEX | Natural gas | Collar
Derivative [Line Items]
Volume (MMBtu) | MMBTU	0	776,292
Henry Hub NYMEX | Natural gas | Collar | Minimum
Derivative [Line Items]
Weighted-average price/differential (in USD per unit) | $ / MMBTU	0	3.40
Henry Hub NYMEX | Natural gas | Collar | Maximum
Derivative [Line Items]
Weighted-average price/differential (in USD per unit) | $ / MMBTU	0	6.11
Waha Inside FERC to Henry Hub NYMEX | Natural gas | Basis Swap
Derivative [Line Items]
Weighted-average price/differential (in USD per unit) | $ / MMBTU	0	(0.74)
Volume (MMBtu) | MMBTU	0	26,851,992

Fair value measurements - Fair

Fair value measurements - Fair value hierarchy (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Assets:
Total gross fair value	$ 150,407	$ 43,073
Net fair value presented on the consolidated balance sheets	99,336	24,670
Net fair value presented on the consolidated balance sheets	51,071	24,363
Liabilities:
Net fair value presented on the consolidated balance sheets	0	(5,960)
Amounts offset	0	0
Net derivative asset positions	150,407	43,073
Level 1
Liabilities:
Net derivative asset positions	0	0
Level 2
Liabilities:
Net derivative asset positions	119,301	16,433
Level 3
Liabilities:
Net derivative asset positions	31,106	26,640
Commodity derivatives
Assets:
Net fair value presented on the consolidated balance sheets	97,035	22,393
Net fair value presented on the consolidated balance sheets	22,266
Liabilities:
Net fair value presented on the consolidated balance sheets	0	(5,960)
Contingent Consideration
Assets:
Net fair value presented on the consolidated balance sheets	2,301	2,277
Net fair value presented on the consolidated balance sheets	28,805	24,363
Current Assets | Commodity derivatives
Assets:
Total gross fair value	106,067	35,586
Amounts offset	(9,032)	(13,193)
Current Assets | Commodity derivatives | Level 1
Assets:
Total gross fair value	0	0
Current Assets | Commodity derivatives | Level 2
Assets:
Total gross fair value	106,067	35,586
Current Assets | Commodity derivatives | Level 3
Assets:
Total gross fair value	0	0
Current Assets | Contingent Consideration
Assets:
Total gross fair value	2,301	2,277
Amounts offset	0	0
Current Assets | Contingent Consideration | Level 1
Assets:
Total gross fair value	0	0
Current Assets | Contingent Consideration | Level 2
Assets:
Total gross fair value	0	0
Current Assets | Contingent Consideration | Level 3
Assets:
Total gross fair value	2,301	2,277
Noncurrent Assets | Commodity derivatives
Assets:
Total gross fair value	22,266
Amounts offset	0
Noncurrent Assets | Commodity derivatives | Level 1
Assets:
Total gross fair value	0
Noncurrent Assets | Commodity derivatives | Level 2
Assets:
Total gross fair value	22,266
Noncurrent Assets | Commodity derivatives | Level 3
Assets:
Total gross fair value	0
Noncurrent Assets | Contingent Consideration
Assets:
Total gross fair value	28,805	24,363
Amounts offset	0	0
Noncurrent Assets | Contingent Consideration | Level 1
Assets:
Total gross fair value	0	0
Noncurrent Assets | Contingent Consideration | Level 2
Assets:
Total gross fair value	0	0
Noncurrent Assets | Contingent Consideration | Level 3
Assets:
Total gross fair value	28,805	24,363
Current Liabilities | Commodity derivatives
Liabilities:
Total gross fair value	(9,032)	(19,153)
Amounts offset	9,032	13,193
Current Liabilities | Commodity derivatives | Level 1
Liabilities:
Total gross fair value	0	0
Current Liabilities | Commodity derivatives | Level 2
Liabilities:
Total gross fair value	(9,032)	(19,153)
Current Liabilities | Commodity derivatives | Level 3
Liabilities:
Total gross fair value	$ 0	$ 0

Fair value measurements - Chang

Fair value measurements - Changes in Contingent Consideration (Details) - Contingent Consideration Derivative - Level 3 - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Change in Amount of Contingent Consideration, Liability [Roll Forward]
Balance of Level 3 at beginning of year	$ 26,640	$ 35,861	$ 0
Sixth Street Contingent Consideration valuation as of Sixth Street Closing Date	0	0	33,832
Change in Sixth Street Contingent Consideration fair value	6,279	(6,764)	2,029
Settlements realized	(1,813)	(2,457)	0
Balance of Level 3 at end of year	$ 31,106	$ 26,640	$ 35,861

Fair value measurements - Carry

Fair value measurements - Carrying amounts and fair values of debt (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Carrying Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	$ 1,633,523	$ 1,124,151
Carrying Value | Senior Notes | January 2025 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	0	455,628
Carrying Value | Senior Notes | January 2028 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	700,309	300,309
Carrying Value | Senior Notes | July 2029 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	298,214	298,214
Carrying Value | Senior Notes | September 2030 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	500,000	0
Carrying Value | Secured Debt | Senior Secured Credit Facility
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	135,000	70,000
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	1,658,686	1,080,329
Fair Value | Senior Notes | January 2025 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	0	449,122
Fair Value | Senior Notes | January 2028 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	719,617	292,846
Fair Value | Senior Notes | July 2029 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	285,099	268,416
Fair Value | Senior Notes | September 2030 Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	518,875	0
Fair Value | Secured Debt | Senior Secured Credit Facility
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	$ 135,095	$ 69,945

Income taxes - Income tax benef

Income taxes - Income tax benefit (expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current income tax benefit (expense):
Federal	$ 0	$ 0	$ 0
State	(5,723)	(6,121)	(1,324)
Deferred income tax benefit (expense):
Federal	190,341	0	0
State	(1,281)	619	(2,321)
Total income tax benefit (expense):	$ 183,337	$ (5,502)	$ (3,645)

Income taxes - Deferred income

Income taxes - Deferred income tax reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income tax expense computed by applying the statutory rate	$ (107,466)	$ (133,773)	$ (31,217)
Change in deferred tax valuation allowance	297,658	144,480	45,717
Non-deductible equity-based compensation	0	(19,301)	(13,640)
State income tax and change in valuation allowance	(5,803)	8,058	(3,274)
Other items	(1,052)	(4,966)	(1,231)
Total income tax benefit (expense):	$ 183,337	$ (5,502)	$ (3,645)

Income taxes - Net deferred tax

Income taxes - Net deferred tax asset (liability) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Deferred tax assets:
Net operating loss carryforwards	$ 264,114	$ 307,357
Equity-based compensation	232	2,933
Interest expense limitation	3,908	0
Other	4,117	1,110
Total deferred tax asset	272,371	311,400
Valuation allowance	(20,145)	(298,184)
Deferred tax assets, net of valuation allowance	252,226	13,216
Deferred tax liabilities:
Oil and natural gas properties, midstream service assets and other fixed assets	(36,524)	(11,105)
Derivatives	(25,353)	(2,331)
Other	(1,513)	0
Total deferred tax liabilities	(63,390)	(13,436)
Total net deferred tax asset	$ 188,836
Total net deferred tax liability		$ (220)

Income taxes - Narrative (Detai

Income taxes - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Income Tax Examination [Line Items]
Valuation allowance (decrease)	$ 20,145	$ 298,184
Valuation allowance, deferred tax asset, increase (decrease), amount	183,300
Federal
Income Tax Examination [Line Items]
Net operating loss carry-forwards	1,200,000
Deferred tax assets, operating loss carryforwards, subject to expiration	789,800
Deferred tax assets, operating loss carryforwards, not subject to expiration	366,800
State | Oklahoma
Income Tax Examination [Line Items]
Net operating loss carry-forwards	523,700
Deferred tax assets, operating loss carryforwards, subject to expiration	34,600
Deferred tax assets, operating loss carryforwards, not subject to expiration	$ 489,100

Credit risk - Narrative (Detail

Credit risk - Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Concentration Risk [Line Items]
Net derivative asset positions	$ 150,407	$ 43,073
Level 2
Concentration Risk [Line Items]
Net derivative asset positions	$ 119,301	$ 16,433

Credit risk - Concentration Ris

Credit risk - Concentration Risk (Details) - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Purchaser A | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)	32%	33%	29%
Purchaser A | Purchased Oil Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)			47%
Purchaser B | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)	21%
Purchaser B | Purchased Oil Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)			31%
Purchaser C | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)	12%
Purchaser C | Purchased Oil Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)			22%
Purchaser D | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)		18%	14%
Purchaser E | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)		17%	24%
Purchaser F | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)			17%

Commitments and contingencies (

Commitments and contingencies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Unrecorded Unconditional Purchase Obligation [Line Items]
Minimum volume commitment deficiency payments	$ 5.8	$ 13.2	$ 4.4
Minimum volume commitments deficiency payments liability	6.7	$ 11.5
Firm sale and transportation commitments
Unrecorded Unconditional Purchase Obligation [Line Items]
Future drilling contracts commitments	$ 124.3

Related parties (Details)

Related parties (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Related Party Transaction [Line Items]
Operating lease liabilities	$ 141,994
Capital expenditures for oil and natural gas properties	617,397	$ 566,989	$ 418,362
Halliburton | Affiliated Entity
Related Party Transaction [Line Items]
Operating lease liabilities	59,700
Capital expenditures for oil and natural gas properties	$ 113,291	$ 103,152	$ 69,670

Organizational restructurings -

Organizational restructurings - Narrative (Details)	Jun. 29, 2021 senior_officer
Restructuring and Related Activities [Abstract]
Workforce reduction (positions eliminated)	14
Workforce reduction (as a percent)	5%

Organizational restructurings_2

Organizational restructurings - Gross equity-based compensation expense reversals (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Restructuring Cost and Reserve [Line Items]
Gross equity-based compensation expense reversals	$ 14,146	$ 10,058	$ 16,028
Share-Based Compensation Awards Forfeited
Restructuring Cost and Reserve [Line Items]
Gross equity-based compensation expense reversals	$ (283)	$ (4,908)	$ (1,088)

Subsequent events - Narrative (

Subsequent events - Narrative (Details) - USD ($) $ in Thousands				12 Months Ended
	Feb. 15, 2024	Feb. 02, 2024	Jan. 04, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Mar. 04, 2024
Subsequent Event [Line Items]
Proceeds from long-term lines of credit				$ 765,000	$ 455,000	$ 570,000
Line of Credit | Secured Debt
Subsequent Event [Line Items]
Line of credit				$ 135,000
Subsequent event | Line of Credit | Secured Debt
Subsequent Event [Line Items]
Proceeds from long-term lines of credit	$ 30,000		$ 100,000
Line of credit							$ 265,000
PEP Acquisition | Subsequent event
Subsequent Event [Line Items]
Purchase price		$ 79,700
Transaction related expenses		$ 1,000
PEP Acquisition | Subsequent event | Common stock
Subsequent Event [Line Items]
Stock issued in asset acquisition (in shares)		878,690
PEP Acquisition | Subsequent event | Preferred stock
Subsequent Event [Line Items]
Stock issued in asset acquisition (in shares)		980,272

Supplemental oil, NGL and nat_3

Supplemental oil, NGL and natural 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
Property acquisition costs:
Evaluated	$ 1,328,571	$ 8,295	$ 899,128
Unevaluated	401,533	3,470	198,770
Exploration costs	29,612	26,384	33,482
Development costs	633,413	540,447	410,855
Total oil and natural gas properties costs incurred	$ 2,393,129	$ 578,596	$ 1,542,235

Supplemental oil, NGL and nat_4

Supplemental oil, NGL and natural gas disclosures (unaudited) - Aggregate capitalized oil, NGL and natural gas costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Gross capitalized costs:
Evaluated properties	$ 11,799,155	$ 9,554,706
Unevaluated properties not being depleted	195,457	46,430
Total gross capitalized costs	11,994,612	9,601,136
Less accumulated depletion and impairment	(7,764,697)	(7,318,399)
Net capitalized costs	4,229,915	2,282,737
Oil and natural gas property costs not being amortized
Unevaluated properties not being depleted remained	167,192	3,124	$ 24,618	$ 523
Unevaluated properties not being depleted	$ 195,457	$ 46,430

Supplemental oil, NGL and nat_5

Supplemental oil, NGL and natural gas disclosures (unaudited) - Results of operations of oil, NGL and natural gas producing activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues:
Oil, NGL and natural gas sales	$ 1,528,633	$ 1,794,374	$ 1,147,143
Production costs:
Lease operating expenses	261,129	173,983	101,994
Production and ad valorem taxes	93,224	110,997	68,742
Oil transportation and marketing expenses	41,284	53,692	47,916
Total production costs	397,650	338,672	218,652
Other costs:
Depletion	446,611	298,259	201,691
Accretion of asset retirement obligation	3,518	3,653	4,018
Income tax expense	149,788	11,538	14,456
Total other costs	599,917	313,450	220,165
Results of operations	531,066	$ 1,142,252	$ 708,326
Effective Income Tax Rate Reconciliation, Percent		1%	2%
Gas gathering, processing and transportation expenses
Production costs:
Gas gathering, processing and transportation expenses	$ 2,013	$ 0	$ 0

Supplemental oil, NGL and nat_6

Supplemental oil, NGL and natural gas disclosures (unaudited) - Net proved oil, NGL and natural gas reserves - (unaudited) - Narrative (Details) Boe in Thousands	12 Months Ended
	Dec. 31, 2023 Boe location reserve_stream	Dec. 31, 2022 Boe reserve_stream location	Dec. 31, 2021 Boe reserve_stream location
Net proved oil and natural gas reserves
Percentage of proved reserves estimated by independent reserve engineers (percent)	100%	100%	100%
Number of reportable reserves streams | reserve_stream	3	3	3
Revisions of previous estimates (MBOE)	(58,601)	(16,802)	38,709
Extensions, discoveries and other additions (MBOE)	30,844	34,141	19,369
Acquisitions of reserves in place (MBOE)	165,578		100,286
Divestitures of reserves in place (MBOE)		3,585	88,125
Development wells drilled, net productive | location			6
Development wells drilled, net nonproductive | location			12
Disposal group, disposed of by sale, not discontinued operations
Net proved oil and natural gas reserves
Average working interest (as a percent)			37.50%
Performance, Pricing and Other Increases
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	16,240	4,351	37,341
Negative Revision from Decrease in Estimated Quantities of Proved Undeveloped Locations
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	4,470	1,837	2,885
Negative Revision due to Proved Undeveloped Locations Removed due to Year-End Pricing
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	8,679
Performance, Pricing and Other Decreases
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	12,030	9,531	3,622
Drilling of New Wells
Net proved oil and natural gas reserves
Extensions, discoveries and other additions (MBOE)	598	3,850	6,724
Horizontal Proved Undeveloped Properties
Net proved oil and natural gas reserves
Extensions, discoveries and other additions (MBOE)	30,246	30,291	12,645
New Proved Developed Locations
Net proved oil and natural gas reserves
Acquisitions of reserves in place (MBOE)	104,323		47,310
Additional Acreage Acquired under Proved Locations
Net proved oil and natural gas reserves
Acquisitions of reserves in place (MBOE)	61,255		52,976
Reinterpretation of Undeveloped Locations
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	26,122	9,785	7,875
Proved undeveloped locations | location	45	16

Supplemental oil, NGL and nat_7

Supplemental oil, NGL and natural gas disclosures (unaudited) - Net proved oil, NGL and natural gas reserves - (unaudited) (Details) bbl in Thousands, Mcf in Thousands, Boe in Thousands	12 Months Ended
	Dec. 31, 2023 Boe Mcf bbl	Dec. 31, 2022 Boe bbl Mcf	Dec. 31, 2021 Boe Mcf bbl
Proved developed and undeveloped reserves:
Beginning of year (MBOE) | Boe	302,318	318,640	278,228
Revisions of previous estimates (MBOE) | Boe	(58,601)	(16,802)	38,709
Extensions, discoveries and other additions (MBOE) | Boe	30,844	34,141	19,369
Acquisitions of reserves in place (MBOE) | Boe	165,578		100,286
Divestitures of reserves in place (MBOE) | Boe		(3,585)	(88,125)
Production (MBOE) | Boe	(35,256)	(30,076)	(29,827)
End of year (MBOE) | Boe	404,883	302,318	318,640
Proved developed reserves:
Beginning of year (energy) | Boe	222,917	232,048	253,586
End of year (energy) | Boe	287,021	222,917	232,048
Proved undeveloped reserves:
Beginning of year (energy) | Boe	79,401	86,592	24,642
End of year (energy) | Boe	117,862	79,401	86,592
Oil (MBbl)
Proved developed and undeveloped reserves:
As of December 31, 2022	116,458	120,902	67,759
Revisions of previous estimates	(28,564)	(9,792)	4,740
Extensions, discoveries and other additions	11,175	21,351	10,354
Acquisitions of reserves in place	77,609		65,572
Divestitures of reserves in place		(2,165)	(15,904)
Production	(16,895)	(13,838)	(11,619)
As of December 31, 2023	159,783	116,458	120,902
Proved developed reserves:
Beginning of year (volume)	70,333	70,727	51,751
End of year (volume)	104,993	70,333	70,727
Proved undeveloped reserves:
Beginning of year (volume)	46,125	50,175	16,008
End of year (volume)	54,790	46,125	50,175
NGL (MBbl)
Proved developed and undeveloped reserves:
As of December 31, 2022	93,812	100,047	100,922
Revisions of previous estimates	(20,823)	(4,561)	16,952
Extensions, discoveries and other additions	10,281	7,162	5,269
Acquisitions of reserves in place	47,261		19,711
Divestitures of reserves in place		(808)	(34,129)
Production	(9,128)	(8,028)	(8,678)
As of December 31, 2023	121,403	93,812	100,047
Proved developed reserves:
Beginning of year (volume)	75,156	78,908	96,251
End of year (volume)	89,449	75,156	78,908
Proved undeveloped reserves:
Beginning of year (volume)	18,656	21,139	4,671
End of year (volume)	31,954	18,656	21,139
Natural gas (MMcf)
Proved developed and undeveloped reserves:
As of December 31, 2022 | Mcf	552,288	586,145	657,284
Revisions of previous estimates | Mcf	(55,284)	(14,694)	102,080
Extensions, discoveries and other additions | Mcf	56,329	33,767	22,479
Acquisitions of reserves in place | Mcf	244,253		90,023
Divestitures of reserves in place | Mcf		(3,671)	(228,546)
Production | Mcf	(55,404)	(49,259)	(57,175)
As of December 31, 2023 | Mcf	742,182	552,288	586,145
Proved developed reserves:
Beginning of year (volume) | Mcf	464,567	494,476	633,503
End of year (volume) | Mcf	555,472	464,567	494,476
Proved undeveloped reserves:
Beginning of year (volume) | Mcf	87,721	91,669	23,781
End of year (volume) | Mcf	186,710	87,721	91,669

Supplemental oil, NGL and nat_8

Supplemental oil, NGL and natural gas disclosures (unaudited) - Standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 15,570,267	$ 16,343,468	$ 11,846,148
Future production costs	(5,543,237)	(4,136,380)	(3,595,524)
Future development costs	(1,904,597)	(1,403,721)	(1,064,527)
Future income tax expenses	(669,158)	(1,587,677)	(774,461)
Future net cash flows	7,453,275	9,215,690	6,411,636
10% discount for estimated timing of cash flows	(3,302,437)	(4,461,114)	(2,986,324)
Standardized measure of discounted future net cash flows	$ 4,150,838	4,754,576	3,425,312	$ 1,014,854
Future net cash flow discount rate for impairment of oil and gas properties (as a percent)	10%
Non-cash full cost ceiling impairment	$ 0	$ 0	$ 0

Supplemental oil, NGL and nat_9

Supplemental oil, NGL and natural gas disclosures (unaudited) - Changes in the standardized measure of discounted future net cash flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves
Standardized measure of discounted future net cash flows, beginning of year	$ 4,754,576	$ 3,425,312	$ 1,014,854
Changes in the year resulting from:
Sales, less production costs	(1,136,735)	(1,468,946)	(934,440)
Revisions of previous quantity estimates	(964,416)	(99,512)	426,060
Extensions, discoveries and other additions	125,875	667,859	293,511
Net change in prices and production costs	(2,560,883)	2,565,963	1,572,662
Changes in estimated future development costs	137,310	(165,579)	134,091
Previously estimated development costs incurred during the period	368,688	260,475	169,376
Acquisitions of reserves in place	2,211,370	0	1,509,087
Divestitures of reserves in place	0	(96,222)	(369,601)
Accretion of discount	624,819	371,625	102,607
Net change in income taxes	371,962	(418,537)	(279,722)
Timing differences and other	218,272	(287,862)	(213,173)
Standardized measure of discounted future net cash flows, end of year	$ 4,150,838	$ 4,754,576	$ 3,425,312