Vital Energy (VTLE) 10-K 22 Feb 23 2022 FY Annual report Financial data

Cover

Cover - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2022	Feb. 17, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
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
Entity Shell Company	false
Entity Public Float			$ 1.2
Entity Common Stock, Shares Outstanding		17,149,215
Documents Incorporated by Reference	Portions of the registrant's definitive proxy statement for its 2023 Annual Meeting of Stockholders are incorporated by reference into Part III of this report for the year ended December 31, 2022.
Entity Central Index Key	0001528129
Amendment Flag	false
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Audit Information [Abstract]
Auditor Name	Ernst & Young LLP	GRANT THORNTON LLP
Auditor Location	Tulsa, OK	Tulsa, Oklahoma
Auditor Firm ID	42	248

Consolidated balance sheets

Consolidated balance sheets - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents	$ 44,435	$ 56,798
Accounts receivable, net	163,369	151,807
Derivatives	24,670	4,346
Other current assets	13,317	22,906
Total current assets	245,791	235,857
Oil and natural gas properties, full cost method:
Evaluated properties	9,554,706	8,968,668
Unevaluated properties not being depleted	46,430	170,033
Less: accumulated depletion and impairment	(7,318,399)	(7,019,670)
Oil and natural gas properties, net	2,282,737	2,119,031
Midstream service assets, net	85,156	96,528
Other fixed assets, net	42,647	34,590
Property and equipment, net	2,410,540	2,250,149
Derivatives	24,363	32,963
Operating lease right-of-use assets	23,047	11,514
Other noncurrent assets, net	22,373	21,341
Total assets	2,726,114	2,551,824
Current liabilities:
Accounts payable and accrued liabilities	102,516	71,386
Accrued capital expenditures	48,378	50,585
Undistributed revenue and royalties	160,023	117,920
Derivatives	5,960	179,809
Operating lease liabilities	15,449	7,742
Other current liabilities	82,950	99,471
Total current liabilities	415,276	526,913
Long-term debt, net	1,113,023	1,425,858
Asset retirement obligations	70,366	69,057
Operating lease liabilities	9,435	5,726
Other noncurrent liabilities	7,268	10,490
Total liabilities	1,615,368	2,038,044
Commitments and contingencies
Stockholders' equity:
Preferred stock, $0.01 par value, 50,000,000 shares authorized and zero issued as of December 31, 2022 and 2021	0	0
Common stock, $0.01 par value, 40,000,000 and 22,500,000 shares authorized, and 16,762,127 and 17,074,516 issued and outstanding as of December 31, 2022 and 2021, respectively	168	171
Additional paid-in capital	2,754,085	2,788,628
Accumulated deficit	(1,643,507)	(2,275,019)
Total stockholders' equity	1,110,746	513,780
Total liabilities and stockholders' equity	$ 2,726,114	$ 2,551,824

Consolidated balance sheets (Pa

Consolidated balance sheets (Parenthetical) - $ / shares	Dec. 31, 2022	Dec. 31, 2021
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)	0	0
Common stock, par value (in USD per share)	$ 0.01	$ 0.01
Common stock authorized (in shares)	40,000,000	22,500,000
Common stock issued (shares)	16,762,127	17,074,516
Common stock outstanding (shares)	16,762,127	17,074,516

Consolidated statements of oper

Consolidated statements of operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues:
Total revenues	$ 1,920,796	$ 1,394,075	$ 677,192
Costs and expenses:
Lease operating expenses	173,983	101,994	82,020
Production and ad valorem taxes	110,997	68,742	33,050
General and administrative	68,082	62,801	50,534
Organizational restructuring expenses	10,420	9,800	4,200
Depletion, depreciation and amortization	311,640	215,355	217,101
Impairment expense	40	1,613	899,039
Other operating expenses, net	8,583	6,381	7,466
Total costs and expenses	859,555	765,663	1,538,199
Gain (loss) on disposal of assets, net	(1,079)	84,551	(963)
Operating income (expense)	1,060,162	712,963	(861,970)
Non-operating income (expense):
Gain (loss) on derivatives, net	(298,723)	(452,175)	80,114
Interest expense	(125,121)	(113,385)	(105,009)
Gain (loss) extinguishment of debt, net	(1,459)	0	8,989
Other income (expense), net	2,155	1,250	(243)
Total non-operating expense, net	(423,148)	(564,310)	(16,149)
Income (loss) before income taxes	637,014	148,653	(878,119)
Income tax (expense) benefit:
Current	(6,121)	(1,324)	0
Deferred	619	(2,321)	3,946
Total income tax (expense) benefit	(5,502)	(3,645)	3,946
Net income (loss)	$ 631,512	$ 145,008	$ (874,173)
Net income (loss) per common share:
Basic (in USD per share)	$ 37.88	$ 10.18	$ (74.92)
Diluted (in USD per share)	$ 37.44	$ 10.03	$ (74.92)
Weighted-average common shares outstanding:
Basic (in shares)	16,672	14,240	11,668
Diluted (in shares)	16,867	14,464	11,668
Oil sales
Revenues:
Total revenues	$ 1,351,207	$ 805,448	$ 367,792
NGL sales
Revenues:
Total revenues	234,613	191,591	78,246
Natural gas sales
Revenues:
Total revenues	208,554	150,104	50,317
Sales of purchased oil
Revenues:
Total revenues	119,408	240,303	172,588
Costs and expenses:
Costs of goods and services sold	122,118	251,061	194,862
Other operating revenues
Revenues:
Total revenues	7,014	6,629	8,249
Transportation and marketing expenses
Costs and expenses:
Costs of goods and services sold	$ 53,692	$ 47,916	$ 49,927

Consolidated statements of stoc

Consolidated statements of stockholders' equity - USD ($) $ in Thousands	Total	Common stock	Additional paid-in capital	Treasury stock (at cost)	Accumulated deficit
Balance at beginning of year (in shares) at Dec. 31, 2019		11,865,000
Balance at beginning of year at Dec. 31, 2019	$ 841,874	$ 2,373	$ 2,385,355	$ 0	$ (1,545,854)
Balance at beginning of year (in shares) at Dec. 31, 2019				0
Increase (Decrease) in Stockholders' Equity
Reverse stock split	0	$ (2,277)	2,277
Restricted stock awards (in shares)		238,000
Restricted stock awards	0	$ 31	(31)
Restricted stock forfeitures (in shares)		(48,000)
Restricted stock forfeitures	0	$ (2)	2
Stock exchanged for tax withholding (in shares)				35,000
Stock exchanged for tax withholding	(779)			$ (779)
Retirement of treasury stock (in shares)		(35,000)		(35,000)
Retirement of treasury stock	0	$ (5)	(774)	$ 779
Share-settled equity-based compensation	11,635		11,635
Net income (loss)	(874,173)				(874,173)
Balance at end of year (in shares) at Dec. 31, 2020		12,020,000
Balance at end of year at Dec. 31, 2020	(21,443)	$ 120	2,398,464	$ 0	(2,420,027)
Balance at end of year (in shares) at Dec. 31, 2020				0
Increase (Decrease) in Stockholders' Equity
Restricted stock awards (in shares)		237,000
Restricted stock awards	0	$ 2	(2)
Restricted stock forfeitures (in shares)		(42,000)
Stock exchanged for tax withholding (in shares)				53,000
Stock exchanged for tax withholding	(2,596)			$ (2,596)
Retirement of treasury stock (in shares)		(53,000)		(53,000)
Retirement of treasury stock	0	$ 0	(2,596)	$ 2,596
Exercise of stock options (in shares)		2,000
Exercise of stock options	173		173
Share-settled equity-based compensation	9,258		9,258
Issuance of common stock, net of costs (in shares)		1,438,000
Issuance of common stock, net of costs	72,492	$ 14	72,478
Equity issued for acquisition of oil and natural gas properties (in shares)		3,467,000
Equity issued for acquisitions of oil and natural gas properties	310,888	$ 35	310,853
Performance share conversion (in shares)		6,000
Net income (loss)	$ 145,008				145,008
Balance at end of year (in shares) at Dec. 31, 2021	17,074,516	17,075,000
Balance at end of year at Dec. 31, 2021	$ 513,780	$ 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)		255,000
Restricted stock awards	0	$ 3	(3)
Restricted stock forfeitures (in shares)		(58,000)
Restricted stock forfeitures	0	$ (1)	1
Share repurchases (in shares)				491,000
Share repurchases	(37,290)			$ (37,290)
Stock exchanged for tax withholding (in shares)				94,000
Stock exchanged for tax withholding	(7,442)			$ (7,442)
Retirement of treasury stock (in shares)		(585,000)		(585,000)
Retirement of treasury stock	0	$ (6)	(44,726)	$ 44,732
Share-settled equity-based compensation	10,186		10,186
Performance share conversion (in shares)		75,000
Performance share conversion	0	$ 1	(1)
Net income (loss)	$ 631,512				631,512
Balance at end of year (in shares) at Dec. 31, 2022	16,762,127	16,762,000
Balance at end of year at Dec. 31, 2022	$ 1,110,746	$ 168	$ 2,754,085	$ 0	$ (1,643,507)
Balance at end of year (in shares) at Dec. 31, 2022				0

Consolidated statements of cash

Consolidated statements of cash flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flows from operating activities:
Net income (loss)	$ 631,512	$ 145,008	$ (874,173)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Share-settled equity-based compensation, net	8,403	7,675	8,217
Depletion, depreciation and amortization	311,640	215,355	217,101
Impairment expense	40	1,613	899,039
(Gain) loss on disposal of assets, net	1,079	(84,551)	963
Mark-to-market on derivatives:
(Gain) loss on derivatives, net	298,723	452,175	(80,114)
Settlements (paid) received for matured derivatives, net	(486,173)	(320,868)	228,221
Settlements received for early-terminated commodity derivatives, net	0	0	6,340
Premiums received (paid) for commodity derivatives	0	9,041	(51,070)
Amortization of debt issuance costs	6,338	5,146	4,321
Amortization of operating lease right-of-use assets	22,621	13,609	13,070
(Gain) loss on extinguishment of debt, net	1,459	0	(8,989)
Deferred income tax (benefit) expense	(619)	2,321	(3,946)
Other, net	5,494	4,633	4,369
Changes in operating assets and liabilities:
Accounts receivable, net	(9,226)	(87,831)	21,117
Other current assets	8,370	(8,767)	6,275
Other noncurrent assets, net	1,837	(8,782)	(6,768)
Accounts payable and accrued liabilities	31,534	31,387	(2,242)
Undistributed revenue and royalties	42,085	81,201	(8,395)
Other current liabilities	(18,503)	33,331	19,944
Other noncurrent liabilities	(26,994)	4,975	(9,890)
Net cash provided by operating activities	829,620	496,671	383,390
Cash flows from investing activities:
Acquisitions of oil and natural gas properties, net	(5,581)	(763,411)	(35,786)
Capital expenditures:
Oil and natural gas properties	(566,989)	(418,362)	(347,359)
Midstream service assets	(1,436)	(2,849)	(3,171)
Other fixed assets	(12,711)	(5,931)	(4,259)
Proceeds from dispositions of capital assets, net of selling costs	108,888	393,742	1,337
Settlements received for contingent consideration	1,877	0	0
Net cash used in investing activities	(475,952)	(796,811)	(389,238)
Cash flows from financing activities:
Borrowings on Senior Secured Credit Facility	455,000	570,000	80,000
Payments on Senior Secured Credit Facility	(490,000)	(720,000)	(200,000)
Extinguishment of debt	(282,902)	0	(846,994)
Proceeds from issuance of common stock, net of offering costs	0	72,492	0
Share repurchases	(37,290)	0	0
Stock exchanged for tax withholding	(7,442)	(2,596)	(779)
Payments for debt issuance costs	(1,938)	(14,686)	(18,479)
Other, net	(1,459)	2,971	0
Net cash (used in) provided by financing activities	(366,031)	308,181	13,748
Net (decrease) increase in cash and cash equivalents	(12,363)	8,041	7,900
Cash and cash equivalents, beginning of period	56,798	48,757	40,857
Cash and cash equivalents, end of period	44,435	56,798	48,757
January 2025 Notes & January 2028 Notes
Cash flows from financing activities:
Issuance of Notes	0	0	1,000,000
July 2029 Notes
Cash flows from financing activities:
Issuance of Notes	$ 0	$ 400,000	$ 0

Organization

Organization	12 Months Ended
	Dec. 31, 2022
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, 2022
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. Reclassifications Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. There was no impact on previously reported total assets, total liabilities, net income (loss) or stockholders' equity for the periods presented. 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) depletion, depreciation and amortization, (iv) impairments, (v) income taxes, (vi) fair values of assets acquired and liabilities assumed in an acquisition, (vii) fair values of derivatives and (viii) 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, 2022 December 31, 2021 Oil, NGL and natural gas sales (1) $ 111,260 $ 135,560 Joint operations, net (2) 35,801 11,491 Other 16,308 4,756 Total accounts receivable, net $ 163,369 $ 151,807 _____________________________________________________________________________ (1) For purchasers that the Company has netting arrangements with, the amounts presented include the net positions. (2) Accounts receivable for joint operations are presented net of an allowance for expected credit losses of $0.4 million as of both December 31, 2022 and 2021. As the operator of the majority of its wells, the Company has the ability to realize some or all of these receivables through the netting of revenues. 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, net 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" under "Non-operating income (expense)" on the consolidated statements of operations. See Notes 11 and 12 for additional discussion of derivatives and their fair value measurement on a recurring basis, respectively. Other current assets and liabilities Other current assets consisted of the following components as of the dates presented: (in thousands) December 31, 2022 December 31, 2021 Prepaid expenses and other $ 7,247 $ 12,746 Inventory 6,070 10,160 Total other current assets $ 13,317 $ 22,906 Other current liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2022 December 31, 2021 Accrued interest payable $ 43,984 $ 56,468 Accrued compensation and benefits 20,000 14,434 Other liabilities 18,966 28,569 Total other current liabilities $ 82,950 $ 99,471 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 incurred capital expenditures 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 2027 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 inventory impairments. 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) 2022 2021 Liability at beginning of year $ 72,003 $ 68,326 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 362 14,610 Accretion expense (1) 3,879 4,233 Liabilities settled due to plugging and abandonment or removed due to sale (2,163) (15,186) Revision of estimates — 20 Liability at end of year 74,081 72,003 Less: current asset retirement obligations (2) 3,715 2,946 Non-current asset retirement obligations $ 70,366 $ 69,057 ______________________________________________________________________________ (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 or (ii) stock exchanged for the cost of exercise of stock options at the awardee's election. 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) 2022 2021 2020 Sales of purchased oil inventory $ 104,403 $ 327,839 $ 17,026 Purchased oil inventory 104,039 326,625 16,918 Net effect on earnings (1) $ 364 $ 1,214 $ 108 ______________________________________________________________________________ (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 existing contracts, 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; therefore, the Company recognizes revenue based on the net amount of the proceeds received from the midstream processing entity who represents the Company's customer. If for future contracts the Company was to conclude that it was the principal with the ultimate third party being the customer, the Company would recognize 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, 2022, 2021 and 2020, 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, performance share awards and the outperformance share award, 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 (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, 2022 or 2021. 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) 2022 2021 2020 Supplemental cash flow information: Cash paid for interest, net of $3,872, $5,866 and $3,019 of capitalized interest, respectively (1) $ 131,867 $ 94,867 $ 77,401 Supplemental non-cash operating information: Right-of-use assets obtained in exchange for operating lease liabilities (2) $ 34,532 $ 7,742 $ 2,349 Supplemental non-cash investing information: Fair value of contingent consideration asset (liability) on transaction closing date (3) $ — $ 33,832 $ (225) Change in accrued capital expenditures $ (2,207) $ 22,310 $ (8,053) Capitalized asset retirement cost $ 362 $ 14,610 $ 2,252 ______________________________________________________________________________ (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 acquisitions and divestiture of oil and natural gas properties that include contingent considerations. See Note 12 for discussion of the quarterly remeasurement of the respective contingent considerations.

New accounting standards

New accounting standards	12 Months Ended
	Dec. 31, 2022
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 ("ASC") and has determined there are no ASUs that are not yet adopted and meaningful to disclose as of December 31, 2022. Additionally, the Company did not adopt any new ASUs during the year ended December 31, 2022.

Acquisitions and divestitures

Acquisitions and divestitures	12 Months Ended
	Dec. 31, 2022
Business Combination and Asset Acquisition [Abstract]
Acquisitions and divestitures	Note 4 Acquisitions and divestitures 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 $106.5 million, inclusive of customary closing adjustments, subject to post-closing adjustments. 2021 Asset acquisitions and divestiture Pioneer Acquisition On September 17, 2021, the Company entered into a purchase and sale agreement (the "Pioneer PSA") with Pioneer Natural Resources USA, Inc ("PXD"), DE Midland III, LLC ("DEM"), Parsley Minerals, LLC ("PM") and Parsley Energy, L.P. ("PE" and collectively with PXD, DEM, and PM, "the Seller") pursuant to which the Company agreed to purchase (the "Pioneer Acquisition"), effective as of July 1, 2021, certain oil and natural gas properties in the Midland Basin, including approximately 20,000 net acres, and approximately 135 gross (121 net) operated locations, located in western Glasscock County, Texas, as well as related assets and contracts (the "Pioneer Assets"). On October 18, 2021 ("Pioneer Closing Date"), the Company closed the Pioneer Acquisition for an aggregate purchase price of $210.1 million, comprised of (i) $135.3 million in cash, (ii) 959,691 shares of the Company's common stock, par value $0.01 per share (the "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 Company determined that the Pioneer 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. The following table presents components of the purchase price, inclusive of customary closing adjustments: (in thousands, except for share and share price data) As of October 18, 2021 Shares of Company common stock 959,691 Company common stock price at the Pioneer Closing Date $ 73.90 Value of Company common stock consideration $ 70,921 Cash consideration $ 135,323 Transaction costs 3,861 Total purchase price $ 210,105 The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on the Pioneer Closing Date: (in thousands) As of October 18, 2021 Evaluated properties $ 143,021 Unevaluated properties 74,468 Revenue suspense liabilities assumed (7,384) Allocated purchase price $ 210,105 The Company funded the cash portion of the aggregate purchase price and related transaction costs with respect to the Pioneer Acquisition with cash on hand and borrowings under its Senior Secured Credit Facility. 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 May 7, 2021, the Company entered into two separate purchase and sale agreements, one (the "Sabalo PSA") with Sabalo Energy, LLC and its subsidiary, Sabalo Operating, LLC (collectively, "Sabalo"), and the other (the "Shad PSA" and together with the Sabalo PSA, the "Sabalo/Shad PSAs") with Shad Permian, LLC ("Shad") to acquire certain Midland Basin oil and natural gas properties, including approximately 21,000 net acres and approximately 120 gross (109 net) operated locations and approximately 150 gross (18 net) non-operated locations, located in Howard and Borden Counties, Texas, (collectively, the "Sabalo/Shad Acquisition"). Sabalo and Shad are unaffiliated, but owned interest in the same assets. On July 1, 2021 ("Sabalo/Shad Closing Date"), the Company closed the Sabalo/Shad Acquisition, effective April 1, 2021, for an aggregate purchase price of $863.1 million, comprised of (i) $606.1 million in cash (ii) 2,506,964 shares of the Company's 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 closing adjustments. The Sabalo/Shad Acquisition was accounted for as a single transaction because the Sabalo PSA and Shad PSA 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. The following table presents components of the purchase price, inclusive of customary closing adjustments: (in thousands, except for share and share price data) As of July 1, 2021 Shares of Company common stock 2,506,964 Company common stock price at the Sabalo/Shad Closing Date $ 95.72 Value of Company common stock consideration $ 239,967 Cash consideration $ 606,126 Transaction costs 17,020 Total purchase price $ 863,113 The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on the Sabalo/Shad Closing Date: (in thousands) As of July 1, 2021 Evaluated properties $ 503,005 Unevaluated properties 362,977 Revenue suspense liabilities assumed (4,269) Inventory 1,400 Allocated purchase price $ 863,113 The Company funded the cash portion of the aggregate purchase price and related transaction costs with respect to the Sabalo/Shad Acquisition with proceeds from borrowings under its Senior Secured Credit Facility (as defined in Note 7) and the Working Interest Sale described below. 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. 2020 Asset acquisitions On February 4, 2020, the Company closed a transaction for $22.5 million, acquiring 1,180 net acres and divesting 80 net acres in Howard County, Texas. All transaction costs were capitalized and are included in "Oil and natural gas properties, net" on the consolidated balance sheet. 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, 2022
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) 2022 2021 Operating lease costs (1) $ 24,174 $ 15,894 Short-term lease costs (2) 110,442 83,471 Variable lease costs (3) 11,328 6,873 Sublease income (990) (1,057) Total lease costs, net $ 144,954 $ 105,181 _____________________________________________________________________________ (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 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 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) 2022 2021 Operating cash flows from operating leases $ 3,892 $ 4,065 Investing cash flows from operating leases (1) $ 20,398 $ 12,569 _____________________________________________________________________________ (1) Amounts associated with drilling 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, 2022 December 31, 2021 Weighted-average remaining lease term 1.91 years 2.80 years Weighted-average discount rate 5.84 % 7.41 % 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, 2022 2023 $ 16,467 2024 6,789 2025 1,350 2026 1,348 2027 666 Total minimum lease payments 26,620 Less: imputed interest (1,736) Present value of future minimum lease payments $ 24,884 Other information See Note 2 for disclosure of supplemental non-cash adjustments information related to operating leases and Note 18 for disclosure of significant leases not yet commenced as of December 31, 2022.

Property and equipment

Property and equipment	12 Months Ended
	Dec. 31, 2022
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) 2022 2021 2020 Capitalized employee-related costs $ 17,026 $ 18,255 $ 18,954 See Note 19 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) 2022 2021 2020 Depletion expense of evaluated oil and natural gas properties $ 298,259 $ 201,691 $ 203,492 Depletion expense per BOE sold $ 9.92 $ 6.76 $ 6.34 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 2022 and 2021. The following table presents the Benchmark Prices and the Realized Prices as of the dates presented: December 31, 2022 December 31, 2021 December 31, 2020 Benchmark Prices: Oil ($/Bbl) $ 90.15 $ 63.04 $ 36.04 NGL ($/Bbl) (1) $ 41.77 $ 34.51 $ 16.63 Natural gas ($/MMBtu) $ 5.20 $ 3.35 $ 1.21 Realized Prices: Oil ($/Bbl) $ 96.21 $ 66.37 $ 37.69 NGL ($/Bbl) $ 29.84 $ 22.90 $ 7.43 Natural gas ($/Mcf) $ 4.24 $ 2.61 $ 0.79 _____________________________________________________________________________ (1) Based on the Company's average composite NGL barrel. The following table presents full cost ceiling impairment expense, which is included in "Impairment expense" on the consolidated statements of operations for the periods presented: Years ended December 31, (in thousands) 2022 2021 2020 Full cost ceiling impairment expense $ — $ — $ 889,453 Midstream service assets Midstream service assets, which 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, are recorded at cost, net of impairment. Depreciation of assets is recorded using the straight-line method based on estimated useful lives of 10 to 20 years, as applicable. 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 "Loss on disposal of assets, net" in the consolidated statements of operations. Midstream service assets consisted of the following components as of the dates presented: (in thousands) December 31, 2022 December 31, 2021 Midstream service assets $ 151,157 $ 165,232 Less accumulated depreciation and impairment (66,001) (68,704) Total midstream service assets, net $ 85,156 $ 96,528 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. During the year ended December 31, 2021, the Company retired $18.8 million in midstream service assets, resulting in the removal of $9.4 million in accumulated depreciation and the recognition of an associated loss of $9.4 million. Other fixed assets Other fixed assets are recorded at cost and are subject to depreciation and amortization. Land is recorded at cost and is not subject to depreciation. Depreciation and amortization of other fixed assets is provided using the straight-line method based on estimated useful lives of three Other fixed assets consisted of the following components as of the dates presented: (in thousands) December 31, 2022 December 31, 2021 Computer hardware and software $ 21,758 $ 15,039 Vehicles 7,934 9,072 Leasehold improvements 7,136 7,136 Buildings 7,039 7,039 Other 6,087 5,095 Depreciable total 49,954 43,381 Less accumulated depreciation and amortization (30,382) (27,692) Depreciable total, net 19,572 15,689 Land 23,075 18,901 Total other fixed assets, net $ 42,647 $ 34,590

Debt

Debt	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
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: December 31, 2022 December 31, 2021 (in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net January 2025 Notes 455,628 (3,297) 452,331 577,913 (6,345) 571,568 January 2028 Notes 300,309 (3,478) 296,831 361,044 (5,024) 356,020 July 2029 Notes 298,214 (4,353) 293,861 400,000 (6,730) 393,270 Senior Secured Credit Facility (1) 70,000 — 70,000 105,000 — 105,000 Total $ 1,124,151 $ (11,128) $ 1,113,023 $ 1,443,957 $ (18,099) $ 1,425,858 _____________________________________________________________________________ (1) Debt issuance costs, net related to the Senior Secured Credit Facility of $7.3 million and $8.1 million as of December 31, 2022 and 2021, 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 Year ended Year ended January 2025 Notes $ 122,285 $ — $ 22,087 January 2028 Notes 60,735 — 38,956 January 2029 Notes 101,786 — — Total principal amount repurchased $ 284,806 $ — $ 61,043 Less: Consideration paid $ 282,902 $ — $ 38,139 Write off of debt issuance costs 3,363 — 595 Gain (loss) on extinguishment of debt, net (1) $ (1,459) $ — $ 22,309 Senior Secured Credit Facility On April 13, 2022, the Company entered into the Eighth Amendment to the Senior Secured Credit Facility (the "Eighth Amendment"). The Eighth Amendment, among other things, (i) increased the borrowing base from $1.0 billion to $1.25 billion and the aggregate elected commitment from $725.0 million to $1.0 billion, (ii) increased, from closing through December 31, 2022, the $50.0 million bond buyback and distributions baskets to $250.0 million, subject to certain conditions, (iii) added an energy transition and technology commercialization investment basket of $25.0 million, subject to certain conditions, (iv) allows for the designation of unrestricted subsidiaries and (v) amended certain other provisions relating to certain commercial agreements and the administration of Loans, in each case, subject to the terms of the Eighth Amendment and the Senior Secured Credit Facility. On August 30, 2022, the Company entered into the Ninth Amendment to the Senior Secured Credit Facility (the "Ninth Amendment"). The Ninth Amendment, among other things, (i) added additional capacity to making repurchases of the Company's common stock and (ii) clarified the conditions to making redemptions of the Company's debt. On November 1, 2022, the Company entered into the Tenth Amendment to the Senior Secured Credit Facility (the "Tenth Amendment"). The Tenth Amendment, among other things, (i) increased the borrowing base from $1.25 billion to $1.3 billion, (ii) permitted additional senior note buybacks and other restricted payments, subject to certain conditions; and (iii) made technical changes to permit the Company to potentially incur term loans, subject to terms to be agreed with lenders making such term loans, in addition to revolving loans, in each case, subject to the terms of the Tenth Amendment and the Senior Secured Credit Facility. As of December 31, 2022, the Senior Secured Credit Facility, which matures on July 16, 2025 (subject to a springing maturity date of July 29, 2024 if any of the January 2025 Notes are outstanding on such date), had a maximum credit amount of $2.0 billion, a borrowing base and an aggregate elected commitment of $1.3 billion and $1.0 billion, respectively, with a $70.0 million balance outstanding, and was subject to an interest rate of 6.897%. 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 1.50% to 2.50%, 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 2.50% to 3.50%, 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 of 0.5%. The Senior Secured Credit Facility is secured by a first-priority lien on Vital and the Guarantors' assets and stock, 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, 2022 and 2021, as then in effect. The Company's measurements of Adjusted EBITDA (non-GAAP) for financial reporting differs from the measurement used for compliance under its debt agreements. 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, 2021, the Company had one letter of credit outstanding of $44.1 million under the Senior Secured Credit Facility. No letters of credit were outstanding under the Senior Secured Credit Facility as of December 31, 2022. See Note 18 for discussion of a borrowing and repayment on the Senior Secured Credit Facility subsequent to December 31, 2022. 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 terms of the July 2029 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, 2022 and 2021. As of December 31, 2022, the July 2029 Notes are fully and unconditionally guaranteed on a senior unsecured basis by VMS, GCM 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 (collectively, the "Releases"). On February 3, 2023, GCM was merged with and into Vital Energy, Inc. and is therefore no longer a guarantor under any of the Company's debt arrangements. 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 "January 2028 Notes"). Interest for both the January 2025 Notes and January 2028 Notes is payable semi-annually, in cash in arrears on January 15 and July 15 of each year. The terms of the January 2025 Notes and January 2028 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, 2022 and 2021. As of December 31, 2022, the January 2025 Notes and January 2028 Notes are fully and unconditionally guaranteed on a senior unsecured basis by VMS, GCM and certain of the Company's future restricted subsidiaries, subject to certain Releases. On February 3, 2023, GCM was merged with and into Vital Energy, Inc. and is therefore no longer a guarantor under any of the Company's debt arrangements. 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 January 2022 Notes and March 2023 Notes 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. January 2022 Notes and March 2023 Notes In January 2020, the Company commenced cash tender offers and consent solicitations for any or all of the $450.0 million and $350.0 million aggregate principle amounts outstanding on the previously disclosed January 2022 Notes and March 2023 Notes, respectively (collectively, the "Tender Offers"). During the first quarter of 2020, the Company settled the Tender Offers for aggregate principle outstanding amounts of $728.3 million for consideration for tender offers and early tender premiums of $735.7 million, plus accrued and unpaid interest. Following the settlement of the tender offers, the Company redeemed the remaining $71.7 million outstanding balances of both notes. The Company recognized a loss on extinguishment of $13.3 million related to the difference between the consideration for tender offers, early tender premiums and redemption prices and the net carrying amounts of the extinguished January 2022 Notes and March 2023 Notes which is included in "Gain (loss) on extinguishment of debt, net" on the consolidated statements of operations. Interest expense The following table presents amounts that have been incurred and charged to interest expense: Years ended December 31, (in thousands) 2022 2021 2020 Interest expense on borrowings $ 123,255 $ 114,800 $ 104,320 Amortization of debt issuance costs and other adjustments 5,738 4,451 3,708 Less capitalized interest 3,872 5,866 3,019 Total interest expense $ 125,121 $ 113,385 $ 105,009

Stockholders' equity

Stockholders' equity	12 Months Ended
	Dec. 31, 2022
Equity [Abstract]
Stockholders' equity	Note 8 Stockholders' equity Authorized shares increase On May 26, 2022, upon recommendation of the Company's board of directors, stockholders approved an amendment to the Company's Amended and Restated Certificate of Incorporation to increase the number of authorized shares of its common stock from 22,500,000 shares to 40,000,000 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, 2021 and 2020. ATM Program On February 23, 2021, the Company entered into an equity distribution agreement (the "Equity Distribution Agreement") with Wells Fargo Securities, LLC acting as sales agent and/or principal (the "Sales Agent"), pursuant to which the Company may offer and sell, from time to time 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"). Pursuant to the Equity Distribution Agreement, shares of common stock may be offered and sold in privately negotiated transactions or transactions that are deemed to be "at-the-market" offerings as defined in Rule 415 under the Securities Act, including by ordinary brokers’ transactions through the facilities of the New York Stock Exchange, to or through a market maker or as otherwise agreed with the Sales Agent. Under the terms of the Equity Distribution Agreement, the Company may also sell common stock from time to time to the Sales Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common stock to the Sales Agent as principal would be pursuant to the terms of a separate terms agreement between the Company and the Sales Agent, which would be described in a separate prospectus supplement or pricing supplement. 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. Reverse stock split and reduction of authorized shares On June 1, 2020, the amendment to the Company's amended and restated certificate of incorporation became effective and effected the 1-for-20 reverse stock split of the Company's issued and outstanding common stock and the related reduction of the number of authorized shares of common stock from 450,000,000 to 22,500,000 authorized shares, par value $0.01 per share, with authorized shares of preferred stock remaining unchanged at 50,000,000, par value $0.01 per share, for a total of 72,500,000 shares of capital stock. See Note 9 for discussion of the Vital Energy, Inc. Omnibus Equity Incentive Plan (the "Equity Incentive Plan"), that proportionately reduced the number of shares that may be granted.

Compensation plans

Compensation plans	12 Months Ended
	Dec. 31, 2022
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 June 1, 2020, in connection with the effectiveness of the reverse stock split and Authorized Share Reduction, the board of directors approved and adopted an amendment to the Equity Incentive Plan to proportionately adjust the limitations on awards that may be granted under the Equity Incentive Plan. Following the amendment, an aggregate of 1,492,500 shares may be issued under the Equity Incentive Plan. See Note 8 for additional discussion of the reverse stock split and Authorized Share Reduction. 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. At December 31, 2022, 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 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 first anniversary of the grant date. Restricted stock awards granted to non-employee directors vest immediately on the grant date. 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 at the start of the calendar year in which the award is granted. For performance share awards granted in 2022, the market criteria consists of: (i) annual relative total shareholder return comparing the Company's shareholder return to the shareholder return of the exploration and production companies listed in the Russell 2000 Index and (ii) annual absolute total shareholder return. The performance criteria for these awards consists of: (i) earnings before interest, taxes, depreciation, amortization and exploration expense and three-year total debt reduction, (ii) growth in inventory and (iii) emissions reduction targets. 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%. For performance share awards granted in 2019, the market criteria consists of: (i) the relative three-year total shareholder return ("TSR") comparing the Company's shareholder return to the shareholder return of the peer group specified in each award agreement ("RTSR Performance Percentage"), and (ii) the Company's absolute three-year total shareholder return ("ATSR Appreciation"). The performance criteria for these awards consists of the Company's three-year return on average capital employed ("ROACE Percentage"). Potential payout of these awards ranged from 0% to 200%. In the first quarter of 2022, following the completion of the requisite service period and achievement of certain market and performance criteria, these shares were issued at 107% payout. Equity award activity The following table presents activity for equity compensation awards for the year ended December 31, 2022: (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, 2021 350 $35.57 7 $275.88 72 $64.74 Granted 255 $67.54 — 62 $89.76 Forfeited (58) $46.75 — (16) $88.28 Vested (1)(2) (185) $42.30 — (70) $64.53 Expired or canceled — (4) $313.12 — Outstanding as of December 31, 2022 (3) 362 $52.90 3 $235.08 48 $89.76 _____________________________________________________________________________ (1) The aggregate intrinsic value of vested restricted stock awards for the year ended December 31, 2022 was $14.6 million. (2) The performance share awards granted on February 28, 2019 and June 3, 2019 had a performance period of January 1, 2019 to December 31, 2021 and, as their market and performance criteria were satisfied, resulted in a 107% payout. As such, the granted awards vested and were converted into 75,107 shares of the Company's common stock during the year ended December 31, 2022 based on this 107% payout. (3) The vested and exercisable stock option awards as of December 31, 2022 had no intrinsic value. As of December 31, 2022, total unrecognized cost related to equity compensation awards was $16.0 million, which will be settled in shares. Such cost will be recognized on a straight-line basis over an expected weighted-average period of 2.02 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 2021, the market criteria consists of: (i) annual relative shareholder return comparing the Company's shareholder return to the shareholder return of the E&P companies listed in the Russell 2000 index and (ii) annual absolute total shareholder 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") and (ii) growth in inventory (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 can range from 0% to 250% for the market criteria and 0% to 200% for the performance criteria. 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. 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 200%, but is capped at 100% if the ATSR Appreciation is zero or less. The performance period for the performance unit awards granted March 5, 2020 ended December 31, 2022. As their market and performance criteria were fully satisfied, resulting in a 151% payout, the granted awards will be paid in cash during the first quarter of 2023. 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, 2022: (in thousands) Performance Unit Awards Phantom Unit Awards Outstanding as of December 31, 2021 209 33 Forfeited (59) — Vested (1) — (15) Outstanding as of December 31, 2022 150 18 _____________________________________________________________________________ (1) On March 1, 2022 and March 5, 2022, the vested phantom unit awards were settled and paid out in cash at a fair value of $76.60 and $83.00 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, 2022 was $51.42. As of December 31, 2022, total unrecognized cost related to equity-based liability awards was $3.1 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 1.05 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, 2022 for the grant dates presented: Performance Share Awards Performance Unit Awards February 22, 2022 March 9, 2021 Remaining performance period on grant date 2.86 years n/a Remaining performance period n/a 1 year Risk-free interest rate (1) 1.71 % 4.62 % Dividend yield — % — % Expected volatility (2) 119.25 % 79.77 % Expense per performance share or unit as of December 31, 2022 $89.76 $79.85 ______________________________________________________________________________ (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 5, 2020 had a performance period of January 1, 2020 to December 31, 2022. As of December 31, 2022, their expense per performance unit was $78.92 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) 2022 2021 2020 Equity awards: Restricted stock awards $ 8,596 $ 7,594 $ 8,839 Performance share awards 1,590 1,657 2,719 Stock option awards — 7 77 Total share-settled equity-based compensation, gross $ 10,186 $ 9,258 $ 11,635 Less amounts capitalized (1,783) (1,583) (3,418) Total share-settled equity-based compensation, net $ 8,403 $ 7,675 $ 8,217 Liability awards: Performance unit awards $ 741 $ 7,480 $ 749 Phantom unit awards 1,186 1,238 404 Total cash-settled equity-based compensation, gross $ 1,927 $ 8,718 $ 1,153 Less amounts capitalized (272) (365) (163) Total cash-settled equity-based compensation, net $ 1,655 $ 8,353 $ 990 Total equity-based compensation, net $ 10,058 $ 16,028 $ 9,207 See Note 17 for discussion of the Company's organizational restructurings and the related equity-based compensation reversals during the years ended December 31, 2022, 2021 and 2020.

Net income (loss) per common sh

Net income (loss) per common share	12 Months Ended
	Dec. 31, 2022
Earnings Per Share [Abstract]
Net income (loss) per common share	Note 10 Net income (loss) per common share Basic and diluted net income (loss) per common share are computed by dividing net income (loss) by the weighted-average common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution of non-vested equity-based compensation awards. See Note 9 for additional discussion of these awards. For the year ended December 31, 2020, all of these awards were anti-dilutive to the Company's net loss and, therefore, were excluded from the calculation of diluted net loss per common share. The following table reflects the calculations of basic and diluted (i) weighted-average common shares outstanding and (ii) net income (loss) per common share for the periods presented: Years ended December 31, (in thousands, except for per share data) 2022 2021 2020 Net income (loss) $ 631,512 $ 145,008 $ (874,173) Weighted-average common shares outstanding: Basic 16,672 14,240 11,668 Dilutive non-vested restricted stock awards 183 181 — Dilutive non-vested performance share awards (1) 12 43 — Diluted 16,867 14,464 11,668 Net income (loss) per common share: Basic $ 37.88 $ 10.18 $ (74.92) Diluted $ 37.44 $ 10.03 $ (74.92) _____________________________________________________________________________ (1) The dilutive effect of the non-vested performance shares for the year ended December 31, 2022 was calculated as of the end of the performance period on December 31, 2022.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Note 11 Derivatives The Company has two types of derivative instruments as of December 31, 2022: (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 Notes (i) 2 for the Company's significant accounting policies for derivatives and presentation in the consolidated financial statements, (ii) 12 for fair value measurement of derivatives on a recurring basis and (iii) 18 for derivatives subsequent events. 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) 2022 2021 2020 Commodity $ (291,973) $ (453,784) $ 73,662 Contingent consideration (6,764) 1,639 6,795 Interest rate 14 (30) (343) Gain (loss) on derivatives, net $ (298,723) $ (452,175) $ 80,114 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, 2022, the Company's derivatives were settled based on reported prices on commodity exchanges, with (i) oil derivatives settled based on WTI NYMEX and Brent ICE pricing, (ii) NGL derivatives settled based on Mont Belvieu OPIS pricing and (iii) 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, 2022, for commodity derivatives that were entered into through December 31, 2022, for the settlement periods presented: Year 2023 Oil: WTI NYMEX - Collars: Volume (Bbl) 5,089,000 Weighted-average floor price ($/Bbl) $ 68.58 Weighted-average ceiling price ($/Bbl) $ 84.88 Natural gas: Henry Hub NYMEX - Collars: Volume (MMBtu) 25,550,000 Weighted-average floor price ($/MMBtu) $ 4.14 Weighted-average ceiling price ($/MMBtu) $ 8.43 Waha Inside FERC to Henry Hub NYMEX - Basis Swaps: Volume (MMBtu) 25,550,000 Weighted-average differential ($/MMBtu) $ (1.65) 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, 2022, the maximum remaining additional cash consideration of the contingent consideration was $88.9 million. The fair value of the Sixth Street Contingent Consideration was determined to be $26.6 million as of December 31, 2022 and $35.9 million as of December 31, 2021. See Note 4 for further discussion of the Working Interest Sale associated with the Sixth Street Contingent Consideration. Interest rate swap

Fair value measurements

Fair value measurements	12 Months Ended
	Dec. 31, 2022
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, (ii) 11 for derivatives and (iii) 18 for derivatives subsequent events. 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, 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 December 31, 2021 (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 $ — $ 21,671 $ — $ 21,671 $ (21,671) $ — Contingent consideration — — 4,346 4,346 — 4,346 Noncurrent: Commodity — 1,448 — 1,448 — 1,448 Contingent consideration — — 31,515 31,515 — 31,515 Liabilities: Current: Commodity — (201,428) — (201,428) 21,671 (179,757) Interest rate — (52) — (52) — (52) Net derivative asset (liability) positions $ — $ (178,361) $ 35,861 $ (142,500) $ — $ (142,500) 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" under "Non-operating income (expense)" on the consolidated statement of operations. 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) 2022 2021 2020 Balance of Level 3 at beginning of year $ 35,861 $ — $ — Sixth Street Contingent Consideration valuation as of Sixth Street Closing Date — 33,832 — Change in Sixth Street Contingent Consideration fair value (11,678) 2,029 — Settlements realized (1) 2,457 — — Balance of Level 3 at end of year $ 26,640 $ 35,861 $ — _____________________________________________________________________________ (1) For the year ended December 31, 2022, $1.9 million of realized settlements has been received and is included in "Settlements received for contingent consideration" in cash flows from investing activities on the consolidated statements of cash flows, and $0.6 million is a receivable at period end. 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, 2022 December 31, 2021 (in thousands) Long-term debt Fair value (1) Long-term debt Fair value (1) January 2025 Notes $ 455,628 $ 449,122 $ 577,913 $ 589,471 January 2028 Notes 300,309 292,846 361,044 378,578 July 2029 Notes 298,214 268,416 400,000 390,000 Senior Secured Credit Facility 70,000 69,945 105,000 105,040 Total $ 1,124,151 $ 1,080,329 $ 1,443,957 $ 1,463,089 _____________________________________________________________________________ (1) The fair values of the outstanding notes were determined using the Level 1 fair value hierarchy quoted market prices for each respective instrument as of December 31, 2022 and 2021. 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, 2022 and 2021.

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2022
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 (expense) benefit reported on the consolidated statements of operations for the periods presented: Years ended December 31, (in thousands) 2022 2021 2020 Current income tax (expense) benefit: Federal $ — $ — $ — State (6,121) (1,324) — Deferred income tax (expense) benefit: Federal — — — State 619 (2,321) 3,946 Total income tax (expense) benefit $ (5,502) $ (3,645) $ 3,946 Total income tax (expense) benefit differed from amounts computed by applying the applicable federal income tax rate of 21% for the years ended December 31, 2022, 2021 and 2020 to pre-tax earnings as a result of the following: Years ended December 31, (in thousands) 2022 2021 2020 Income tax (expense) benefit computed by applying the statutory rate $ (133,773) $ (31,217) $ 184,405 Change in deferred tax valuation allowance 144,480 45,717 (182,634) Non-deductible equity-based compensation (19,301) (13,640) — State income tax and change in valuation allowance 8,058 (3,274) 2,903 Other items (4,966) (1,231) (728) Total income tax (expense) benefit $ (5,502) $ (3,645) $ 3,946 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 liability as of the dates presented: (in thousands) December 31, 2022 December 31, 2021 Deferred tax assets: Net operating loss carryforward $ 307,357 $ 445,426 Equity-based compensation 2,933 11,123 Derivatives — 36,639 Other 1,110 3,227 Total deferred tax asset 311,400 496,415 Valuation allowance (298,184) (443,390) Deferred tax assets, net of valuation allowance 13,216 53,025 Deferred tax liabilities: Oil and natural gas properties, midstream service assets and other fixed assets (11,105) (53,868) Derivatives (2,331) — Total deferred tax liabilities (13,436) (53,868) Texas net deferred tax liability (1) $ (220) $ (843) ___________________________________________________________________________ (1) The net deferred tax liability is included in "Other noncurrent liabilities" as of December 31, 2022 and 2021, respectively. As of December 31, 2022, the Company had federal net operating loss carryforwards totaling $1.5 billion which expire between 2033 and 2037 and state of Oklahoma net operating loss carryforwards totaling $34.4 million that will begin expiring in 2032. Due to the passing of the Tax Act, $425.9 million of the federal net operating loss carryforwards will not expire but may be limited in future periods. 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 would be limited. As of December 31, 2022, no ownership change has occurred. Since September 30, 2015, the Company has recorded a full valuation allowance against its federal and Oklahoma net deferred tax position. As such, the Company's effective tax rate is 1%, due to the Texas franchise tax. 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 years ended December 31, 2022, 2021 and 2020, the Company’s items of discrete income tax expense or benefit were not material. A valuation allowance is established to reduce deferred tax assets if it is determined that it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. To the extent a valuation allowance is established or is increased or decreased during a period, there is a corresponding expense or reduction of expense within the tax provision in the consolidated statement of operations. During the years ended December 31, 2022 and 2021, in evaluating whether it was more likely than not that the Company's net deferred tax assets were realizable through future net income, the Company considered all available positive and negative evidence, including projected future cash flows from its oil, NGL and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of December 31, 2022 and the Company's ability to capitalize intangible drilling costs, rather than expensing these costs and future projections of taxable income. Significant items of objective negative evidence considered were the cumulative historical three-year pre-tax loss and net deferred tax asset position. Such objective evidence limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Based on all the evidence available, the Company determined it was more likely than not that the net deferred tax assets were not realizable. The Company files a single return. The Company's income tax returns for the years 2019 through 2022 remain open and subject to examination by federal tax authorities and/or the tax authorities in Oklahoma and Texas, which are the jurisdictions where the Company has operations. Additionally, the statute of limitations for examination of federal net operating loss carryforwards typically does not begin to run until the year the attribute is utilized in a tax return. 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 that applies to certain corporations with adjusted financial statement income in excess of $1.0 billion. The Company continues to evaluate the IRA and its effect on our financial results and operating cash flows.

Credit risk

Credit risk	12 Months Ended
	Dec. 31, 2022
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, 2022, the Company had a net asset position of $16.4 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, 12 and 18 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, 2022 2021 2020 Purchaser A (1) 33 % 29 % 33 % Purchaser B (1) 18 % 14 % n/a (2) Purchaser C 17 % 24 % 24 % Purchaser D (1) n/a (2) 17 % 14 % Purchaser E n/a (2) n/a (2) 10 % _____________________________________________________________________________ (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 in at least one of the years presented: Years ended December 31, 2022 2021 2020 Purchaser A (1) 47 % 47 % 69 % Purchaser B (1) 22 % 31 % 16 % Purchaser C (1) 22 % 22 % 14 % _____________________________________________________________________________ (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.

Commitments and contingencies

Commitments and contingencies	12 Months Ended
	Dec. 31, 2022
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 $13.2 million, $4.4 million and $4.0 million during the years ended December 31, 2022, 2021 and 2020, respectively, which is recorded in "Transportation and marketing expenses" on the consolidated statements of operations. The Company had an estimated aggregate liability of firm transportation payments on excess capacity of $11.5 million and $4.7 million as of December 31, 2022 and 2021, respectively, and is included in "Accounts payable and accrued liabilities" on the consolidated balance sheets.

Related parties

Related parties	12 Months Ended
	Dec. 31, 2022
Related Party Transactions [Abstract]
Related parties	Note 16 Related parties Halliburton Beginning in 2020, 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 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) 2022 2021 2020 Capital expenditures for oil and natural gas properties $ 103,152 $ 69,670 $ 63,886

Organizational restructurings

Organizational restructurings	12 Months Ended
	Dec. 31, 2022
Restructuring and Related Activities [Abstract]
Organizational restructurings	Note 17 Organizational restructurings 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. On June 17, 2020, the Company announced organizational changes, including a workforce reduction of 22 individuals which included a senior officer, that were implemented immediately, subject to certain administrative procedures. The Company's board of directors approved the reduction in workforce in response to the COVID-19 pandemic and market conditions to reduce costs and 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. See Note 9 for additional information on the associated forfeiture activity for the years ended December 31, 2022, 2021 and 2020. 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) 2022 2021 2020 Gross equity-based compensation expense reversals $ (4,908) $ (1,088) $ (793)

Subsequent events

Subsequent events	12 Months Ended
	Dec. 31, 2022
Subsequent Events [Abstract]
Subsequent events	Note 18 Subsequent events 2023 Acquisition On February 14, 2023, the Company entered into a purchase and sale agreement with Driftwood Energy Operating, LLC (the "Seller"), pursuant to which the Company agreed to purchase (the "Driftwood Acquisition") Seller's oil and gas properties in the Midland Basin, including approximately 11,200 net acres located in Upton and Reagan Counties and related assets and contracts, for a purchase price of (i) $127.6 million of cash, subject to customary closing price adjustments, and (ii) 1,578,948 shares of the Company's common stock. The Company currently expects to fund the cash portion of the purchase price and related transaction costs with respect to the Driftwood Acquisition from cash on hand and borrowings under its Senior Secured Credit Facility. Leases As of December 31, 2022, the Company had significant obligations for leases not yet commenced related to a new corporate office and equipment for completions, which commenced subsequent to December 31, 2022. Future undiscounted lease payments related to the corporate office, which continue through 2033, total $24.5 million. Future undiscounted lease payments related to the equipment for completions, which continue through 2025, total $126.0 million. Senior Secured Credit Facility On January 9, 2023, January 13, 2023 and February 13, 2023, the Company borrowed an additional $15.0 million, $40.0 million and $40.0 million, respectively, and on January 23, 2023, the Company repaid $30.0 million on the Senior Secured Credit Facility. As a result, the outstanding balance under the Senior Secured Credit Facility was $135.0 million as of February 17, 2023. See Note 7 for additional discussion of the Senior Secured Credit Facility. Commodity derivatives The following table summarizes the resulting open oil and natural gas derivative positions as of December 31, 2022, updated for the derivative transactions entered into from December 31, 2022 through February 17, 2023, for the settlement periods presented: Year 2023 Year 2024 Oil: WTI NYMEX - Collars: Volume (Bbl) 5,607,000 — Weighted-average floor price ($/Bbl) $ 68.71 $ — Weighted-average ceiling price ($/Bbl) $ 84.90 $ — Natural gas: Henry Hub NYMEX - Collars: Volume (MMBtu) 25,550,000 — Weighted-average floor price ($/MMBtu) $ 4.14 $ — Weighted-average ceiling price ($/MMBtu) $ 8.43 $ — Waha Inside FERC to Henry Hub NYMEX - Basis Swaps: Volume (MMBtu) 38,350,000 3,660,000 Weighted-average differential ($/MMBtu) $ (1.54) $ (0.75) See Note 11 for additional discussion regarding the Company's derivatives. There has been no other derivative activity subsequent to December 31, 2022.

Supplemental oil, NGL and natur

Supplemental oil, NGL and natural gas disclosures (unaudited)	12 Months Ended
	Dec. 31, 2022
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental oil, NGL and natural gas disclosures (unaudited)	Note 19 Supplemental oil, NGL and natural gas disclosures (unaudited) Incurred capital expenditures in oil and natural gas property acquisition, exploration and development activities The following table presents incurred capital expenditures 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) 2022 2021 2020 Property acquisition costs: Evaluated $ 8,295 $ 899,128 $ 11,368 Unevaluated 3,470 198,770 25,549 Exploration costs 26,384 33,482 17,337 Development costs 540,447 410,855 326,823 Total oil and natural gas properties incurred capital expenditures $ 578,596 $ 1,542,235 $ 381,077 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, 2022 December 31, 2021 Gross capitalized costs: Evaluated properties $ 9,554,706 $ 8,968,668 Unevaluated properties not being depleted 46,430 170,033 Total gross capitalized costs 9,601,136 9,138,701 Less accumulated depletion and impairment (7,318,399) (7,019,670) Net capitalized costs $ 2,282,737 $ 2,119,031 The following table presents a summary of the unevaluated property costs not being depleted as of December 31, 2022, by year in which such costs were incurred: (in thousands) 2022 2021 2020 2019 and prior Total Unevaluated properties not being depleted $ 14,707 $ 29,705 $ 784 $ 1,234 $ 46,430 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) 2022 2021 2020 Revenues: Oil, NGL and natural gas sales $ 1,794,374 $ 1,147,143 $ 496,355 Production costs: Lease operating expenses 173,983 101,994 82,020 Production and ad valorem taxes 110,997 68,742 33,050 Transportation and marketing expenses 53,692 47,916 49,927 Total production costs 338,672 218,652 164,997 Other costs: Depletion 298,259 201,691 203,492 Accretion of asset retirement obligation 3,653 4,018 4,227 Impairment expense — — 889,453 Income tax expense (1) 11,538 14,456 — Total other costs 313,450 220,165 1,097,172 Results of operations $ 1,142,252 $ 708,326 $ (765,814) _____________________________________________________________________________ (1) During each of the years ended December 31, 2022, 2021 and 2020, the Company recorded valuation allowances 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, 2% for the year ended December 31, 2021 and 0% for the year ended December 31, 2020, which reflects tax deductions and tax credits and allowances relating to the oil, NGL and natural gas producing activities that are reflected in the Company's "Total income tax (expense) benefit" on the consolidated statements of operations. 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, 2022, 2021 and 2020. In accordance with SEC regulations, the reserves as of December 31, 2022, 2021 and 2020 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, 2022, 2021 and 2020, all of which are located within the U.S.: Oil NGL Natural gas MBOE (1) Proved developed and undeveloped reserves: As of December 31, 2019 78,639 102,198 675,237 293,377 Revisions of previous estimates (10,517) 6,218 34,376 1,430 Extensions, discoveries and other additions 4,282 1,811 10,772 7,888 Acquisitions of reserves in place 5,182 1,310 6,948 7,650 Production (9,827) (10,615) (70,049) (32,117) 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 Proved developed reserves: December 31, 2019 52,711 90,861 600,334 243,628 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 Proved undeveloped reserves: December 31, 2019 25,928 11,337 74,903 49,749 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 _____________________________________________________________________________ (1) BOE is calculated using a conversion rate of six Mcf per one Bbl. 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 (ii) 52,976 MBOE from new proved undeveloped locations in Howard and western Glasscock Counties. The following discussion is for the year ended December 31, 2020. The Company's positive revision of 1,430 MBOE of previously estimated quantities consisted of (i) 29,080 MBOE of positive revisions from performance of proved developed producing wells, (ii) 3,140 MBOE of negative revisions from a decrease in previously estimated quantities of proved undeveloped locations, (iii) 8,245 MBOE of negative revisions due to proved undeveloped locations that were removed due to year-end pricing and (iv) 16,265 MBOE of negative revisions from a decrease in the Realized Prices for oil, NGL and natural gas and other changes to proved wells. Extensions, discoveries and other additions of 7,888 MBOE consisted of (i) 5,347 MBOE that resulted from new wells drilled and (ii) 2,541 MBOE that resulted from new horizontal proved undeveloped locations added in the Company's Howard County, Texas acreage. Acquisitions of reserves in place of 7,650 MBOE consisted of (i) 367 MBOE from new proved developed producing wells and (ii) 4,016 MBOE from additional acreage acquired under proved locations in Howard County and (iii) 3,267 MBOE from new proved undeveloped locations in Howard County. 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, 2022, 2021 and 2020 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%. The Company's unamortized cost of evaluated oil and natural gas properties being depleted exceeded the full cost ceiling for each of the quarterly periods in 2020 and, as such, the Company recorded non-cash full cost ceiling impairments totaling $889.5 million during the year ended December 31, 2020. No full cost ceiling impairment was recorded for the years ended December 31, 2022 and December 31, 2021. See Note 6 for discussion of the Benchmark Prices, Realized Prices and the 2020 full cost ceiling impairment recorded. 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) 2022 2021 2020 Future cash inflows $ 16,343,468 $ 11,846,148 $ 3,824,104 Future production costs (4,136,380) (3,595,524) (1,740,537) Future development costs (1,403,721) (1,064,527) (351,568) Future income tax expenses (1,587,677) (774,461) (20,076) Future net cash flows 9,215,690 6,411,636 1,711,923 10% discount for estimated timing of cash flows (4,461,114) (2,986,324) (697,069) Standardized measure of discounted future net cash flows $ 4,754,576 $ 3,425,312 $ 1,014,854 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) 2022 2021 2020 Standardized measure of discounted future net cash flows, beginning of year $ 3,425,312 $ 1,014,854 $ 1,662,261 Changes in the year resulting from: Sales, less production costs (1,468,946) (934,440) (331,358) Revisions of previous quantity estimates (99,512) 426,060 199 Extensions, discoveries and other additions 667,859 293,511 60,004 Net change in prices and production costs 2,565,963 1,572,662 (770,885) Changes in estimated future development costs (165,579) 134,091 64,146 Previously estimated development incurred capital expenditures during the period 260,475 169,376 186,261 Acquisitions of reserves in place — 1,509,087 14,208 Divestitures of reserves in place (96,222) (369,601) — Accretion of discount 371,625 102,607 167,227 Net change in income taxes (418,537) (279,722) (1,205) Timing differences and other (287,862) (213,173) (36,004) Standardized measure of discounted future net cash flows, end of year $ 4,754,576 $ 3,425,312 $ 1,014,854 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.

Basis of presentation and sig_2

Basis of presentation and significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2022
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.
Reclassifications	Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. There was no impact on previously reported total assets, total liabilities, net income (loss) or stockholders' equity for the periods presented.
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) depletion, depreciation and amortization, (iv) impairments, (v) income taxes, (vi) fair values of assets acquired and liabilities assumed in an acquisition, (vii) fair values of derivatives and (viii) 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.
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.
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, net 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" under "Non-operating income (expense)" on the consolidated statements of operations.
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 incurred capital expenditures 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 2027 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 or (ii) stock exchanged for the cost of exercise of stock options at the awardee's election.
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) 2022 2021 2020 Sales of purchased oil inventory $ 104,403 $ 327,839 $ 17,026 Purchased oil inventory 104,039 326,625 16,918 Net effect on earnings (1) $ 364 $ 1,214 $ 108 ______________________________________________________________________________ (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 existing contracts, 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; therefore, the Company recognizes revenue based on the net amount of the proceeds received from the midstream processing entity who represents the Company's customer. If for future contracts the Company was to conclude that it was the principal with the ultimate third party being the customer, the Company would recognize 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
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, performance share awards and the outperformance share award, 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. Equity Awards Restricted stock 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 first anniversary of the grant date. Restricted stock awards granted to non-employee directors vest immediately on the grant date. 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 at the start of the calendar year in which the award is granted. For performance share awards granted in 2022, the market criteria consists of: (i) annual relative total shareholder return comparing the Company's shareholder return to the shareholder return of the exploration and production companies listed in the Russell 2000 Index and (ii) annual absolute total shareholder return. The performance criteria for these awards consists of: (i) earnings before interest, taxes, depreciation, amortization and exploration expense and three-year total debt reduction, (ii) growth in inventory and (iii) emissions reduction targets. 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%. For performance share awards granted in 2019, the market criteria consists of: (i) the relative three-year total shareholder return ("TSR") comparing the Company's shareholder return to the shareholder return of the peer group specified in each award agreement ("RTSR Performance Percentage"), and (ii) the Company's absolute three-year total shareholder return ("ATSR Appreciation"). The performance criteria for these awards consists of the Company's three-year return on average capital employed ("ROACE Percentage"). Potential payout of these awards ranged from 0% to 200%. In the first quarter of 2022, following the completion of the requisite service period and achievement of certain market and performance criteria, these shares were issued at 107% payout. 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 2021, the market criteria consists of: (i) annual relative shareholder return comparing the Company's shareholder return to the shareholder return of the E&P companies listed in the Russell 2000 index and (ii) annual absolute total shareholder 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") and (ii) growth in inventory (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 can range from 0% to 250% for the market criteria and 0% to 200% for the performance criteria. 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. 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 200%, but is capped at 100% if the ATSR Appreciation is zero or less. The performance period for the performance unit awards granted March 5, 2020 ended December 31, 2022. As their market and performance criteria were fully satisfied, resulting in a 151% payout, the granted awards will be paid in cash during the first quarter of 2023. 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 (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.
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 ("ASC") and has determined there are no ASUs that are not yet adopted and meaningful to disclose as of December 31, 2022. Additionally, the Company did not adopt any new ASUs during the year ended December 31, 2022.

Compensation Related Costs, Sha

Compensation Related Costs, Share Based Payments (Policies)	12 Months Ended
	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
Share-based Payment Arrangement [Policy Text Block]	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, performance share awards and the outperformance share award, 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. Equity Awards Restricted stock 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 first anniversary of the grant date. Restricted stock awards granted to non-employee directors vest immediately on the grant date. 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 at the start of the calendar year in which the award is granted. For performance share awards granted in 2022, the market criteria consists of: (i) annual relative total shareholder return comparing the Company's shareholder return to the shareholder return of the exploration and production companies listed in the Russell 2000 Index and (ii) annual absolute total shareholder return. The performance criteria for these awards consists of: (i) earnings before interest, taxes, depreciation, amortization and exploration expense and three-year total debt reduction, (ii) growth in inventory and (iii) emissions reduction targets. 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%. For performance share awards granted in 2019, the market criteria consists of: (i) the relative three-year total shareholder return ("TSR") comparing the Company's shareholder return to the shareholder return of the peer group specified in each award agreement ("RTSR Performance Percentage"), and (ii) the Company's absolute three-year total shareholder return ("ATSR Appreciation"). The performance criteria for these awards consists of the Company's three-year return on average capital employed ("ROACE Percentage"). Potential payout of these awards ranged from 0% to 200%. In the first quarter of 2022, following the completion of the requisite service period and achievement of certain market and performance criteria, these shares were issued at 107% payout. 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 2021, the market criteria consists of: (i) annual relative shareholder return comparing the Company's shareholder return to the shareholder return of the E&P companies listed in the Russell 2000 index and (ii) annual absolute total shareholder 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") and (ii) growth in inventory (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 can range from 0% to 250% for the market criteria and 0% to 200% for the performance criteria. 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. 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 200%, but is capped at 100% if the ATSR Appreciation is zero or less. The performance period for the performance unit awards granted March 5, 2020 ended December 31, 2022. As their market and performance criteria were fully satisfied, resulting in a 151% payout, the granted awards will be paid in cash during the first quarter of 2023. 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.

Basis of presentation and sig_3

Basis of presentation and significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 December 31, 2021 Oil, NGL and natural gas sales (1) $ 111,260 $ 135,560 Joint operations, net (2) 35,801 11,491 Other 16,308 4,756 Total accounts receivable, net $ 163,369 $ 151,807 _____________________________________________________________________________ (1) For purchasers that the Company has netting arrangements with, the amounts presented include the net positions. (2) Accounts receivable for joint operations are presented net of an allowance for expected credit losses of $0.4 million as of both December 31, 2022 and 2021. As the operator of the majority of its wells, the Company has the ability to realize some or all of these receivables through the netting of revenues.
Schedule of components of other current assets	Other current assets consisted of the following components as of the dates presented: (in thousands) December 31, 2022 December 31, 2021 Prepaid expenses and other $ 7,247 $ 12,746 Inventory 6,070 10,160 Total other current assets $ 13,317 $ 22,906
Schedule of components of other current liabilities	Other current liabilities consisted of the following components as of the dates presented: (in thousands) December 31, 2022 December 31, 2021 Accrued interest payable $ 43,984 $ 56,468 Accrued compensation and benefits 20,000 14,434 Other liabilities 18,966 28,569 Total other current liabilities $ 82,950 $ 99,471
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) 2022 2021 Liability at beginning of year $ 72,003 $ 68,326 Liabilities added due to acquisitions, drilling, midstream service asset construction and other 362 14,610 Accretion expense (1) 3,879 4,233 Liabilities settled due to plugging and abandonment or removed due to sale (2,163) (15,186) Revision of estimates — 20 Liability at end of year 74,081 72,003 Less: current asset retirement obligations (2) 3,715 2,946 Non-current asset retirement obligations $ 70,366 $ 69,057 ______________________________________________________________________________ (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) 2022 2021 2020 Sales of purchased oil inventory $ 104,403 $ 327,839 $ 17,026 Purchased oil inventory 104,039 326,625 16,918 Net effect on earnings (1) $ 364 $ 1,214 $ 108 ______________________________________________________________________________ (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) 2022 2021 2020 Supplemental cash flow information: Cash paid for interest, net of $3,872, $5,866 and $3,019 of capitalized interest, respectively (1) $ 131,867 $ 94,867 $ 77,401 Supplemental non-cash operating information: Right-of-use assets obtained in exchange for operating lease liabilities (2) $ 34,532 $ 7,742 $ 2,349 Supplemental non-cash investing information: Fair value of contingent consideration asset (liability) on transaction closing date (3) $ — $ 33,832 $ (225) Change in accrued capital expenditures $ (2,207) $ 22,310 $ (8,053) Capitalized asset retirement cost $ 362 $ 14,610 $ 2,252 ______________________________________________________________________________ (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 acquisitions and divestiture of oil and natural gas properties that include contingent considerations. See Note 12 for discussion of the quarterly remeasurement of the respective contingent considerations.

Acquisitions and divestitures (

Acquisitions and divestitures (Tables)	12 Months Ended
	Dec. 31, 2022
Business Combination and Asset Acquisition [Abstract]
Schedule of components of purchase price	The following table presents components of the purchase price, inclusive of customary closing adjustments: (in thousands, except for share and share price data) As of October 18, 2021 Shares of Company common stock 959,691 Company common stock price at the Pioneer Closing Date $ 73.90 Value of Company common stock consideration $ 70,921 Cash consideration $ 135,323 Transaction costs 3,861 Total purchase price $ 210,105 The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on the Pioneer Closing Date: (in thousands) As of October 18, 2021 Evaluated properties $ 143,021 Unevaluated properties 74,468 Revenue suspense liabilities assumed (7,384) Allocated purchase price $ 210,105 The following table presents components of the purchase price, inclusive of customary closing adjustments: (in thousands, except for share and share price data) As of July 1, 2021 Shares of Company common stock 2,506,964 Company common stock price at the Sabalo/Shad Closing Date $ 95.72 Value of Company common stock consideration $ 239,967 Cash consideration $ 606,126 Transaction costs 17,020 Total purchase price $ 863,113 The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed, based on their relative fair values, on the Sabalo/Shad Closing Date: (in thousands) As of July 1, 2021 Evaluated properties $ 503,005 Unevaluated properties 362,977 Revenue suspense liabilities assumed (4,269) Inventory 1,400 Allocated purchase price $ 863,113

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2022
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) 2022 2021 Operating lease costs (1) $ 24,174 $ 15,894 Short-term lease costs (2) 110,442 83,471 Variable lease costs (3) 11,328 6,873 Sublease income (990) (1,057) Total lease costs, net $ 144,954 $ 105,181 _____________________________________________________________________________ (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 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 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) 2022 2021 Operating cash flows from operating leases $ 3,892 $ 4,065 Investing cash flows from operating leases (1) $ 20,398 $ 12,569 _____________________________________________________________________________ (1) Amounts associated with drilling 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, 2022 December 31, 2021 Weighted-average remaining lease term 1.91 years 2.80 years Weighted-average discount rate 5.84 % 7.41 %
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, 2022 2023 $ 16,467 2024 6,789 2025 1,350 2026 1,348 2027 666 Total minimum lease payments 26,620 Less: imputed interest (1,736) Present value of future minimum lease payments $ 24,884

Property and equipment (Tables)

Property and equipment (Tables)	12 Months Ended
	Dec. 31, 2022
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) 2022 2021 2020 Capitalized employee-related costs $ 17,026 $ 18,255 $ 18,954
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) 2022 2021 2020 Depletion expense of evaluated oil and natural gas properties $ 298,259 $ 201,691 $ 203,492 Depletion expense per BOE sold $ 9.92 $ 6.76 $ 6.34 The following table presents full cost ceiling impairment expense, which is included in "Impairment expense" on the consolidated statements of operations for the periods presented: Years ended December 31, (in thousands) 2022 2021 2020 Full cost ceiling impairment expense $ — $ — $ 889,453 Midstream service assets consisted of the following components as of the dates presented: (in thousands) December 31, 2022 December 31, 2021 Midstream service assets $ 151,157 $ 165,232 Less accumulated depreciation and impairment (66,001) (68,704) Total midstream service assets, net $ 85,156 $ 96,528 Other fixed assets consisted of the following components as of the dates presented: (in thousands) December 31, 2022 December 31, 2021 Computer hardware and software $ 21,758 $ 15,039 Vehicles 7,934 9,072 Leasehold improvements 7,136 7,136 Buildings 7,039 7,039 Other 6,087 5,095 Depreciable total 49,954 43,381 Less accumulated depreciation and amortization (30,382) (27,692) Depreciable total, net 19,572 15,689 Land 23,075 18,901 Total other fixed assets, net $ 42,647 $ 34,590
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, 2022 December 31, 2021 December 31, 2020 Benchmark Prices: Oil ($/Bbl) $ 90.15 $ 63.04 $ 36.04 NGL ($/Bbl) (1) $ 41.77 $ 34.51 $ 16.63 Natural gas ($/MMBtu) $ 5.20 $ 3.35 $ 1.21 Realized Prices: Oil ($/Bbl) $ 96.21 $ 66.37 $ 37.69 NGL ($/Bbl) $ 29.84 $ 22.90 $ 7.43 Natural gas ($/Mcf) $ 4.24 $ 2.61 $ 0.79 _____________________________________________________________________________

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2022
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: December 31, 2022 December 31, 2021 (in thousands) Long-term debt Debt issuance costs, net Long-term debt, net Long-term debt Debt issuance costs, net Long-term debt, net January 2025 Notes 455,628 (3,297) 452,331 577,913 (6,345) 571,568 January 2028 Notes 300,309 (3,478) 296,831 361,044 (5,024) 356,020 July 2029 Notes 298,214 (4,353) 293,861 400,000 (6,730) 393,270 Senior Secured Credit Facility (1) 70,000 — 70,000 105,000 — 105,000 Total $ 1,124,151 $ (11,128) $ 1,113,023 $ 1,443,957 $ (18,099) $ 1,425,858 _____________________________________________________________________________ (1) Debt issuance costs, net related to the Senior Secured Credit Facility of $7.3 million and $8.1 million as of December 31, 2022 and 2021, 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 Year ended Year ended January 2025 Notes $ 122,285 $ — $ 22,087 January 2028 Notes 60,735 — 38,956 January 2029 Notes 101,786 — — Total principal amount repurchased $ 284,806 $ — $ 61,043 Less: Consideration paid $ 282,902 $ — $ 38,139 Write off of debt issuance costs 3,363 — 595 Gain (loss) on extinguishment of debt, net (1) $ (1,459) $ — $ 22,309
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) 2022 2021 2020 Interest expense on borrowings $ 123,255 $ 114,800 $ 104,320 Amortization of debt issuance costs and other adjustments 5,738 4,451 3,708 Less capitalized interest 3,872 5,866 3,019 Total interest expense $ 125,121 $ 113,385 $ 105,009

Stockholders' equity (Tables)

Stockholders' equity (Tables)	12 Months Ended
	Dec. 31, 2022
Equity [Abstract]
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, 2022
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, 2022: (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, 2021 350 $35.57 7 $275.88 72 $64.74 Granted 255 $67.54 — 62 $89.76 Forfeited (58) $46.75 — (16) $88.28 Vested (1)(2) (185) $42.30 — (70) $64.53 Expired or canceled — (4) $313.12 — Outstanding as of December 31, 2022 (3) 362 $52.90 3 $235.08 48 $89.76 _____________________________________________________________________________ (1) The aggregate intrinsic value of vested restricted stock awards for the year ended December 31, 2022 was $14.6 million. (2) The performance share awards granted on February 28, 2019 and June 3, 2019 had a performance period of January 1, 2019 to December 31, 2021 and, as their market and performance criteria were satisfied, resulted in a 107% payout. As such, the granted awards vested and were converted into 75,107 shares of the Company's common stock during the year ended December 31, 2022 based on this 107% payout. (3) The vested and exercisable stock option awards as of December 31, 2022 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, 2022: (in thousands) Performance Unit Awards Phantom Unit Awards Outstanding as of December 31, 2021 209 33 Forfeited (59) — Vested (1) — (15) Outstanding as of December 31, 2022 150 18 _____________________________________________________________________________
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, 2022 for the grant dates presented: Performance Share Awards Performance Unit Awards February 22, 2022 March 9, 2021 Remaining performance period on grant date 2.86 years n/a Remaining performance period n/a 1 year Risk-free interest rate (1) 1.71 % 4.62 % Dividend yield — % — % Expected volatility (2) 119.25 % 79.77 % Expense per performance share or unit as of December 31, 2022 $89.76 $79.85 ______________________________________________________________________________ (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) 2022 2021 2020 Equity awards: Restricted stock awards $ 8,596 $ 7,594 $ 8,839 Performance share awards 1,590 1,657 2,719 Stock option awards — 7 77 Total share-settled equity-based compensation, gross $ 10,186 $ 9,258 $ 11,635 Less amounts capitalized (1,783) (1,583) (3,418) Total share-settled equity-based compensation, net $ 8,403 $ 7,675 $ 8,217 Liability awards: Performance unit awards $ 741 $ 7,480 $ 749 Phantom unit awards 1,186 1,238 404 Total cash-settled equity-based compensation, gross $ 1,927 $ 8,718 $ 1,153 Less amounts capitalized (272) (365) (163) Total cash-settled equity-based compensation, net $ 1,655 $ 8,353 $ 990 Total equity-based compensation, net $ 10,058 $ 16,028 $ 9,207

Net income (loss) per common _2

Net income (loss) per common share (Tables)	12 Months Ended
	Dec. 31, 2022
Earnings Per Share [Abstract]
Schedule of calculation of basic and diluted weighted average shares outstanding and net income (loss) per share	The following table reflects the calculations of basic and diluted (i) weighted-average common shares outstanding and (ii) net income (loss) per common share for the periods presented: Years ended December 31, (in thousands, except for per share data) 2022 2021 2020 Net income (loss) $ 631,512 $ 145,008 $ (874,173) Weighted-average common shares outstanding: Basic 16,672 14,240 11,668 Dilutive non-vested restricted stock awards 183 181 — Dilutive non-vested performance share awards (1) 12 43 — Diluted 16,867 14,464 11,668 Net income (loss) per common share: Basic $ 37.88 $ 10.18 $ (74.92) Diluted $ 37.44 $ 10.03 $ (74.92) _____________________________________________________________________________ (1) The dilutive effect of the non-vested performance shares for the year ended December 31, 2022 was calculated as of the end of the performance period on December 31, 2022.

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2022
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) 2022 2021 2020 Commodity $ (291,973) $ (453,784) $ 73,662 Contingent consideration (6,764) 1,639 6,795 Interest rate 14 (30) (343) Gain (loss) on derivatives, net $ (298,723) $ (452,175) $ 80,114
Schedule of open positions and derivatives in place	The following table summarizes open commodity derivative positions as of December 31, 2022, for commodity derivatives that were entered into through December 31, 2022, for the settlement periods presented: Year 2023 Oil: WTI NYMEX - Collars: Volume (Bbl) 5,089,000 Weighted-average floor price ($/Bbl) $ 68.58 Weighted-average ceiling price ($/Bbl) $ 84.88 Natural gas: Henry Hub NYMEX - Collars: Volume (MMBtu) 25,550,000 Weighted-average floor price ($/MMBtu) $ 4.14 Weighted-average ceiling price ($/MMBtu) $ 8.43 Waha Inside FERC to Henry Hub NYMEX - Basis Swaps: Volume (MMBtu) 25,550,000 Weighted-average differential ($/MMBtu) $ (1.65)

Fair value measurements (Tables

Fair value measurements (Tables)	12 Months Ended
	Dec. 31, 2022
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, 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 December 31, 2021 (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 $ — $ 21,671 $ — $ 21,671 $ (21,671) $ — Contingent consideration — — 4,346 4,346 — 4,346 Noncurrent: Commodity — 1,448 — 1,448 — 1,448 Contingent consideration — — 31,515 31,515 — 31,515 Liabilities: Current: Commodity — (201,428) — (201,428) 21,671 (179,757) Interest rate — (52) — (52) — (52) Net derivative asset (liability) positions $ — $ (178,361) $ 35,861 $ (142,500) $ — $ (142,500)
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) 2022 2021 2020 Balance of Level 3 at beginning of year $ 35,861 $ — $ — Sixth Street Contingent Consideration valuation as of Sixth Street Closing Date — 33,832 — Change in Sixth Street Contingent Consideration fair value (11,678) 2,029 — Settlements realized (1) 2,457 — — Balance of Level 3 at end of year $ 26,640 $ 35,861 $ — _____________________________________________________________________________ (1) For the year ended December 31, 2022, $1.9 million of realized settlements has been received and is included in "Settlements received for contingent consideration" in cash flows from investing activities on the consolidated statements of cash flows, and $0.6 million is a receivable at period end.
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, 2022 December 31, 2021 (in thousands) Long-term debt Fair value (1) Long-term debt Fair value (1) January 2025 Notes $ 455,628 $ 449,122 $ 577,913 $ 589,471 January 2028 Notes 300,309 292,846 361,044 378,578 July 2029 Notes 298,214 268,416 400,000 390,000 Senior Secured Credit Facility 70,000 69,945 105,000 105,040 Total $ 1,124,151 $ 1,080,329 $ 1,443,957 $ 1,463,089 _____________________________________________________________________________ (1) The fair values of the outstanding notes were determined using the Level 1 fair value hierarchy quoted market prices for each respective instrument as of December 31, 2022 and 2021. 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, 2022 and 2021.

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Schedule of income tax (expense) benefit	The following table presents the "Current" and "Deferred" income tax (expense) benefit reported on the consolidated statements of operations for the periods presented: Years ended December 31, (in thousands) 2022 2021 2020 Current income tax (expense) benefit: Federal $ — $ — $ — State (6,121) (1,324) — Deferred income tax (expense) benefit: Federal — — — State 619 (2,321) 3,946 Total income tax (expense) benefit $ (5,502) $ (3,645) $ 3,946
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 (expense) benefit differed from amounts computed by applying the applicable federal income tax rate of 21% for the years ended December 31, 2022, 2021 and 2020 to pre-tax earnings as a result of the following: Years ended December 31, (in thousands) 2022 2021 2020 Income tax (expense) benefit computed by applying the statutory rate $ (133,773) $ (31,217) $ 184,405 Change in deferred tax valuation allowance 144,480 45,717 (182,634) Non-deductible equity-based compensation (19,301) (13,640) — State income tax and change in valuation allowance 8,058 (3,274) 2,903 Other items (4,966) (1,231) (728) Total income tax (expense) benefit $ (5,502) $ (3,645) $ 3,946
Schedule of net deferred tax assets (liabilities)	The following table presents significant components of the Company's net deferred tax liability as of the dates presented: (in thousands) December 31, 2022 December 31, 2021 Deferred tax assets: Net operating loss carryforward $ 307,357 $ 445,426 Equity-based compensation 2,933 11,123 Derivatives — 36,639 Other 1,110 3,227 Total deferred tax asset 311,400 496,415 Valuation allowance (298,184) (443,390) Deferred tax assets, net of valuation allowance 13,216 53,025 Deferred tax liabilities: Oil and natural gas properties, midstream service assets and other fixed assets (11,105) (53,868) Derivatives (2,331) — Total deferred tax liabilities (13,436) (53,868) Texas net deferred tax liability (1) $ (220) $ (843) ___________________________________________________________________________

Credit risk (Tables)

Credit risk (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 2021 2020 Purchaser A (1) 33 % 29 % 33 % Purchaser B (1) 18 % 14 % n/a (2) Purchaser C 17 % 24 % 24 % Purchaser D (1) n/a (2) 17 % 14 % Purchaser E n/a (2) n/a (2) 10 % _____________________________________________________________________________ (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 in at least one of the years presented: Years ended December 31, 2022 2021 2020 Purchaser A (1) 47 % 47 % 69 % Purchaser B (1) 22 % 31 % 16 % Purchaser C (1) 22 % 22 % 14 % _____________________________________________________________________________ (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, 2022
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) 2022 2021 2020 Capital expenditures for oil and natural gas properties $ 103,152 $ 69,670 $ 63,886

Organizational restructurings (

Organizational restructurings (Tables)	12 Months Ended
	Dec. 31, 2022
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) 2022 2021 2020 Gross equity-based compensation expense reversals $ (4,908) $ (1,088) $ (793)

Subsequent events (Tables)

Subsequent events (Tables)	12 Months Ended
	Dec. 31, 2022
Subsequent Events [Abstract]
Schedule of subsequent events	The following table summarizes the resulting open oil and natural gas derivative positions as of December 31, 2022, updated for the derivative transactions entered into from December 31, 2022 through February 17, 2023, for the settlement periods presented: Year 2023 Year 2024 Oil: WTI NYMEX - Collars: Volume (Bbl) 5,607,000 — Weighted-average floor price ($/Bbl) $ 68.71 $ — Weighted-average ceiling price ($/Bbl) $ 84.90 $ — Natural gas: Henry Hub NYMEX - Collars: Volume (MMBtu) 25,550,000 — Weighted-average floor price ($/MMBtu) $ 4.14 $ — Weighted-average ceiling price ($/MMBtu) $ 8.43 $ — Waha Inside FERC to Henry Hub NYMEX - Basis Swaps: Volume (MMBtu) 38,350,000 3,660,000 Weighted-average differential ($/MMBtu) $ (1.54) $ (0.75)

Supplemental oil, NGL and nat_2

Supplemental oil, NGL and natural gas disclosures (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2022
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 incurred capital expenditures 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) 2022 2021 2020 Property acquisition costs: Evaluated $ 8,295 $ 899,128 $ 11,368 Unevaluated 3,470 198,770 25,549 Exploration costs 26,384 33,482 17,337 Development costs 540,447 410,855 326,823 Total oil and natural gas properties incurred capital expenditures $ 578,596 $ 1,542,235 $ 381,077
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, 2022 December 31, 2021 Gross capitalized costs: Evaluated properties $ 9,554,706 $ 8,968,668 Unevaluated properties not being depleted 46,430 170,033 Total gross capitalized costs 9,601,136 9,138,701 Less accumulated depletion and impairment (7,318,399) (7,019,670) Net capitalized costs $ 2,282,737 $ 2,119,031
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, 2022, by year in which such costs were incurred: (in thousands) 2022 2021 2020 2019 and prior Total Unevaluated properties not being depleted $ 14,707 $ 29,705 $ 784 $ 1,234 $ 46,430
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) 2022 2021 2020 Revenues: Oil, NGL and natural gas sales $ 1,794,374 $ 1,147,143 $ 496,355 Production costs: Lease operating expenses 173,983 101,994 82,020 Production and ad valorem taxes 110,997 68,742 33,050 Transportation and marketing expenses 53,692 47,916 49,927 Total production costs 338,672 218,652 164,997 Other costs: Depletion 298,259 201,691 203,492 Accretion of asset retirement obligation 3,653 4,018 4,227 Impairment expense — — 889,453 Income tax expense (1) 11,538 14,456 — Total other costs 313,450 220,165 1,097,172 Results of operations $ 1,142,252 $ 708,326 $ (765,814) _____________________________________________________________________________
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, 2022, 2021 and 2020, all of which are located within the U.S.: Oil NGL Natural gas MBOE (1) Proved developed and undeveloped reserves: As of December 31, 2019 78,639 102,198 675,237 293,377 Revisions of previous estimates (10,517) 6,218 34,376 1,430 Extensions, discoveries and other additions 4,282 1,811 10,772 7,888 Acquisitions of reserves in place 5,182 1,310 6,948 7,650 Production (9,827) (10,615) (70,049) (32,117) 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 Proved developed reserves: December 31, 2019 52,711 90,861 600,334 243,628 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 Proved undeveloped reserves: December 31, 2019 25,928 11,337 74,903 49,749 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 _____________________________________________________________________________ (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) 2022 2021 2020 Future cash inflows $ 16,343,468 $ 11,846,148 $ 3,824,104 Future production costs (4,136,380) (3,595,524) (1,740,537) Future development costs (1,403,721) (1,064,527) (351,568) Future income tax expenses (1,587,677) (774,461) (20,076) Future net cash flows 9,215,690 6,411,636 1,711,923 10% discount for estimated timing of cash flows (4,461,114) (2,986,324) (697,069) Standardized measure of discounted future net cash flows $ 4,754,576 $ 3,425,312 $ 1,014,854
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) 2022 2021 2020 Standardized measure of discounted future net cash flows, beginning of year $ 3,425,312 $ 1,014,854 $ 1,662,261 Changes in the year resulting from: Sales, less production costs (1,468,946) (934,440) (331,358) Revisions of previous quantity estimates (99,512) 426,060 199 Extensions, discoveries and other additions 667,859 293,511 60,004 Net change in prices and production costs 2,565,963 1,572,662 (770,885) Changes in estimated future development costs (165,579) 134,091 64,146 Previously estimated development incurred capital expenditures during the period 260,475 169,376 186,261 Acquisitions of reserves in place — 1,509,087 14,208 Divestitures of reserves in place (96,222) (369,601) — Accretion of discount 371,625 102,607 167,227 Net change in income taxes (418,537) (279,722) (1,205) Timing differences and other (287,862) (213,173) (36,004) Standardized measure of discounted future net cash flows, end of year $ 4,754,576 $ 3,425,312 $ 1,014,854

Organization (Details)

Organization (Details)	12 Months Ended
	Dec. 31, 2022 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, 2022	Dec. 31, 2021
Accounts receivable
Oil, NGL and natural gas sales	$ 111,260	$ 135,560
Joint operations, net	35,801	11,491
Other	16,308	4,756
Accounts receivable, net	163,369	151,807
Allowance for doubtful accounts of accounts receivable for joint operations	$ 400	$ 400

Basis of presentation and sig_5

Basis of presentation and significant accounting policies - Other current assets (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Prepaid expenses and other	$ 7,247	$ 12,746
Inventory	6,070	10,160
Total other current assets	$ 13,317	$ 22,906

Basis of presentation and sig_6

Basis of presentation and significant accounting policies - Other current liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Accrued interest payable	$ 43,984	$ 56,468
Accrued compensation and benefits	20,000	14,434
Other liabilities	18,966	28,569
Total other current liabilities	$ 82,950	$ 99,471

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, 2022	Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liability at beginning of year	$ 72,003	$ 68,326
Liabilities added due to acquisitions, drilling, midstream service asset construction and other	362	14,610
Accretion expense	3,879	4,233
Liabilities settled due to plugging and abandonment or removed due to sale	(2,163)	(15,186)
Revision of estimates	0	20
Liability at end of year	74,081	72,003
Less: current asset retirement obligations	3,715	2,946
Non-current asset retirement obligations	$ 70,366	$ 69,057

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Sales of purchased oil
Disaggregation of Revenue [Line Items]
Net effect on earnings	$ 364	$ 1,214	$ 108
Sales of purchased oil inventory
Disaggregation of Revenue [Line Items]
Net effect on earnings	104,403	327,839	17,026
Purchased oil inventory
Disaggregation of Revenue [Line Items]
Net effect on earnings	$ 104,039	$ 326,625	$ 16,918

Basis of presentation and sig_9

Basis of presentation and significant accounting policies - Revenue recognition (Details)	12 Months Ended
	Dec. 31, 2022
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, 2022	Dec. 31, 2021
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Supplemental cash flow information:
Cash paid for interest, net of capitalized interest	$ 131,867	$ 94,867	$ 77,401
Supplemental non-cash operating information:
Right-of-use assets obtained in exchange for operating lease liabilities	34,532	7,742	2,349
Supplemental non-cash investing information:
Fair value of contingent consideration asset (liability) on transaction closing date	0	33,832	(225)
Change in accrued capital expenditures	(2,207)	22,310	(8,053)
Capitalized asset retirement cost	362	14,610	2,252
Capitalized interest	$ 3,872	$ 5,866	$ 3,019

Acquisitions and divestitures -

Acquisitions and divestitures - Narrative (Details) $ / shares in Units, $ in Thousands				12 Months Ended
	Oct. 18, 2021 USD ($) $ / shares shares	Jul. 01, 2021 USD ($) shares	Feb. 04, 2020 USD ($) a	Dec. 31, 2021 USD ($) $ / shares	Dec. 31, 2022 USD ($) $ / shares	Oct. 03, 2022 USD ($)	Sep. 17, 2021 a location	May 07, 2021 a location agreement	Jun. 01, 2020 $ / shares
Business Acquisition [Line Items]
Common stock, par value (in USD per share) | $ / shares	$ 0.01			$ 0.01	$ 0.01				$ 0.01
Howard County Net Acres
Business Acquisition [Line Items]
Area of land (in acres) | a			80
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		$ 35,900	$ 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%
Pioneer Acquisition
Business Acquisition [Line Items]
Area of land (in acres) | a							20,000
Total purchase price	$ 210,105
Cash consideration	$ 135,323
Stock issued in asset acquisition (in shares) | shares	959,691
Transaction costs	$ 3,861
Pioneer - Glasscock County Gross - Operated Locations
Business Acquisition [Line Items]
Number of real estate properties | location							135
Pioneer - Glasscock County Net - Operated Locations
Business Acquisition [Line Items]
Number of real estate properties | location							121
Pioneer Acquisition - 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
Total purchase price		$ 863,113
Cash consideration		$ 606,126
Stock issued in asset acquisition (in shares) | shares		2,506,964
Transaction costs		$ 17,020
Number of purchase and sale agreements | agreement								2
Sabalo and Shad - Howard and Borden County Gross - Operated Locations
Business Acquisition [Line Items]
Number of real estate properties | location								120
Sabalo and Shad - Howard and Borden County Net - Operated Locations
Business Acquisition [Line Items]
Number of real estate properties | location								109
Sabalo and Shad - Howard and Borden County Gross - Non-Operated Locations
Business Acquisition [Line Items]
Number of real estate properties | location								150
Sabalo and Shad - Howard and Borden County Net - Non-Operated Locations
Business Acquisition [Line Items]
Number of real estate properties | location								18
Howard County Net Acres
Business Acquisition [Line Items]
Area of land (in acres) | a			1,180
Total purchase price			$ 22,500
Oil and Gas Properties
Business Acquisition [Line Items]
Proceeds after transaction costs						$ 106,500

Acquisitions and divestitures_2

Acquisitions and divestitures - Purchase price (Details) - USD ($) $ / shares in Units, $ in Thousands	Oct. 18, 2021	Jul. 01, 2021
Pioneer Acquisition
Asset Acquisition [Line Items]
Shares of Company common stock (in shares)	959,691
Cash consideration	$ 135,323
Transaction costs	3,861
Total purchase price	$ 210,105
Pioneer Acquisition | Common stock
Asset Acquisition [Line Items]
Shares of Company common stock (in shares)	959,691
Company common stock price at the Pioneer Closing Date (in USD per share)	$ 73.90
Value of Company common stock consideration	$ 70,921
Sabalo and Shad
Asset Acquisition [Line Items]
Shares of Company common stock (in shares)		2,506,964
Cash consideration		$ 606,126
Transaction costs		17,020
Total purchase price		$ 863,113
Sabalo and Shad | Common stock
Asset Acquisition [Line Items]
Shares of Company common stock (in shares)		2,506,964
Company common stock price at the Pioneer Closing Date (in USD per share)		$ 95.72
Value of Company common stock consideration		$ 239,967

Acquisitions and divestitures_3

Acquisitions and divestitures - Assets acquired and liabilities assumed (Details) - USD ($) $ in Thousands	Oct. 18, 2021	Jul. 01, 2021
Pioneer Acquisition
Asset Acquisition [Line Items]
Revenue suspense liabilities assumed	$ (7,384)
Allocated purchase price	210,105
Pioneer Acquisition | Evaluated Properties
Asset Acquisition [Line Items]
Properties	143,021
Pioneer Acquisition | Unevaluated Properties
Asset Acquisition [Line Items]
Properties	$ 74,468
Sabalo and Shad
Asset Acquisition [Line Items]
Revenue suspense liabilities assumed		$ (4,269)
Inventory		1,400
Allocated purchase price		863,113
Sabalo and Shad | Evaluated Properties
Asset Acquisition [Line Items]
Properties		503,005
Sabalo and Shad | Unevaluated Properties
Asset Acquisition [Line Items]
Properties		$ 362,977

Leases - Lease costs (Details)

Leases - Lease costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Operating lease costs	$ 24,174	$ 15,894
Short-term lease costs	110,442	83,471
Variable lease costs	11,328	6,873
Sublease income	(990)	(1,057)
Total lease costs, net	$ 144,954	$ 105,181

Leases - Supplemental cash flow

Leases - Supplemental cash flow information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Operating cash flows from operating leases	$ 3,892	$ 4,065
Investing cash flows from operating leases	$ 20,398	$ 12,569

Leases - Lease terms and discou

Leases - Lease terms and discount rates (Details)	Dec. 31, 2022	Dec. 31, 2021
Operating leases:
Weighted-average remaining lease term	1 year 10 months 28 days	2 years 9 months 18 days
Weighted-average discount rate (as a percent)	5.84%	7.41%

Leases - Maturities of operatin

Leases - Maturities of operating lease liabilities (Details) $ in Thousands	Dec. 31, 2022 USD ($)
Operating leases:
2023	$ 16,467
2024	6,789
2025	1,350
2026	1,348
2027	666
Total minimum lease payments	26,620
Less: imputed interest	(1,736)
Present value of future minimum lease payments	$ 24,884

Property and equipment - Oil an

Property and equipment - Oil and natural gas properties (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) $ / MMcf $ / bbl $ / Boe $ / MMBTU	Dec. 31, 2021 USD ($) $ / MMcf $ / Boe $ / bbl $ / MMBTU	Dec. 31, 2020 USD ($) $ / MMBTU $ / Boe $ / bbl $ / MMcf
Property, Plant and Equipment [Line Items]
Capitalized employee-related costs | $	$ 17,026	$ 18,255	$ 18,954
Depletion expense of evaluated oil and natural gas properties | $	$ 298,259	$ 201,691	$ 203,492
Depletion per BOE sold (USD per BOE) | $ / Boe	9.92	6.76	6.34
Discount rate used in calculating full cost ceiling (as a percent)	10%
Non-cash full cost ceiling impairment | $	$ 0	$ 0	$ 889,453
Crude Oil
Property, Plant and Equipment [Line Items]
Benchmark prices (USD per barrel or MMBtu)	90.15	63.04	36.04
Realized prices (USD per barrel or Mcf)	96.21	66.37	37.69
Natural Gas (Bbl)
Property, Plant and Equipment [Line Items]
Benchmark prices (USD per barrel or MMBtu)	41.77	34.51	16.63
Realized prices (USD per barrel or Mcf)	29.84	22.90	7.43
Natural gas (MMcf)
Property, Plant and Equipment [Line Items]
Benchmark prices (USD per barrel or MMBtu) | $ / MMBTU	5.20	3.35	1.21
Realized prices (USD per barrel or Mcf) | $ / MMcf	4.24	2.61	0.79

Property and equipment - Midstr

Property and equipment - Midstream service assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Total midstream service assets, net	$ 85,156	$ 96,528
Gain (loss) on disposal of assets, net	(1,079)	84,551	$ (963)
Midstream service assets
Property, Plant and Equipment [Line Items]
Midstream service assets	151,157	165,232
Less accumulated depreciation and impairment	(66,001)	(68,704)
Total midstream service assets, net	85,156	96,528
Retired midstream service assets	15,600	18,800
Accumulated depreciation	11,400	9,400
Gain (loss) on disposal of assets, net	$ (4,200)	$ (9,400)
Midstream service assets | Minimum
Property, Plant and Equipment [Line Items]
Useful life	10 years
Midstream service assets | Maximum
Property, Plant and Equipment [Line Items]
Useful life	20 years

Property and equipment - Other

Property and equipment - Other fixed assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Total other fixed assets, net	$ 42,647	$ 34,590
Computer hardware and software
Property, Plant and Equipment [Line Items]
Other fixed assets, net	21,758	15,039
Vehicles
Property, Plant and Equipment [Line Items]
Other fixed assets, net	7,934	9,072
Leasehold improvements
Property, Plant and Equipment [Line Items]
Other fixed assets, net	7,136	7,136
Buildings
Property, Plant and Equipment [Line Items]
Other fixed assets, net	7,039	7,039
Other
Property, Plant and Equipment [Line Items]
Other fixed assets, net	6,087	5,095
Depreciable total, net
Property, Plant and Equipment [Line Items]
Other fixed assets, net	49,954	43,381
Less accumulated depreciation and impairment	(30,382)	(27,692)
Total other fixed assets, net	19,572	15,689
Land
Property, Plant and Equipment [Line Items]
Total other fixed assets, net	$ 23,075	$ 18,901
Minimum | Other fixed assets
Property, Plant and Equipment [Line Items]
Useful life	3 years
Maximum | Other fixed assets
Property, Plant and Equipment [Line Items]
Useful life	10 years

Debt - Long-term debt, net (Det

Debt - Long-term debt, net (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Long-term debt	$ 1,124,151	$ 1,443,957
Debt issuance costs, net	(11,128)	(18,099)
Long-term debt, net	1,113,023	1,425,858
Senior Notes | January 2025 Notes
Debt Instrument [Line Items]
Long-term debt	455,628	577,913
Debt issuance costs, net	(3,297)	(6,345)
Long-term debt, net	452,331	571,568
Senior Notes | January 2028 Notes
Debt Instrument [Line Items]
Long-term debt	300,309	361,044
Debt issuance costs, net	(3,478)	(5,024)
Long-term debt, net	296,831	356,020
Senior Notes | July 2029 Notes
Debt Instrument [Line Items]
Long-term debt	298,214	400,000
Debt issuance costs, net	(4,353)	(6,730)
Long-term debt, net	293,861	393,270
Senior Secured Credit Facility | Line of Credit
Debt Instrument [Line Items]
Long-term debt	70,000	105,000
Debt issuance costs, net	0	0
Long-term debt, net	70,000	105,000
Senior Secured Credit Facility | Line of Credit | Other Noncurrent Assets
Debt Instrument [Line Items]
Debt issuance costs, net	$ 7,300	$ 8,100

Debt - Senior Unsecured Notes R

Debt - Senior Unsecured Notes Repurchases under Authorized Bond Purchase Programs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Consideration paid	$ 282,902	$ 0	$ 846,994
Gain (loss) on extinguishment of debt, net	(1,459)	0	8,989
Senior Notes
Debt Instrument [Line Items]
Total principal amount repurchased	284,806	0	61,043
Consideration paid	282,902	0	38,139
Write-off of debt issuance costs	3,363	0	595
Gain (loss) on extinguishment of debt, net	(1,459)	0	22,309
Senior Notes | January 2025 Notes
Debt Instrument [Line Items]
Total principal amount repurchased	122,285	0	22,087
Senior Notes | January 2028 Notes
Debt Instrument [Line Items]
Total principal amount repurchased	60,735	0	38,956
Senior Notes | July 2029 Notes
Debt Instrument [Line Items]
Total principal amount repurchased	$ 101,786	$ 0	$ 0

Debt - Senior Secured Credit Fa

Debt - Senior Secured Credit Facility (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Nov. 01, 2022	Oct. 31, 2022	Apr. 13, 2022	Apr. 12, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Unrestricted and unencumbered cash and cash equivalents maximum	$ 50,000,000
Secured Debt
Debt Instrument [Line Items]
Borrowing capacity		$ 1,300,000,000	$ 1,250,000,000
Secured Debt | Senior Secured Credit Facility
Debt Instrument [Line Items]
Commitment fee on unused capacity (as a percent)	0.50%
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 | Base Rate
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	1.50%
Secured Debt | Minimum | Secured Overnight Financing Rate (SOFR) | Senior Secured Credit Facility
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	2.50%
Secured Debt | Maximum | Base Rate
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	2.50%
Secured Debt | Maximum | Secured Overnight Financing Rate (SOFR) | Senior Secured Credit Facility
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	3.50%
Letters of credit | Secured Debt
Debt Instrument [Line Items]
Borrowing capacity	$ 80,000,000			$ 1,250,000,000	$ 1,000,000,000
Aggregate elected commitment				1,000,000,000	725,000,000
Bond buyback and distributions baskets				250,000,000	$ 50,000,000
Energy transition and technology commercialization investment basket				$ 25,000,000
Letters of credit outstanding	0					$ 44,100,000
Line of Credit | Secured Debt
Debt Instrument [Line Items]
Borrowing capacity	2,000,000,000
Current borrowing capacity	1,300,000,000
Aggregate elected commitment	1,000,000,000
Line of credit	$ 70,000,000
Credit facility, interest rate at period end (as a percent)	6.897%

Debt - July 2029 Notes (Details

Debt - July 2029 Notes (Details) - July 2029 Notes - Senior 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) - Senior Notes - USD ($)	Jan. 24, 2020	Dec. 31, 2022	Jan. 31, 2020
January 2025 Notes & January 2028 Notes
Debt Instrument [Line Items]
Proceeds from issuance of unsecured notes	$ 982,000,000
January 2025 Notes
Debt Instrument [Line Items]
Face amount of debt	$ 600,000,000
Stated rate (as a percent)	9.50%
January 2028 Notes
Debt Instrument [Line Items]
Face amount of debt	$ 400,000,000
Stated rate (as a percent)	10.125%
Senior Note 6.25 Percent Due 2023
Debt Instrument [Line Items]
Face amount of debt			$ 350,000,000
Stated rate (as a percent)		6.25%
Senior Note 5.625 Percent Due 2022
Debt Instrument [Line Items]
Face amount of debt			$ 450,000,000
Stated rate (as a percent)		5.625%

Debt - January 2022 Notes and M

Debt - January 2022 Notes and March 2023 Notes (Details) - USD ($)	3 Months Ended	12 Months Ended			33 Months Ended
	Mar. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2022	Jan. 31, 2020
Debt Instrument [Line Items]
Outstanding balance		$ 1,113,023,000	$ 1,425,858,000		$ 1,113,023,000
Consideration paid		282,902,000	0	$ 846,994,000
Loss on extinguishment of debt		1,459,000	0	(8,989,000)
Senior Notes
Debt Instrument [Line Items]
Consideration paid		282,902,000	0	38,139,000
Loss on extinguishment of debt		$ 1,459,000	$ 0	$ (22,309,000)
January 2022 Notes & March 2023 Notes | Senior Notes
Debt Instrument [Line Items]
Outstanding balance	$ 728,300,000
Consideration paid	$ 735,700,000				71,700,000
Loss on extinguishment of debt					$ 13,300,000
Senior Note 5.625 Percent Due 2022 | Senior Notes
Debt Instrument [Line Items]
Face amount of debt						$ 450,000,000
Senior Note 6.25 Percent Due 2023 | Senior Notes
Debt Instrument [Line Items]
Face amount of debt						$ 350,000,000

Debt - Interest expense (Detail

Debt - Interest expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Debt Disclosure [Abstract]
Interest expense on borrowings	$ 123,255	$ 114,800	$ 104,320
Amortization of debt issuance costs and other adjustments	5,738	4,451	3,708
Less capitalized interest	3,872	5,866	3,019
Total interest expense	$ 125,121	$ 113,385	$ 105,009

Stockholders' equity - Narrativ

Stockholders' equity - Narrative (Details) $ / shares in Units, $ in Millions			12 Months Ended
	Feb. 23, 2021 USD ($)	Jun. 01, 2020 $ / shares shares	Dec. 31, 2021 USD ($) $ / shares shares	Dec. 31, 2022 $ / shares shares	May 31, 2022 USD ($)	May 26, 2022 shares	May 25, 2022 shares	Oct. 18, 2021 $ / shares	May 31, 2020 shares
Class of Stock [Line Items]
Common stock authorized (in shares)		22,500,000	22,500,000	40,000,000		40,000,000	22,500,000		450,000,000
Authorized amount of share repurchase program | $					$ 200
Conversation ratio of reverse stock split		0.05
Common stock, par value (in USD per share) | $ / shares		$ 0.01	$ 0.01	$ 0.01				$ 0.01
Preferred stock authorized (in shares)		50,000,000	50,000,000	50,000,000
Preferred stock, par value (in USD per share) | $ / shares		$ 0.01	$ 0.01	$ 0.01
Capital stock authorized (in shares)		72,500,000
At-the-Market Offering
Class of Stock [Line Items]
Consideration received from sale of stock | $	$ 75
Stock issued in sale (in shares)			1,438,105
Maximum | At-the-Market Offering
Class of Stock [Line Items]
Consideration received from sale of stock | $			$ 72.5

Stockholders' equity - Share re

Stockholders' equity - Share repurchase program (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Class of Stock [Line Items]
Total	$ 37,290	$ 0	$ 0
Treasury stock (at cost)
Class of Stock [Line Items]
Shares of Company common stock repurchased (in shares)	490,536	0	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
	Mar. 09, 2021 $ / shares	Mar. 05, 2020 $ / shares	Dec. 31, 2022 USD ($) $ / shares	Dec. 31, 2021 $ / shares	Dec. 31, 2019	Mar. 05, 2022 $ / shares	Mar. 01, 2022 $ / shares	May 20, 2021 shares	May 19, 2021 shares	Jun. 01, 2020 shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized equity and stock-based compensation expense | $			$ 16
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)			2 years 7 days
Restricted Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value (USD per share)			$ 52.90	$ 35.57
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%
Performance Share Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Requisite service period (in years)			3 years
Total shareholder return					3 years
Fair value (USD per share)			$ 89.76	$ 64.74
Expense per performance share award (in dollars per share)			$ 89.76
Performance Share Awards | February 28, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Overall payout (as a percent)			107%
Performance Share Awards | February 28, 2019 | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout range (as a percent)					0%
Performance Share Awards | February 28, 2019 | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payout range (as a percent)					200%
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 award (in dollars per share)	$ 79.85	$ 78.92
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)			$ 51.42
Closing stock price on grant date (in USD per share)						$ 83	$ 76.60
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 | $			$ 3.1
Weighted average period over which unrecognized equity and stock-based compensation expense is expected to be recognized (in years)			1 year 18 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	1,492,500

Compensation plans - Activity f

Compensation plans - Activity for equity compensation awards (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) $ / shares shares
Restricted Stock Awards
Restricted Stock and Performance Shares Awards
Outstanding at the beginning of the period (in shares)	350,000
Granted (in shares)	255,000
Forfeited (in shares)	(58,000)
Vested (in shares)	(185,000)
Outstanding at the end of the period (in shares)	362,000
Weighted-average grant-date fair value (per share)
Outstanding at the beginning of the period (USD per share) | $ / shares	$ 35.57
Granted (in USD per share) | $ / shares	67.54
Forfeited (USD per share) | $ / shares	46.75
Vested (USD per share) | $ / shares	42.30
Outstanding at the end of the period (USD per share) | $ / shares	$ 52.90
Weighted-average exercise price (per share)
Intrinsic value of vested restricted stock awards | $	$ 14.6
Stock Option Awards
Stock Option Awards
Outstanding at the beginning of the period (in shares)	7,000
Expired or canceled (in shares)	(4,000)
Outstanding at the end of the period (in shares)	3,000
Weighted-average exercise price (per share)
Outstanding at the end of the period (in USD per share) | $ / shares	$ 275.88
Expired or canceled (in USD per share) | $ / shares	313.12
Outstanding at end of the period (in USD per share) | $ / shares	$ 235.08
Performance Share Awards
Restricted Stock and Performance Shares Awards
Outstanding at the beginning of the period (in shares)	72,000
Granted (in shares)	62,000
Forfeited (in shares)	(16,000)
Vested (in shares)	(70,000)
Outstanding at the end of the period (in shares)	48,000
Weighted-average grant-date fair value (per share)
Outstanding at the beginning of the period (USD per share) | $ / shares	$ 64.74
Granted (in USD per share) | $ / shares	89.76
Forfeited (USD per share) | $ / shares	88.28
Vested (USD per share) | $ / shares	64.53
Outstanding at the end of the period (USD per share) | $ / shares	$ 89.76
Weighted-average exercise price (per share)
Performance share conversion (in shares)	75,107
Performance Share Awards | February 28, 2019
Weighted-average exercise price (per share)
Overall payout (as a percent)	107%

Compensation plans - Performanc

Compensation plans - Performance and Phantom unit award activity (Details) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2022	Mar. 05, 2022	Mar. 01, 2022
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)	209
Forfeited (in shares)	(59)
Vested (in shares)	0
Outstanding at the end of the period (in shares)	150
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)	33
Forfeited (in shares)	0
Vested (in shares)	(15)
Outstanding at the end of the period (in shares)	18
Stock price (in USD per share)		$ 83	$ 76.60

Compensation plans - Assumption

Compensation plans - Assumptions used to estimate fair value of performance share and unit awards (Details) - $ / shares			12 Months Ended
	Mar. 09, 2021	Mar. 05, 2020	Dec. 31, 2022
Performance Share Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected option life (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 award (in dollars per share)			$ 89.76
Performance unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected option life (in years)	1 year
Risk-free interest rate (as a percent)	4.62%
Dividend yield (as a percent)	0%
Expected volatility (as a percent)	79.77%
Expense per performance share award (in dollars per share)	$ 79.85	$ 78.92

Compensation plans - Equity-bas

Compensation plans - Equity-based compensation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	$ 10,058	$ 16,028	$ 9,207
Share-settled
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-settled equity-based compensation, gross	10,186	9,258	11,635
Less amounts capitalized	(1,783)	(1,583)	(3,418)
Equity-based compensation	8,403	7,675	8,217
Restricted Stock Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-settled equity-based compensation, gross	8,596	7,594	8,839
Performance Share Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-settled equity-based compensation, gross	1,590	1,657	2,719
Stock Option Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-settled equity-based compensation, gross	0	7	77
Cash-settled
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-settled equity-based compensation, gross	1,927	8,718	1,153
Less amounts capitalized	(272)	(365)	(163)
Equity-based compensation	1,655	8,353	990
Performance unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-settled equity-based compensation, gross	741	7,480	749
Phantom unit awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-settled equity-based compensation, gross	$ 1,186	$ 1,238	$ 404

Net income (loss) per common _3

Net income (loss) per common share - Summary (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Net income (numerator):
Net income (loss)	$ 631,512	$ 145,008	$ (874,173)
Weighted-average common shares outstanding (denominator):
Basic (in shares)	16,672	14,240	11,668
Diluted (in shares)	16,867	14,464	11,668
Net income (loss) per common share:
Basic (in USD per share)	$ 37.88	$ 10.18	$ (74.92)
Diluted (in USD per share)	$ 37.44	$ 10.03	$ (74.92)
Non-vested restricted stock awards
Weighted-average common shares outstanding (denominator):
Non-vested and outstanding awards (in shares)	183	181	0
Performance Share Awards
Weighted-average common shares outstanding (denominator):
Non-vested and outstanding awards (in shares)	12	43	0

Derivatives - Narrative (Detail

Derivatives - Narrative (Details) $ in Millions	Dec. 31, 2022 USD ($) derivative	Dec. 31, 2021 USD ($)	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	$ 88.9
Fair value of contingent consideration	$ 26.6	$ 35.9	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, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Gain (loss) on derivatives, net	$ (298,723)	$ (452,175)	$ 80,114
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	$ (291,973)	$ (453,784)	$ 73,662
Contingent consideration
Derivative [Line Items]
Gain (loss) on derivatives, net	(6,764)	1,639	6,795
Interest rate
Derivative [Line Items]
Gain (loss) on derivatives, net	$ 14	$ (30)	$ (343)

Derivatives - Summary (Details)

Derivatives - Summary (Details) - Forecast - Derivatives not designated as hedges	12 Months Ended
	Dec. 31, 2024 MMBTU $ / bbl $ / MMBTU bbl	Dec. 31, 2023 MMBTU $ / MMBTU $ / bbl bbl
WTI NYMEX | Crude Oil | Collar
Derivative [Line Items]
Volume (Bbl) | bbl	0	5,607,000
WTI NYMEX | Crude Oil | Collar | Minimum
Derivative [Line Items]
Weighted-average price ($/Bbl) | $ / bbl	0	68.71
WTI NYMEX | Crude Oil | Collar | Maximum
Derivative [Line Items]
Weighted-average price ($/Bbl) | $ / bbl	0	84.90
WTI NYMEX | Outstanding at End of Period | Crude Oil | Collar
Derivative [Line Items]
Volume (Bbl) | bbl		5,089,000
WTI NYMEX | Outstanding at End of Period | Crude Oil | Collar | Minimum
Derivative [Line Items]
Weighted-average price ($/Bbl) | $ / bbl		68.58
WTI NYMEX | Outstanding at End of Period | Crude Oil | Collar | Maximum
Derivative [Line Items]
Weighted-average price ($/Bbl) | $ / bbl		84.88
Henry Hub NYMEX | Natural gas (MMcf) | Collar
Derivative [Line Items]
Volume (MMBtu) | MMBTU	0	25,550,000
Henry Hub NYMEX | Natural gas (MMcf) | Collar | Minimum
Derivative [Line Items]
Weighted-average price ($/Bbl)	0	4.14
Henry Hub NYMEX | Natural gas (MMcf) | Collar | Maximum
Derivative [Line Items]
Weighted-average price ($/Bbl)	0	8.43
Henry Hub NYMEX | Outstanding at End of Period | Natural gas (MMcf) | Collar
Derivative [Line Items]
Volume (MMBtu) | MMBTU		25,550,000
Henry Hub NYMEX | Outstanding at End of Period | Natural gas (MMcf) | Collar | Minimum
Derivative [Line Items]
Weighted-average price ($/Bbl)		4.14
Henry Hub NYMEX | Outstanding at End of Period | Natural gas (MMcf) | Collar | Maximum
Derivative [Line Items]
Weighted-average price ($/Bbl)		8.43
Waha Inside FERC to Henry Hub NYMEX | Natural gas (MMcf) | Basis Swap
Derivative [Line Items]
Weighted-average price ($/Bbl)	(0.75)	(1.54)
Volume (MMBtu) | MMBTU	3,660,000	38,350,000
Waha Inside FERC to Henry Hub NYMEX | Outstanding at End of Period | Natural gas (MMcf) | Basis Swap
Derivative [Line Items]
Weighted-average price ($/Bbl)		(1.65)
Volume (MMBtu) | MMBTU		25,550,000

Fair value measurements - Fair

Fair value measurements - Fair value hierarchy (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Assets:
Total gross fair value	$ 43,073
Net fair value presented on the consolidated balance sheets	24,670	$ 4,346
Net fair value presented on the consolidated balance sheets	24,363	32,963
Liabilities:
Total gross fair value		(142,500)
Net fair value presented on the consolidated balance sheets	(5,960)	(179,809)
Amounts offset	0	0
Net derivative asset (liability) positions	43,073	(142,500)
Level 1
Liabilities:
Net derivative asset (liability) positions	0	0
Level 2
Liabilities:
Net derivative asset (liability) positions	16,433	(178,361)
Level 3
Liabilities:
Net derivative asset (liability) positions	26,640	35,861
Commodity derivatives
Assets:
Net fair value presented on the consolidated balance sheets	22,393	0
Net fair value presented on the consolidated balance sheets		1,448
Liabilities:
Net fair value presented on the consolidated balance sheets	(5,960)	(179,757)
Contingent Consideration
Assets:
Net fair value presented on the consolidated balance sheets	2,277	4,346
Net fair value presented on the consolidated balance sheets	24,363	31,515
Interest rate
Liabilities:
Net fair value presented on the consolidated balance sheets		(52)
Current Assets | Commodity derivatives
Assets:
Total gross fair value	35,586	21,671
Amounts offset	(13,193)	(21,671)
Current Assets | Commodity derivatives | Level 1
Assets:
Total gross fair value	0	0
Current Assets | Commodity derivatives | Level 2
Assets:
Total gross fair value	35,586	21,671
Current Assets | Commodity derivatives | Level 3
Assets:
Total gross fair value	0	0
Current Assets | Contingent Consideration
Assets:
Total gross fair value	2,277	4,346
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	2,277	4,346
Noncurrent Assets | Commodity derivatives
Assets:
Total gross fair value		1,448
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		1,448
Noncurrent Assets | Commodity derivatives | Level 3
Assets:
Total gross fair value		0
Noncurrent Assets | Contingent Consideration
Assets:
Total gross fair value	24,363	31,515
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	24,363	31,515
Current Liabilities | Commodity derivatives
Liabilities:
Total gross fair value	(19,153)	(201,428)
Amounts offset	13,193	21,671
Current Liabilities | Commodity derivatives | Level 1
Liabilities:
Total gross fair value	0	0
Current Liabilities | Commodity derivatives | Level 2
Liabilities:
Total gross fair value	(19,153)	(201,428)
Current Liabilities | Commodity derivatives | Level 3
Liabilities:
Total gross fair value	$ 0	0
Current Liabilities | Interest rate
Liabilities:
Total gross fair value		(52)
Amounts offset		0
Current Liabilities | Interest rate | Level 1
Liabilities:
Total gross fair value		0
Current Liabilities | Interest rate | Level 2
Liabilities:
Total gross fair value		(52)
Current Liabilities | Interest rate | Level 3
Liabilities:
Total gross fair value		$ 0

Fair value measurements - Chang

Fair value measurements - Changes in Contingent Consideration (Details) - Level 3 - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Contingent Consideration Derivative
Change in Amount of Contingent Consideration, Liability [Roll Forward]
Settlements received for contingent consideration	$ 1,900
Realized settlements receivable at period end	600
Contingent Consideration Derivative
Change in Amount of Contingent Consideration, Liability [Roll Forward]
Balance of Level 3 at beginning of year	35,861	$ 0	$ 0
Sixth Street Contingent Consideration valuation as of Sixth Street Closing Date	0	33,832	0
Change in Sixth Street Contingent Consideration fair value	(11,678)	2,029	0
Settlements realized	2,457	0	0
Balance of Level 3 at end of year	$ 26,640	$ 35,861	$ 0

Fair value measurements - Carry

Fair value measurements - Carrying amounts and fair values of debt (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Carrying Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	$ 1,124,151	$ 1,443,957
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	455,628	577,913
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	300,309	361,044
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	400,000
Carrying Value | Secured Debt | Line of Credit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	70,000	105,000
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	1,080,329	1,463,089
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	449,122	589,471
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	292,846	378,578
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	268,416	390,000
Fair Value | Secured Debt | Line of Credit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value disclosure of debt	$ 69,945	$ 105,040

Income taxes - Income tax (expe

Income taxes - Income tax (expense) benefit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Current income tax (expense) benefit:
Federal	$ 0	$ 0	$ 0
State	(6,121)	(1,324)	0
Deferred income tax (expense) benefit:
Federal	0	0	0
State	619	(2,321)	3,946
Total income tax (expense) benefit	$ (5,502)	$ (3,645)	$ 3,946

Income taxes - Deferred income

Income taxes - Deferred income tax reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income tax (expense) benefit computed by applying the statutory rate	$ (133,773)	$ (31,217)	$ 184,405
Change in deferred tax valuation allowance	144,480	45,717	(182,634)
Non-deductible equity-based compensation	(19,301)	(13,640)	0
State income tax and change in valuation allowance	8,058	(3,274)	2,903
Other items	(4,966)	(1,231)	(728)
Total income tax (expense) benefit	$ (5,502)	$ (3,645)	$ 3,946

Income taxes - Net deferred tax

Income taxes - Net deferred tax asset (liability) (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Deferred tax assets:
Net operating loss carryforward	$ 307,357	$ 445,426
Equity-based compensation	2,933	11,123
Derivatives	0	36,639
Other	1,110	3,227
Total deferred tax asset	311,400	496,415
Valuation allowance	(298,184)	(443,390)
Deferred tax assets, net of valuation allowance	13,216	53,025
Deferred tax liabilities:
Oil and natural gas properties, midstream service assets and other fixed assets	(11,105)	(53,868)
Derivatives	(2,331)	0
Total deferred tax liabilities	(13,436)	(53,868)
Texas net deferred tax liability	$ (220)	$ (843)

Income taxes - Narrative (Detai

Income taxes - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Examination [Line Items]
Amount of federal net operating loss carry-forward limited in future periods	$ 425,900
Current tax expense	$ (6,121)	$ (1,324)	$ 0
Effective tax rate (as a percent)	1%	2%	0%
Federal
Income Tax Examination [Line Items]
Net operating loss carry-forwards	$ 1,500,000
State | Oklahoma
Income Tax Examination [Line Items]
Net operating loss carry-forwards	$ 34,400

Credit risk - Narrative (Detail

Credit risk - Narrative (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Concentration Risk [Line Items]
Net derivative asset (liability) positions	$ 43,073	$ (142,500)
Level 2
Concentration Risk [Line Items]
Net derivative asset (liability) positions	$ 16,433	$ (178,361)

Credit risk - Concentration Ris

Credit risk - Concentration Risk (Details) - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Purchaser A | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)	33%	29%	33%
Purchaser A | Purchased Oil Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)	47%	47%	69%
Purchaser B | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)	18%	14%
Purchaser B | Purchased Oil Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)	22%	31%	16%
Purchaser C | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)	17%	24%	24%
Purchaser C | Purchased Oil Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)	22%	22%	14%
Purchaser D | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)		17%	14%
Purchaser E | Oil, NGL, and Natural Gas Sales
Concentration Risk [Line Items]
Concentration risk (as a percent)			10%

Commitments and contingencies (

Commitments and contingencies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Unrecorded Unconditional Purchase Obligation [Line Items]
Minimum volume commitment deficiency payments	$ 13.2	$ 4.4	$ 4
Minimum volume commitments deficiency payments liability	11.5	$ 4.7
Firm sale and transportation commitments
Unrecorded Unconditional Purchase Obligation [Line Items]
Future drilling contracts commitments	$ 165.6

Related parties (Details)

Related parties (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Related Party Transaction [Line Items]
Capital expenditures for oil and natural gas properties	$ 566,989	$ 418,362	$ 347,359
Halliburton | Affiliated Entity
Related Party Transaction [Line Items]
Capital expenditures for oil and natural gas properties	$ 103,152	$ 69,670	$ 63,886

Organizational restructurings -

Organizational restructurings - Narrative (Details)	Jun. 29, 2021 senior_officer	Jun. 17, 2020 employee
Restructuring and Related Activities [Abstract]
Workforce reduction (positions eliminated)	14	22
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Restructuring Cost and Reserve [Line Items]
Gross equity-based compensation expense reversals	$ 10,058	$ 16,028	$ 9,207
Share-Based Compensation Awards Forfeited
Restructuring Cost and Reserve [Line Items]
Gross equity-based compensation expense reversals	$ (4,908)	$ (1,088)	$ (793)

Subsequent events - Narrative (

Subsequent events - Narrative (Details) $ in Thousands						12 Months Ended
	Feb. 14, 2023 USD ($) a shares	Feb. 13, 2023 USD ($)	Jan. 23, 2023 USD ($)	Jan. 13, 2023 USD ($)	Jan. 09, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Feb. 17, 2023 USD ($)
Subsequent Event [Line Items]
Operating lease, liability, payments, due						$ 26,620
Proceeds from long-term lines of credit						455,000	$ 570,000	$ 80,000
Payments on senior secured credit facility						490,000	$ 720,000	$ 200,000
Line of Credit | Secured Debt
Subsequent Event [Line Items]
Line of credit						70,000
Equipment
Subsequent Event [Line Items]
Operating lease, liability, payments, due						126,000
New Corporate Office
Subsequent Event [Line Items]
Operating lease, liability, payments, due						$ 24,500
Subsequent event | Line of Credit | Secured Debt
Subsequent Event [Line Items]
Proceeds from long-term lines of credit		$ 40,000		$ 40,000	$ 15,000
Payments on senior secured credit facility			$ 30,000
Line of credit									$ 135,000
Midland Basin | Subsequent event
Subsequent Event [Line Items]
Area of land (in acres) | a	11,200
Cash consideration	$ 127,600
Stock issued in asset acquisition (in shares) | shares	1,578,948

Subsequent events - Derivatives

Subsequent events - Derivatives (Details) - Forecast - Derivatives not designated as hedges	12 Months Ended
	Dec. 31, 2024 MMBTU $ / bbl $ / MMBTU bbl	Dec. 31, 2023 MMBTU $ / bbl $ / MMBTU bbl
WTI NYMEX | Crude Oil | Collar
Subsequent Event [Line Items]
Volume (Bbl) | bbl	0	5,607,000
WTI NYMEX | Crude Oil | Collar | Minimum
Subsequent Event [Line Items]
Weighted-average price ($/Bbl) | $ / bbl	0	68.71
WTI NYMEX | Crude Oil | Collar | Maximum
Subsequent Event [Line Items]
Weighted-average price ($/Bbl) | $ / bbl	0	84.90
Henry Hub NYMEX | Natural gas (MMcf) | Collar
Subsequent Event [Line Items]
Volume (MMBtu) | MMBTU	0	25,550,000
Henry Hub NYMEX | Natural gas (MMcf) | Collar | Minimum
Subsequent Event [Line Items]
Weighted-average price ($/Bbl)	0	4.14
Henry Hub NYMEX | Natural gas (MMcf) | Collar | Maximum
Subsequent Event [Line Items]
Weighted-average price ($/Bbl)	0	8.43
Waha Inside FERC to Henry Hub NYMEX | Natural gas (MMcf) | Basis Swap
Subsequent Event [Line Items]
Weighted-average price ($/Bbl)	(0.75)	(1.54)
Volume (MMBtu) | MMBTU	3,660,000	38,350,000

Supplemental oil, NGL and nat_3

Supplemental oil, NGL and natural gas disclosures (unaudited) - Incurred Capital Expenditures in oil and natural gas property acquisition, exploration and development activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property acquisition costs:
Evaluated	$ 8,295	$ 899,128	$ 11,368
Unevaluated	3,470	198,770	25,549
Exploration costs	26,384	33,482	17,337
Development costs	540,447	410,855	326,823
Total oil and natural gas properties incurred capital expenditures	$ 578,596	$ 1,542,235	$ 381,077

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, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Gross capitalized costs:
Evaluated properties	$ 9,554,706	$ 8,968,668
Unevaluated properties not being depleted	46,430	170,033
Total gross capitalized costs	9,601,136	9,138,701
Less accumulated depletion and impairment	(7,318,399)	(7,019,670)
Net capitalized costs	2,282,737	2,119,031
Oil and natural gas property costs not being amortized
Unevaluated properties not being depleted	14,707	29,705	$ 784	$ 1,234
Unevaluated properties not being depleted	$ 46,430	$ 170,033

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues:
Oil, NGL and natural gas sales	$ 1,794,374	$ 1,147,143	$ 496,355
Production costs:
Lease operating expenses	173,983	101,994	82,020
Production and ad valorem taxes	110,997	68,742	33,050
Transportation and marketing expenses	53,692	47,916	49,927
Total production costs	338,672	218,652	164,997
Other costs:
Depletion	298,259	201,691	203,492
Accretion of asset retirement obligation	3,653	4,018	4,227
Impairment expense	0	0	889,453
Income tax expense (benefit)	11,538	14,456	0
Total other costs	313,450	220,165	1,097,172
Results of operations	$ 1,142,252	$ 708,326	$ (765,814)
Effective tax rate (as a percent)	1%	2%	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, 2022 Boe location reserve_stream	Dec. 31, 2021 Boe location reserve_stream	Dec. 31, 2020 Boe reserve_stream	May 07, 2021
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)	(16,802)	38,709	1,430
Development wells drilled, net productive | location		6
Development wells drilled, net nonproductive | location		12
Extensions, discoveries and other additions (MBOE)	34,141	19,369	7,888
Sale of reserves (MBOE)	3,585	88,125
Acquisitions of reserves in place (MBOE)		100,286	7,650
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 Decreases
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	9,531	3,622	16,265
Negative Revision from Decrease in Estimated Quantities of Proved Undeveloped Locations
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	1,837	2,885	3,140
Performance, Pricing and Other Increases
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	4,351	37,341	29,080
Reinterpretation of Undeveloped Locations
Net proved oil and natural gas reserves
Revisions of previous estimates (MBOE)	9,785	7,875
Proved undeveloped locations | location	16
Drilling of New Wells
Net proved oil and natural gas reserves
Extensions, discoveries and other additions (MBOE)	3,850	6,724	5,347
Horizontal Proved Undeveloped Properties
Net proved oil and natural gas reserves
Extensions, discoveries and other additions (MBOE)	30,291	12,645	2,541
New Proved Developed Locations
Net proved oil and natural gas reserves
Acquisitions of reserves in place (MBOE)		47,310	367
Additional Acreage Acquired under Proved Locations
Net proved oil and natural gas reserves
Acquisitions of reserves in place (MBOE)		52,976	4,016
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)			8,245
New Proved Undeveloped Locations
Net proved oil and natural gas reserves
Acquisitions of reserves in place (MBOE)			3,267

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, 2022 Boe bbl Mcf	Dec. 31, 2021 Boe bbl Mcf	Dec. 31, 2020 Boe bbl Mcf
Proved developed and undeveloped reserves:
Beginning of year (MBOE) | Boe	318,640	278,228	293,377
Revisions of previous estimates (MBOE) | Boe	(16,802)	38,709	1,430
Extensions, discoveries and other additions (MBOE) | Boe	34,141	19,369	7,888
Acquisitions of reserves in place (MBOE) | Boe		100,286	7,650
Divestitures of reserves in place (MBOE) | Boe	(3,585)	(88,125)
Production (MBOE) | Boe	(30,076)	(29,827)	(32,117)
End of year (MBOE) | Boe	302,318	318,640	278,228
Proved developed reserves:
Beginning of year (energy) | Boe	232,048	253,586	243,628
End of year (energy) | Boe	222,917	232,048	253,586
Proved undeveloped reserves:
Beginning of year (energy) | Boe	86,592	24,642	49,749
End of year (energy) | Boe	79,401	86,592	24,642
Oil (MBbl)
Proved developed and undeveloped reserves:
As of December 31, 2021	120,902	67,759	78,639
Revisions of previous estimates	(9,792)	4,740	(10,517)
Extensions, discoveries and other additions	21,351	10,354	4,282
Acquisitions of reserves in place		65,572	5,182
Divestitures of reserves in place	(2,165)	(15,904)
Production	(13,838)	(11,619)	(9,827)
As of December 31, 2022	116,458	120,902	67,759
Proved developed reserves:
Beginning of year (volume)	70,727	51,751	52,711
End of year (volume)	70,333	70,727	51,751
Proved undeveloped reserves:
Beginning of year (volume)	50,175	16,008	25,928
End of year (volume)	46,125	50,175	16,008
NGL (MBbl)
Proved developed and undeveloped reserves:
As of December 31, 2021	100,047	100,922	102,198
Revisions of previous estimates	(4,561)	16,952	6,218
Extensions, discoveries and other additions	7,162	5,269	1,811
Acquisitions of reserves in place		19,711	1,310
Divestitures of reserves in place	(808)	(34,129)
Production	(8,028)	(8,678)	(10,615)
As of December 31, 2022	93,812	100,047	100,922
Proved developed reserves:
Beginning of year (volume)	78,908	96,251	90,861
End of year (volume)	75,156	78,908	96,251
Proved undeveloped reserves:
Beginning of year (volume)	21,139	4,671	11,337
End of year (volume)	18,656	21,139	4,671
Natural gas (MMcf)
Proved developed and undeveloped reserves:
As of December 31, 2021 | Mcf	586,145	657,284	675,237
Revisions of previous estimates | Mcf	(14,694)	102,080	34,376
Extensions, discoveries and other additions | Mcf	33,767	22,479	10,772
Acquisitions of reserves in place | Mcf		90,023	6,948
Divestitures of reserves in place | Mcf	(3,671)	(228,546)
Production | Mcf	(49,259)	(57,175)	(70,049)
As of December 31, 2022 | Mcf	552,288	586,145	657,284
Proved developed reserves:
Beginning of year (volume) | Mcf	494,476	633,503	600,334
End of year (volume) | Mcf	464,567	494,476	633,503
Proved undeveloped reserves:
Beginning of year (volume) | Mcf	91,669	23,781	74,903
End of year (volume) | Mcf	87,721	91,669	23,781

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, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 16,343,468	$ 11,846,148	$ 3,824,104
Future production costs	(4,136,380)	(3,595,524)	(1,740,537)
Future development costs	(1,403,721)	(1,064,527)	(351,568)
Future income tax expenses	(1,587,677)	(774,461)	(20,076)
Future net cash flows	9,215,690	6,411,636	1,711,923
10% discount for estimated timing of cash flows	(4,461,114)	(2,986,324)	(697,069)
Standardized measure of discounted future net cash flows	$ 4,754,576	3,425,312	1,014,854	$ 1,662,261
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	$ 889,453

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, 2022	Dec. 31, 2021	Dec. 31, 2020
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	$ 3,425,312	$ 1,014,854	$ 1,662,261
Changes in the year resulting from:
Sales, less production costs	(1,468,946)	(934,440)	(331,358)
Revisions of previous quantity estimates	(99,512)	426,060	199
Extensions, discoveries and other additions	667,859	293,511	60,004
Net change in prices and production costs	2,565,963	1,572,662	(770,885)
Changes in estimated future development costs	(165,579)	134,091	64,146
Previously estimated development incurred capital expenditures during the period	260,475	169,376	186,261
Acquisitions of reserves in place	0	1,509,087	14,208
Divestitures of reserves in place	(96,222)	(369,601)	0
Accretion of discount	371,625	102,607	167,227
Net change in income taxes	(418,537)	(279,722)	(1,205)
Timing differences and other	(287,862)	(213,173)	(36,004)
Standardized measure of discounted future net cash flows, end of year	$ 4,754,576	$ 3,425,312	$ 1,014,854