Ranger Oil (ROCC) 10-K 8 Mar 22 2021 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2021	Mar. 04, 2022	Jun. 30, 2021
Document Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	1-13283
Entity Registrant Name	RANGER OIL CORPORATION
Entity Incorporation, State or Country Code	VA
Entity Tax Identification Number	23-1184320
Entity Address, Address Line One	16285 Park Ten Place, Suite 500
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77084
City Area Code	713
Local Phone Number	722-6500
Title of 12(b) Security	Class A Common Stock, $0.01 Par Value
Trading Symbol	ROCC
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 360,656,066
Entity Common Stock, Shares Outstanding		43,664,292
Documents Incorporated by Reference	Part III of this Form 10-K.
Amendment Flag	false
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Entity Central Index Key	0000077159
ICFR Auditor Attestation Flag	true
Class A Common Stock
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		21,115,294
Class B Common Stock
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		22,548,998

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2021
Audit Information [Abstract]
Auditor Firm ID	248
Auditor Name	GRANT THORNTON LLP
Auditor Location	Houston, Texas

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Revenues
Total revenues and other	$ 579,491,000	$ 273,268,000	$ 471,216,000
Operating expenses
Lease operating	45,402,000	37,463,000	43,088,000
Gathering, processing and transportation	23,647,000	22,050,000	23,197,000
Production and ad valorem taxes	31,041,000	16,619,000	28,057,000
General and administrative	66,529,000	33,789,000	25,484,000
Depreciation, depletion and amortization	131,657,000	140,673,000	174,569,000
Impairments of oil and gas properties	1,811,000	391,849,000	0
Total operating expenses	300,087,000	642,443,000	294,395,000
Operating income (loss)	279,404,000	(369,175,000)	176,821,000
Other income (expense)
Interest expense, net of amounts capitalized	(33,161,000)	(31,257,000)	(35,811,000)
Loss on extinguishment of debt	(8,860,000)	0	0
Derivatives	(136,999,000)	88,422,000	(68,131,000)
Other, net	94,000	(850,000)	(153,000)
Income (loss) before income taxes	100,478,000	(312,860,000)	72,726,000
Income tax (expense) benefit	(1,560,000)	2,303,000	(2,137,000)
Net income (loss)	98,918,000	(310,557,000)	70,589,000
Net income attributable to Noncontrolling interest	(58,689,000)	0	0
Net income (loss) attributable to common shareholders	$ 40,229,000	$ (310,557,000)	$ 70,589,000
Net income (loss) per share attributable to common shareholders:
Basic (in dollars per share)	$ 2.41	$ (20.46)	$ 4.67
Diluted (in dollars per share)	$ 2.34	$ (20.46)	$ 4.67
Weighted average shares outstanding – basic	16,695	15,176	15,110
Weighted average shares outstanding – diluted	17,165	15,176	15,126
Oil and Gas, Exploration and Production [Member]
Revenues
Revenue from contract with customer	$ 517,301,000	$ 251,741,000	$ 434,713,000
Oil and Condensate [Member]
Revenues
Revenue from contract with customer	33,443,000	8,948,000	16,589,000
Natural Gas, Production [Member]
Revenues
Revenue from contract with customer	26,080,000	10,103,000	17,733,000
Product and Service, Other [Member]
Revenues
Revenue from contract with customer	$ 2,667,000	$ 2,476,000	$ 2,181,000

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 98,918	$ (310,557)	$ 70,589
Other comprehensive income (loss):
Change in pension and postretirement obligations, net of tax	20	(72)	(141)
Comprehensive income (loss)	98,938	(310,629)	70,448
Net income attributable to Noncontrolling interest	(58,689)	0	0
Other comprehensive income attributable to Noncontrolling interest	(23)	0	0
Comprehensive income (loss) attributable to common shareholders	$ 40,226	$ (310,629)	$ 70,448

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Current assets
Cash and cash equivalents	$ 23,681	$ 13,020
Accounts receivable, net of allowance for credit losses	118,594	45,849
Derivative assets	11,478	75,506
Prepaid and other current assets	20,998	19,045
Assets held for sale	11,400	0
Total current assets	186,151	153,420
Property and equipment, net (full cost method)	1,383,348	723,549
Derivative assets	2,092	25,449
Other assets	5,017	4,908
Total assets	1,576,608	907,326
Current liabilities
Accounts payable and accrued liabilities	214,381	63,089
Derivative liabilities	50,372	85,106
Current portion of long-term debt	4,129	0
Total current liabilities	268,882	148,195
Deferred income taxes	2,793	0
Derivative liabilities	23,815	28,434
Other non-current liabilities	10,358	8,362
Long-term debt, net	601,252	509,497
Commitments and contingencies (Note 14)
Equity
Preferred stock	0	0
Paid-in capital	273,329	203,463
Retained earnings	49,583	9,354
Accumulated other comprehensive loss	(111)	(131)
Ranger Oil shareholders’ equity	323,532	212,838
Noncontrolling interest	345,976	0
Total equity	669,508	212,838
Total liabilities and shareholders’ equity	$ 1,576,608	$ 907,326
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, authorized (in shares)	5,000,000	5,000,000
Class A Common Stock
Equity
Common stock	$ 729	$ 152
Class B Common Stock
Equity
Common stock	$ 2	$ 0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ 98,918,000	$ (310,557,000)	$ 70,589,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss on extinguishment of debt	8,860,000	0	0
Depreciation, depletion and amortization	131,657,000	140,673,000	174,569,000
Impairments of oil and gas properties	1,811,000	391,849,000	0
Derivative contracts:
Net (gains) losses	136,999,000	(88,422,000)	68,131,000
Cash settlements and premiums received (paid), net	(130,475,000)	78,087,000	(4,136,000)
Deferred income tax expense (benefit)	1,249,000	(1,424,000)	3,373,000
Non-cash interest expense	2,735,000	4,150,000	3,354,000
Share-based compensation	15,589,000	3,284,000	4,082,000
Other, net	19,000	13,000	47,000
Changes in operating assets and liabilities:
Accounts receivable, net	(38,676,000)	28,078,000	(5,079,000)
Accounts payable and accrued expenses	60,338,000	(24,244,000)	5,736,000
Other assets and liabilities	1,000	778,000	574,000
Net cash provided by operating activities	289,025,000	222,265,000	321,240,000
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions, net of cash acquired (paid)	11,009,000	0	(6,516,000)
Capital expenditures	(256,343,000)	(168,565,000)	(362,743,000)
Proceeds from sales of assets, net	160,000	87,000	215,000
Net cash used in investing activities	(245,174,000)	(168,478,000)	(369,044,000)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from credit facility borrowings	70,000,000	51,000,000	76,400,000
Repayments of credit facility borrowings	(176,400,000)	(99,000,000)	(35,000,000)
Repayments of second lien term loan	(200,000,000)	0	0
Proceeds from 9.25% Senior Notes due 2026, net of discount	396,072,000	0	0
Repayments of acquired and other debt	(249,700,000)	0	0
Proceeds from redeemable common units	151,160,000	0	0
Proceeds from redeemable preferred stock	2,000	0	0
Transaction costs paid on behalf of Noncontrolling interest	(5,543,000)	0	0
Issuance costs paid for Noncontrolling interest securities	(3,758,000)	0	0
Withholding taxes for share-based compensation	(656,000)	(487,000)	(1,046,000)
Debt issuance costs paid	(14,367,000)	(78,000)	(2,616,000)
Net cash provided by (used in) financing activities	(33,190,000)	(48,565,000)	37,738,000
Net increase (decrease) in cash and cash equivalents	10,661,000	5,222,000	(10,066,000)
Cash and cash equivalents – beginning of period	13,020,000	7,798,000	17,864,000
Cash and cash equivalents – end of period	23,681,000	13,020,000	7,798,000
Cash paid for:
Interest, net of amounts capitalized	15,609,000	27,333,000	32,398,000
Income tax refunds, net of payments	288,000	(2,471,000)	(2,471,000)
Non-cash investing and financing activities:
Changes in property and equipment related to capital contributions	(38,561,000)	0	0
Changes in accrued liabilities related to capital expenditures	16,726,000	(18,671,000)	(3,602,000)
Change in property and equipment related to acquisitions	(480,563,000)	0	(6,211,000)
Equity and replacement awards issued as consideration in the Lonestar Acquisition	$ 173,576,000	$ 0	$ 0

CONSOLIDATED STATEMENTS OF CA_2

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Aug. 10, 2021
Changes in property and equipment related to capital contributions	$ (38,561)	$ 0	$ 0
Equity and replacement awards issued as consideration in the Lonestar Acquisition	$ 173,576	$ 0	$ 0
Senior Notes Due 2026 | Senior Notes
Interest rate				9.25%

CONSOLIDATED STATEMENTS OF SHAR

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) shares in Thousands	Total	Preferred Stock	Common Stock	Paid-in Capital	Paid-in CapitalLonestar	Retained Earnings	Accumulated Other Comprehensive Loss	Noncontrolling Interest
Balance as of beginning of period (in shares) at Dec. 31, 2018			15,080
Balance as of beginning of period at Dec. 31, 2018	$ 447,355,000	$ 0	$ 151,000	$ 197,630,000		$ 249,492,000	$ 82,000	$ 0
Balance as of beginning of period (Accounting Standards Update 2014-09) at Dec. 31, 2018	(94,000)					(94,000)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	70,589,000					70,589,000
Share-based compensation	4,082,000			4,082,000
Restricted stock unit vesting (in shares)			56
Restricted stock unit vesting	(1,046,000)			(1,046,000)
Conversion of preferred stock into common stock	31,900,000
Other	(141,000)						(141,000)
Balance as of end of period (in shares) at Dec. 31, 2019			15,136
Balance as of end of period at Dec. 31, 2019	520,745,000	0	$ 151,000	200,666,000		319,987,000	(59,000)	0
Balance as of end of period (Accounting Standards Update 2016-02) at Dec. 31, 2019	(76,000)					(76,000)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(310,557,000)					(310,557,000)
Share-based compensation	3,284,000			3,284,000
Restricted stock unit vesting (in shares)			64
Restricted stock unit vesting	(486,000)		$ 1,000	(487,000)
Conversion of preferred stock into common stock	34,500,000
Other	(72,000)						(72,000)
Balance as of end of period (in shares) at Dec. 31, 2020			15,200
Balance as of end of period at Dec. 31, 2020	212,838,000	0	$ 152,000	203,463,000		9,354,000	(131,000)	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	98,918,000					40,229,000		58,689,000
Issuance of preferred stock	2,000	2,000
Issuance of Noncontrolling interest	179,552,000			(50,068,000)				229,620,000
Share-based compensation	15,589,000			15,589,000
Restricted stock unit vesting (in shares)			140
Restricted stock unit vesting	(656,000)		$ 2,000	(658,000)
Conversion of preferred stock into common stock (in shares)			2
Conversion of preferred stock into common stock	0	(2,000)
Issuance of common stock related to the Lonestar Acquisition (in shares)			575
Issuance of common stock related to the Lonestar Acquisition 1	163,182,000		$ 5,750,000	162,607,000
Change in ownership related to the Lonestar Acquisition	40,000			(57,604,000)	$ 57,600,000			57,644,000
Other	43,000						20,000	23,000
Balance as of end of period (in shares) at Dec. 31, 2021			21,090
Balance as of end of period at Dec. 31, 2021	$ 669,508,000	$ 0	$ 731,000	$ 273,329,000		$ 49,583,000	$ (111,000)	$ 345,976,000

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2021	Oct. 05, 2021	Jan. 15, 2021	Dec. 31, 2020
Preferred stock, par value (in dollars per share)	$ 0.01		$ 0.01	$ 0.01
Preferred stock, authorized (in shares)	5,000,000			5,000,000
Preferred stock, issued (in shares)	0			0
Common stock, par value (in dollars per share)		$ 0.01
Common stock, authorized (in shares)		110,000,000
Class A Common Stock
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01		$ 0.01
Common stock, authorized (in shares)	110,000,000			110,000,000
Common stock, issued (in shares)	21,090,259			15,200,435
Class B Common Stock
Common stock, par value (in dollars per share)	$ 0.01			$ 0.01
Common stock, authorized (in shares)	30,000,000			30,000,000
Common stock, issued (in shares)	22,548,998

Nature of Operations

Nature of Operations	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Nature of Operations	Note 1 – Nature of Operations Ranger Oil Corporation (together with its consolidated subsidiaries, unless the context otherwise requires, “Ranger Oil,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company focused on the onshore development and production of oil, natural gas liquids (“NGLs”) and natural gas. Our current operations consist of drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale (the “Eagle Ford”) in South Texas. We operate in and report our financial results and disclosures as one segment, which is the development and production of crude oil, NGLs and natural gas.

Basis of Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Basis of Presentation	Note 2 – Basis of Presentation A substantial noncontrolling interest in our subsidiaries is provided for in our consolidated statements of operations and comprehensive income (loss) as well as our consolidated balance sheets as of and for the period ended December 31, 2021 (see Note 4 for additional detail including the basis of presentation of the noncontrolling interest). Our consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) and the rules and regulations of the Securities and Exchange Commission (the “SEC”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our consolidated financial statements, have been included. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications did not have a material impact on prior period financial statements. As the Lonestar Acquisition was completed on October 5, 2021, our consolidated financial statements include Lonestar’s financial information and operating results from the Closing Date to the period ended December 31, 2021.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 3 – Summary of Significant Accounting Policies Principles of Consolidation Our consolidated financial statements include the accounts of Ranger Oil and all of its subsidiaries. Intercompany balances and transactions have been eliminated. Use of Estimates Preparation of our consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Such estimates include certain asset and liability valuations as further described in these notes. Actual results could differ from those estimates. Cash and Cash Equivalents We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Some of our account balances exceed the FDIC coverage limits. We believe our cash and cash equivalents are not subject to any material interest rate risk, equity price risk, credit risk or other market risk. Derivative Instruments We utilize derivative instruments, which are placed with financial institutions that we believe are of acceptable credit risk, to mitigate our financial exposure to commodity price and interest rate volatility. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by our board of directors. All derivative instruments are recognized in our consolidated financial statements at fair value. We have elected to report all of our derivative asset and liability positions on a gross basis on our consolidated balance sheets and not net the positions, even when a legal right-of-setoff exists. Our derivative instruments are not formally designated as hedges in the context of GAAP. In accordance with our internal policies, we do not utilize derivative instruments for speculative purposes. We recognize changes in fair value in earnings currently as a component of the Derivatives caption in our consolidated statements of operations. See Note 6. Property and Equipment Oil and Gas Properties We apply the full cost method of accounting for our oil and gas properties. Under this method, all productive and nonproductive costs incurred in the exploration, development and acquisition of oil and gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical, or seismic, drilling, completion and equipment costs. Internal costs incurred that are directly attributable to exploration, development and acquisition activities undertaken by us for our own account, and which are not attributable to production, general corporate overhead or similar activities are also capitalized. Future development costs are estimated on a property-by-property basis based on current economic conditions and are amortized as a component of depreciation, depletion and amortization (“DD&A”). Unproved properties not being amortized include unevaluated leasehold costs and associated capitalized interest. These costs are reviewed quarterly to determine whether or not and to what extent proved reserves have been assigned to a property or if an impairment has occurred due to lease expirations, general economic conditions and other factors, in which case the related costs along with associated capitalized interest are reclassified to the proved oil and gas properties subject to DD&A. At the end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated after-tax discounted future net revenues from proved properties adjusted for costs excluded from amortization (the “Ceiling Test”). The estimated after-tax discounted future net revenues are determined using the prior 12-month’s average commodity prices based on closing prices on the first day of each month, adjusted for differentials, discounted at 10%. The calculation of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are significant uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production, timing and plan of development. DD&A of our oil and gas properties is computed using the units-of-production method. We apply this method by multiplying the unamortized cost of our proved oil and gas properties, net of estimated salvage plus future development costs, by a rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves at the beginning of the period. Other Property and Equipment Other property and equipment consists primarily of gathering systems and related support equipment, vehicles, leasehold improvements, information technology hardware and capitalized software costs. Other property and equipment are carried at cost and include expenditures for additions and improvements which increase the productive lives of existing assets. Renewals and betterments, which extend the useful life of the properties, are also capitalized. Maintenance and repair costs are charged to expense as incurred. We compute depreciation and amortization of property and equipment using the straight-line method over the estimated useful life of each asset as follows: Gathering systems – 15 to 20 years and Other property and equipment – three Leases We determine if a contractual arrangement is a lease at inception and whether it is classified as operating or financing based on whether that contract conveys the right to control the use of an identified asset in exchange for consideration for a period of time. Leases are included in Other assets, Accounts payable and accrued liabilities and Other liabilities on our consolidated balance sheets and are identified as Right-of-use (“ROU”) assets, Current lease obligations and Noncurrent lease obligations, respectively, in Note 11 and Note 12. ROU assets represent our right to use an underlying asset for the lease term and lease obligations represent our obligation to make lease payments arising from the underlying contractual arrangement. Operating lease ROU assets and obligations are recognized at the commencement date based on the present value of lease payments over the lease term. The operating lease ROU assets include any lease payments made in advance and excludes lease incentives. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise such options. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Most of our leasing arrangements do not identify or otherwise provide for an implicit interest rate. Accordingly, we utilize a secured incremental borrowing rate based on information available at the commencement date in the determination of the present value of the lease payments. As most of our lease arrangements have terms ranging from two We have lease arrangements that include lease and certain non-lease components, including amounts for related taxes, insurance, common area maintenance and similar terms. We apply a practical expedient provided in Accounting Standards Codification (“ASC”) Topic 842, Leases , to not separate the lease and non-lease components. Accordingly, the ROU assets and lease obligations for such leases will include the present value of the estimated payments for the non-lease components over the lease term. Certain of our lease arrangements with contractual terms of 12 months or less are classified as short-term leases. Accordingly, we do not include the underlying ROU assets and lease obligations on our consolidated balance sheets. The associated costs are aggregated with all of our other lease arrangements and are disclosed in the tables in Note 11. Certain of our lease arrangements result in variable lease payments which, in accordance with ASC Topic 842, do not give rise to lease obligations. Rather, the basis and terms and conditions upon which such variable lease payments are determined are disclosed in Note 11. Asset Retirement Obligations We recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. Associated asset retirement costs are capitalized as part of the carrying cost of the asset. Our AROs relate to the plugging and abandonment of oil and gas wells and the associated asset is recorded as a component of oil and gas properties. After recording these amounts, the ARO is accreted to its future estimated value, and the additional capitalized costs are depreciated over the productive life of the assets. Both the accretion of the ARO and the depreciation of the related long-lived assets are included in the DD&A expense caption in our consolidated statements of operations. Income Taxes We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company’s financial statements or tax returns. Using this method, deferred tax assets and liabilities are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates. In assessing our deferred tax assets, we consider whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is assessed at each reporting period and is dependent upon the generation of future taxable income and our ability to utilize operating loss carryforwards during the periods in which the temporary differences become deductible. We also consider the scheduled reversal of deferred tax liabilities and available tax planning strategies. We recognize interest attributable to income taxes, to the extent it may be incurred, as a component of interest expense and penalties as a component of income tax expense. We are subject to ongoing tax examinations in numerous domestic jurisdictions. Accordingly, we may record incremental tax expense based upon the more-likely-than-not outcomes of uncertain tax positions. In addition, when applicable, we adjust the previously recorded tax expense to reflect examination results when the position is effectively settled. Our ongoing assessments of the more-likely-than-not outcomes of the examinations and related tax positions require judgment and can increase or decrease our effective tax rate, as well as impact our operating results. The specific timing of when the resolution of each tax position will be reached is uncertain. Noncontrolling interest Noncontrolling interest in the accompanying consolidated financial statements represents the ownership interest held by Juniper and is presented as a component of equity. When the Company’s relative ownership interest in the Partnership change, adjustments to noncontrolling interest and additional paid-in-capital, tax effected, will occur. Because these changes in the ownership interest in the Partnership do not result in a change of control, the transactions are accounted for as equity transactions under ASC Topic 810, Consolidation , which requires that any differences between the carrying value of the Company’s basis in the Partnership and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. Revenue Recognition and Associated Costs The Company recognizes revenue in accordance with ASC Topic 606, Revenue from Contracts with Customers which includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. We record revenue in the month that our oil and gas production is delivered to our customers. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. See Note 5 for further discussion. Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. We apply a practical expedient which provides for an exemption 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. Under our commodity product sales contracts, we bill our customers and recognize revenue when our performance obligations have been satisfied. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do not create material contract assets or liabilities. Crude oil . We sell our crude oil production to our customers at either the wellhead or a contractually agreed-upon delivery point, including certain regional central delivery point terminals or pipeline inter-connections. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality, location differentials and, if applicable, deductions for intermediate transportation. Costs incurred by us for gathering and transporting the products to an agreed-upon delivery point are recognized as a component of gathering, processing and transportation expense (“GPT”). NGLs . We have natural gas processing contracts in place with certain midstream processing vendors. We deliver “wet” natural gas to our midstream processing vendors at the inlet of their processing facilities through gathering lines, certain of which we own and others which are owned by gathering service providers. Subsequent to processing, NGLs are delivered or transported to a third-party customer. Depending upon the nature of the contractual arrangements with the midstream processing vendors regarding the marketing of the NGL products, we recognize revenue for NGL products on either a gross or net basis. For those contracts where we have determined that we are the principal, and the ultimate third party is our customer, we recognize revenue on a gross basis, with associated processing costs presented as GPT expenses. For those contracts where we have determined that we are the agent and the midstream processing vendor is our customer, we recognize NGL product revenues on a net basis with processing costs presented as a reduction of revenue. Natural gas . Subsequent to the processing of “wet” natural gas and the separation of NGL products, the “dry” or residue gas is purchased by the processor or delivered to us at the tailgate of the midstream processing vendors’ facilities and sold to a third-party customer. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality and location differentials, as applicable. Costs incurred by us for gathering and transportation from the wellhead through the processing facilities are recognized as a component of GPT expenses. Marketing and water disposal services . We provide marketing and water disposal services to certain of our joint venture partners and other third parties with respect to oil and gas production for which we are the operator. Pricing for such services represents a fixed rate fee based, in the case of marketing services, on the sales price of the underlying oil and gas products and, in the case of water services, on the quantity of water volume processed. Marketing revenue is recognized simultaneously with the sale of our commodity production to our customers while water service revenue is recognized in the month that the service is rendered. Direct costs associated with our marketing efforts are included in G&A expenses and direct costs associated with our water service efforts are netted against the underlying revenue. Credit Losses We monitor and assess our portfolio of accounts receivable, including those from our customers, our joint interest partners and others, when applicable, for credit losses on a monthly basis as we originate the underlying financial assets. Our review process and related internal controls take into appropriate consideration (i) past events and historical experience with the identified portfolio segments, (ii) current economic and related conditions within the broad energy industry as well as those factors with broader applicability and (iii) reasonable supportable forecasts consistent with other estimates that are inherent in our financial statements. In order to facilitate our processes for the review and assessment of credit losses, we have identified the following portfolio segments: (i) customers for our commodity production and (ii) joint interest partners which are further stratified into the following sub-segments: (a) mutual operators which includes joint interest partners with whom we are a non-operating joint interest partner in properties for which they are the operator, (b) large partners consisting of those legal entities that maintain a working interest of at least 10% in properties for which we are the operator and (c) all others which includes legal entities that maintain working interests of less than 10% in properties for which we are the operator as well as legal entities with whom we no longer have an active joint interest relationship, but continue to have transactions, including joint venture audit settlements, that from time-to-time give rise to the origination of new accounts receivable. Share-Based Compensation Our stock compensation plans permit the grant of incentive and nonqualified stock options, common stock, deferred common stock units, restricted stock and restricted stock units to our employees and directors. We measure the cost of employee services received in exchange for an award of equity-classified instruments based on the grant-date fair value of the award. Compensation cost associated with equity-classified awards are generally amortized on a straight-line basis over the applicable vesting period except for those that are based on performance which are amortized on a graded basis over the term of the applicable performance periods. Compensation cost associated with liability-classified awards is measured at the end of each reporting period and recognized based on the period of time that has elapsed during the applicable performance period. We recognize forfeitures as they occur. We recognize share-based compensation expense related to our share-based compensation plans as a component of General and administrative expenses (“G&A”) in our consolidated statements of operations. Recent Accounting Pronouncements We consider the applicability and impact of all Accounting Standard Updates (“ASUs”). ASUs not listed below were assessed and determined to be not applicable. Recently Issued Accounting Pronouncements Not Yet Adopted In October 2021, the Financial Accounting Standards Board issued ASU 2021-08, Business Combinations (Topic 805): (“ASU 2021-08”): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers. ASU 2021-08 amends Topic 805 to require the acquirer in a business combination to record contract assets and contract liabilities in accordance with Revenue from Contracts with Customers (Topic 606) at acquisition as as if it had originated the contract, rather than at fair value. This update is effective for public companies beginning after December 15, 2022, with early adoption permitted. Adoption should be applied prospectively to business combinations occurring on or after the effective date of the amendments unless early adoption occurs during an interim period in which other application rules apply. We do not expect the adoption of this update to have a material impact to our financial statements.

Transactions

Transactions	12 Months Ended
	Dec. 31, 2021
Transactions [Abstract]
Transactions	Note 4 – Transactions Acquisition of Lonestar Resources As discussed in Note 1, on October 5, 2021, the Company completed its acquisition of Lonestar in an all-stock transaction. In accordance with the terms of the Merger Agreement, Lonestar shareholders received 0.51 shares of Penn Virginia common stock for each share of Lonestar common stock held immediately prior to the effective time of the Lonestar Acquisition. Based on the closing price of Penn Virginia common stock on October 5, 2021 of $30.19, and in connection with the Lonestar Acquisition, the total value of Penn Virginia common stock issued to holders of Lonestar common stock, warrants and restricted stock units as applicable, was approximately $173.6 million. In connection with the consummation of the Lonestar Acquisition, the net proceeds from the offering of the 9.25% Senior Notes due 2026 and certain additional funds totaling $411.5 million were released from escrow on the Closing Date. Obligations under the 9.25% Senior Notes due 2026 were assumed by Penn Virginia Holdings, LLC, a Delaware limited liability company (“Holdings”), as borrower, and are guaranteed by the subsidiaries of Holdings that guarantee the Credit Facility. The net proceeds from the 9.25% Senior Notes due 2026 were used to repay and discharge $249.8 million of Lonestar’s long-term debt including accrued interest and related expenses, and the remainder, along with cash on hand, of $146.2 million was used to repay the Second Lien Term Loan including a prepayment premium and accrued interest and related expenses. See Note 9 for additional information on our debt. The Lonestar Acquisition was accounted for using the acquisition method of accounting, with Ranger Oil being treated as the accounting acquirer. Under the acquisition method of accounting, the assets and liabilities of Lonestar and its subsidiaries was recorded at their respective fair values as of the date of completion of the Lonestar Acquisition and are reflected in the Company’s balance sheet as of December 31, 2021. The purchase price allocation is substantially complete; however, it may be subject to change for up to one year subsequent to the closing date of the Lonestar Acquisition. Determining the fair value of the assets and liabilities of Lonestar requires judgment and certain assumptions to be made, the most significant of these being related to the valuation of Lonestar’s oil and gas properties. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following table sets forth the Company’s preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Preliminary Purchase Price Allocation Consideration: Fair value of the Company’s common stock issued 1 $ 173,576 Less: Replacement awards attributable to post-combination compensation cost 2 (10,394) Total consideration transferred $ 163,182 Assets: Other current assets $ 50,044 Proved oil and gas properties 476,743 ARO asset 1,239 Corporate office building and related assets 3 11,400 Other property and equipment 2,582 Other non-current assets 37 Total assets acquired $ 542,045 Liabilities: Current portion of long-term debt $ 24,187 Other current liabilities 66,150 Derivative liabilities 4 49,554 Asset retirement obligations 2,494 Long-term debt 236,478 Total liabilities assumed $ 378,863 Net Assets Acquired $ 163,182 __________________________________________________________________________________ 1 Includes the fair value of the replacement equity awards to the extent services were provided by employees of Lonestar prior to closing of $4.5 million. See Note 16 for additional information about the replacement equity awards. 2 Represents the fair value of the replacement equity awards considered post-combination services. See Note 16 for further details. 3 As of December 31, 2021, these assets met the held for sale criteria and were classified as Assets held for sale on the respective consolidated balance sheet. 4 Immediately following the Lonestar Acquisition, we paid approximately $50 million to restructure certain of Lonestar’s derivatives which were novated or terminated. We reset the majority of the swaps to reflect then current market pricing. For the period from the closing date of the Lonestar Acquisition on October 5, 2021 through December 31, 2021, approximately $62.5 million of revenues and $34.0 million of direct operating expenses were included in the Company’s consolidated statement of operations for the year ended December 31, 2021. Lonestar Acquisition-Related Expenses The following table summarizes expenses related to the Lonestar Acquisition incurred for the year ended December 31, 2021: Year Ended Bank, legal and consulting fees $ 9,856 Employee severance and related costs 7,563 Replacement awards stock-based compensation costs 10,394 Integration and rebranding costs 1,746 Total acquisition-related expenses $ 29,559 Employee severance and related costs primarily related to one-time severance and change-in-control compensation costs. Replacement awards stock-based compensation costs related to the accelerated vesting of certain Lonestar share-based awards for former Lonestar employees and directors based on the terms of the Merger Agreement and existing change-in-control provisions within the former Lonestar employment agreements. Pro Forma Operating Results (Unaudited) The following unaudited pro forma condensed financial data for the years ended December 31, 2021 and 2020 was derived from the historical financial statements of the Company giving effect to the Lonestar Acquisition, as if it had occurred on January 1, 2020. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Lonestar’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Lonestar’s outstanding shares of common stock and equity awards as of the closing date of the Lonestar Acquisition, (ii) the depletion of Lonestar’s fair-valued proved oil and natural gas properties under the full cost accounting method as well as other impacts of converting Lonestar from successful efforts to the full cost accounting method and (iii) the estimated tax impacts of the pro forma adjustments. The pro forma results of operations do not include any cost savings or other synergies that may result from the Lonestar Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the Lonestar assets. The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Lonestar Acquisition taken place on January 1, 2020 and is not intended to be a projection of future results. December 31, 2021 2020 Total revenues $ 729,026 $ 389,495 Net income (loss) attributable to common shareholders $ 74,355 $ (321,951) Juniper Transactions On January 15, 2021 (the “Juniper Closing Date”), the Company consummated the transactions (collectively, the “Juniper Transactions”) contemplated by: (i) the Contribution Agreement, dated November 2, 2020 (the “Contribution Agreement”), by and among the Company, PV Energy Holdings, L.P. (the “Partnership”) and JSTX Holdings, LLC (“JSTX”), an affiliate of Juniper Capital Advisors, L.P. (“Juniper Capital” and, together with JSTX and Rocky Creek, “Juniper”); and (ii) the Contribution Agreement, dated November 2, 2020 (the “Asset Agreement,” and, together with the Contribution Agreement, the “Juniper Transaction Agreements”), by and among Rocky Creek Resources, LLC, an affiliate of Juniper Capital (“Rocky Creek”), the Company and the Partnership. In connection with the consummation of the Juniper Transactions, the Company completed a reorganization into an up-C structure which was intended to, among other things, result in the affiliates of Juniper Capital having a voting interest in the Company that is commensurate with such holders’ economic interest in the Partnership, including (i) the conversion of each of the Company’s corporate subsidiaries into limited liability companies which are disregarded for U.S. federal income tax purposes, including the conversion of Penn Virginia Holding Corp. into Holdings, and (ii) the Company’s contribution of all of its equity interests in Holdings to the Partnership in exchange for 15,268,686 newly issued common units representing limited partner interests (the “Common Units”). Following consummation of this reorganization, the parent company, Ranger Oil Corporation, and the Partnership are holding companies with no other operations, material cash flows, or material assets or liabilities other than the equity interests in Holdings. On the Juniper Closing Date, (i) pursuant to the terms of the Contribution Agreement, JSTX contributed to the Partnership, as a capital contribution, $150 million in cash in exchange for 17,142,857 newly issued Common Units and the Company issued to JSTX 171,428.57 shares of Series A Preferred Stock, par value $0.01 per share, of the Company (“Series A Preferred Stock”) (now Class B Common Stock as discussed below) at a price equal to the par value of the shares acquired, and (ii) pursuant to the terms of the Asset Agreement, including certain closing adjustments based on a September 1, 2020 effective date (the “Effective Date”), Rocky Creek contributed to our operating subsidiary certain oil and gas assets in exchange for 5,405,252 newly issued Common Units and the Company issued to Rocky Creek 54,052.52 shares of Series A Preferred Stock (5,406,141 Common Units and 54,061.41 shares of Series A Preferred Stock after post-closing adjustments) at a price equal to the par value of the shares acquired, including 495,900 Common Units and 4,959 shares of Series A Preferred Stock placed in a restricted account to support post-closing indemnification claims, 50% of such amount of which was disbursed 180 days after the Juniper Closing Date and the remainder was disbursed one year after the Juniper Closing Date. In connection with the contribution of the oil and gas assets under the Asset Agreement, we received $1.2 million of revenues attributable to production from the Rocky Creek assets for the period from December 1, 2020 through the Juniper Closing Date. We incurred a total of $19.0 million of professional fees, including advisory, legal, consulting fees and other costs in connection with the Juniper Transactions. A total of $5.0 million were attributable to services and costs incurred and recognized in 2020 as G&A. The remaining $14.0 million of costs were incurred in January 2021 or otherwise incurred contingent upon the closing of the Juniper Transactions, including $5.5 million of transaction costs incurred by Juniper that were required to be paid by the Company under the Juniper Transaction Agreements as well as $3.8 million of costs incurred by us related to the issuance of the Series A Preferred Stock and Common Units. Collectively, these amounts were classified as a reduction to the capital contribution on our consolidated balance sheets. The remainder of $4.7 million, representing professional fees and other costs, was recognized as a component of G&A in the quarter ended March 31, 2021. In determining the appropriate accounting for the Partnership and Juniper’s interest, we considered the guidance in ASC Topic 810, Consolidation . The Partnership is considered a variable interest entity for which the Company is the primary beneficiary as it has a controlling financial interest in the Partnership and has the power to direct the activities most significant to the Partnership’s economic performance, as well as the obligation to absorb losses and receive benefits that are potentially significant. As such, the Partnership is reflected as a consolidated subsidiary in the consolidated financial statements. The ownership interest in the Partnership held by Juniper (the “Noncontrolling interest”) is included in the consolidated balance sheets as Noncontrolling interest, which is classified within permanent equity. The Noncontrolling interest is classified in permanent equity as it does not meet the definition of a liability under ASC 480, Distinguishing Liabilities from Equity and, among other considerations, the Common Units are optionally redeemable by the holder for a fixed number of shares (on a one-for-one basis) and there is no fixed or determinable date or fixed or determinable price for redemption; further, while the Common Units may be redeemed with Class A Common Stock or cash, the method of settlement is solely at the discretion of the Company, with the Company having the ability to settle the redemption in shares. Additionally, while the holders of the Series A Preferred Stock, who also own the Common Units, could cause the Noncontrolling interest to be redeemed through an event that is not solely within the control of the Company such as a change-in-control, through their majority voting rights, all holders of equally and more subordinated equity interests in the Company would be entitled to receive the same form of consideration upon such event. The Noncontrolling interest percentage is based on the proportionate amount of the number of Common Units held by Juniper to the total Common Units outstanding which is also equivalent to the voting power in the Company associated with the Series A Preferred Stock held by Juniper. The Noncontrolling interest was initially measured on the Juniper Closing Date as the sum of (i) total Shareholders’ equity immediately prior to the closing of the Juniper Transactions, (ii) the fair value of Juniper’s and Rocky Creek’s contributions provided in exchange for Common Units and Series A Preferred Stock (net of the Juniper transaction costs and securities issuance costs paid by the Company and including the cash received directly by the Company for a portion of the Rocky Creek revenues as discussed above and AROs associated with the contributed properties); and (iii) a deferred income tax adjustment attributable to the Juniper Transactions, the total of which was then multiplied by the Noncontrolling interest percentage. The difference between the calculated Noncontrolling interest and the fair value of the consideration received was recorded as a reduction to paid-in capital. On October 6, 2021, the Company, JSTX and Rocky Creek entered into a Contribution and Exchange Agreement, whereby all outstanding shares of the Series A Preferred Stock were exchanged for newly issued shares of Class B Common Stock (“Class B Common Stock”), at a ratio of one share of Class B Common Stock for each 1/100th of a share of Series A Preferred Stock and the designation of the Series A Preferred Stock was cancelled. See Note 15 for additional information. The following table reconciles the initial investment by Juniper and the carrying value of their Noncontrolling interest as of the Juniper Closing Date (after post-closing adjustments): Cash contribution $ 150,000 Issue costs paid for Noncontrolling interest securities (3,758) Transaction costs paid on behalf of Noncontrolling interest (5,543) Fair value of Rocky Creek oil and gas properties contributed 38,561 Revenues received attributable to contributed properties 1,160 Suspense revenues attributable to the contributed properties (146) Asset retirement obligations of the contributed properties (14) Fair value of capital contributions 180,260 Income tax adjustment attributable to the Juniper Transactions (708) Total shareholders’ equity prior to the Juniper Closing Date 205,558 $ 385,110 Juniper voting power through Series A Preferred Stock 59.6 % Noncontrolling interest as of the Juniper Closing Date $ 229,620 Due to the Lonestar Acquisition in October 2021, a change in ownership of the Noncontrolling interest occurred. Refer to Note 17 for additional information. Eagle Ford Working Interests In 2019, we acquired working interests in certain properties for which we are the operator from our joint venture partners in a series of transactions for cash consideration of $6.5 million. Funding for these acquisitions was provided by borrowings under the Credit Facility.

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2021
Receivables [Abstract]
Revenue Recognition	Note 5 – Revenue Recognition The Company’s revenues are derived from contracts for crude oil, natural gas and NGL sales and other services, as described in Note 3. Our accounts receivable consists mainly of trade receivables from commodity sales and joint interest billings due from partners on properties we operate. Our allowance for credit losses is entirely attributable to receivables from joint interest partners. We generally have the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, our oil, natural gas, and NGL receivables are collected within 30 to 90 days.The following table summarizes our accounts receivable by type as of the dates presented: December 31, 2021 2020 Customers $ 96,195 $ 39,672 Joint interest partners 21,755 3,079 Derivative settlements from counterparties 1,037 3,287 Other 18 8 Total 119,005 46,046 Less: Allowance for credit losses (411) (197) Accounts receivable, net of allowance for credit losses $ 118,594 $ 45,849 Major Customers For the year ended December 31, 2021, three customers accounted for 48% of our consolidated product revenues, of which 22%, 14%, and 12% of the consolidated revenues were generated from these customers, respectively. For the year ended December 31, 2020, three customers accounted for 56% of our consolidated product revenues, of which 27%, 19%, and 10% of the consolidated revenues were generated from these customers, respectively. For the year ended December 31, 2019, four customers accounted for 76% of our consolidated product revenues of which 37%, 18%, 11%, and 10% of the consolidated revenues were generated from these customers, respectively.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Note 6 – Derivative Instruments We utilize derivative instruments, typically swaps, put options and call options which are placed with financial institutions that we believe are acceptable credit risks, to mitigate our financial exposure to commodity price volatility associated with anticipated sales of our future production and volatility in interest rates attributable to our variable rate debt instruments. Our derivative instruments are not formally designated as hedges for accounting purposes. While the use of derivative instruments limits the risk of adverse commodity price and interest rate movements, such use may also limit the beneficial impact of future product revenues and interest expense from favorable commodity price and interest rate movements. From time to time, we may enter into incremental derivative contracts in order to increase the notional volume of production we are hedging, restructure existing derivative contracts or enter into other derivative contracts resulting in modification to the terms of existing contracts. In accordance with our internal policies, we do not utilize derivative instruments for speculative purposes. For our commodity derivatives, we typically combine swaps, purchased put options, purchased call options, sold put options and sold call options in order to achieve various hedging objectives. Certain of these objectives result in combinations that operate as collars which include purchased put options and sold call options, three-way collars, which include purchased put options, sold put options and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap, among others. Commodity Derivatives The following is a general description of the commodity derivative instruments we employ: Swaps . A swap contract is an agreement between two parties pursuant to which the parties exchange payments at specified dates on the basis of a specified notional amount, or the swap price, with the payments calculated by reference to specified commodities or indexes. The purchasing counterparty to a swap contract is required to make a payment to selling counterparty based on the amount of the swap price in excess of the settlement price multiplied by the notional volume if the settlement price for any settlement period is below the swap price for such contract. We are required to make a payment to the counterparty based on the amount of the settlement price in excess of the swap price multiplied by the notional volume if the settlement price for any settlement period is above the swap price for such contract. Put Options . A put option has a defined strike, or floor price. We have entered into put option contracts in the roles of buyer and seller depending upon our particular hedging objective. The buyer of the put option pays the seller a premium to enter into the contract. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the notional volume. When the settlement price is above the floor price, the put option expires worthless. Certain of our purchased put options have deferred premiums. For the deferred premium puts, we agree to pay a premium to the counterparty at the time of settlement. Call Options . A call option has a defined strike, or ceiling price. We have entered into call option contracts in the roles of buyer and seller depending upon our particular hedging objective. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the notional volume. When the settlement price is below the ceiling price, the call option expires worthless. Two-Way Collars . A two-way collar is an arrangement that contains a sold call option, which establishes a maximum price (ceiling price) we will receive for the contract volumes, and a purchased put, which establishes a minimum price (floor price) we will receive based on an index price. We have entered into two-way collars periodically to achieve particular hedging objectives. When the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price. If the index price is between the floor and ceiling prices, no payments are due from either party. When the index price is below the floor price, we will receive the difference between the floor price and the index price. The following table sets forth our commodity derivative contracts as of December 31, 2021: Commodity Derivatives 1Q2022 2Q2022 3Q2022 4Q2022 1Q2023 2Q2023 3Q2023 4Q2023 1Q2024 2Q2024 NYMEX WTI Crude Swaps Average Volume Per Day (bbl) 3,250 3,000 3,000 3,000 2,500 2,400 2,807 2,657 462 462 Weighted Average Swap Price ($/bbl) $ 75.16 $ 74.12 $ 73.01 $ 69.20 $ 54.40 $ 54.26 $ 54.92 $ 54.93 $ 58.75 $ 58.75 NYMEX WTI Crude Collars Average Volume Per Day (bbl) 17,083 14,423 7,745 6,114 2,917 2,885 Weighted Average Purchased Put Price ($/bbl) $ 56.10 $ 54.29 $ 47.37 $ 45.33 $ 40.00 $ 40.00 Weighted Average Sold Call Price ($/bbl) $ 70.49 $ 72.84 $ 64.60 $ 60.87 $ 50.00 $ 50.00 NYMEX WTI Purchased Puts Average Volume Per Day (bbl) 9,444 Weighted Average Purchased Put Price ($/bbl) $ 65.74 NYMEX WTI Crude CMA Roll Basis Swaps Average Volume Per Day (bbl) 13,333 13,187 6,522 6,522 Weighted Average Swap Price ($/bbl) $ 0.880 $ 0.880 $ 1.135 $ 1.135 NYMEX HH Swaps Average Volume Per Day (MMBtu) 17,500 12,500 12,500 12,500 10,000 7,500 Weighted Average Swap Price ($/MMBtu) $ 4.349 $ 3.727 $ 3.745 $ 3.793 $ 3.620 $ 3.690 NYMEX HH Collars Average Volume Per Day (MMBtu) 3,333 13,187 13,043 13,043 11,538 11,413 11,413 11,538 11,538 Weighted Average Purchased Put Price ($/MMBtu) $ 4.150 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.328 Weighted Average Sold Call Price ($/MMBtu) $ 5.750 $ 3.220 $ 3.220 $ 3.220 $ 2.682 $ 2.682 $ 2.682 $ 3.650 $ 3.000 OPIS Mt Belv Ethane Swaps Average Volume per Day (gal) 28,022 27,717 27,717 98,901 34,239 34,239 34,615 Weighted Average Fixed Price ($/gal) $ 0.2500 $ 0.2500 $ 0.2500 $ 0.2288 $ 0.2275 $ 0.2275 $ 0.2275 Interest Rate Derivatives As of December 31, 2021, we had a series of interest rate swap contracts (the “Interest Rate Swaps”) establishing fixed interest rates on a portion of our variable interest rate indebtedness. The notional amount of the Interest Rate Swaps totals $300 million, with us paying a weighted average fixed rate of 1.36% on the notional amount, and the counterparties paying a variable rate equal to LIBOR through May 2022. Financial Statement Impact of Derivatives The impact of our derivatives activities on income is included within Derivatives on our consolidated statements of operations. Derivative contracts that have expired at the end of a period, but for which cash had not been received or paid as of the balance sheet date, have been recognized as components of Accounts receivable (see Note 5) and Accounts payable and accrued liabilities (see Note 12) on the consolidated balance sheets. The effects of derivative gains and (losses) and cash settlements are reported as adjustments to reconcile net income (loss) to net cash provided by operating activities. These items are recorded within the Derivative contracts section of our consolidated statements of cash flows under Net (gains) losses and Cash settlements and premiums received (paid), net. The following table summarizes the effects of our derivative activities for the periods presented: Year Ended December 31, 2021 2020 2019 Interest Rate Swap losses recognized in the consolidated statements of operations $ (2) $ (7,510) $ — Commodity gains (losses) recognized in the consolidated statements of operations (136,997) 95,932 (68,131) $ (136,999) $ 88,422 $ (68,131) Interest rate cash settlements recognized in the consolidated statements of cash flows $ (3,822) $ (2,210) $ — Commodity cash settlements and premiums received (paid) recognized in the consolidated statements of cash flows (77,099) 80,297 (4,136) Commodity cash settlements paid for acquired derivatives recognized in the consolidated statements of cash flows (49,554) — — $ (130,475) $ 78,087 $ (4,136) The following table summarizes the fair value of our derivative instruments, which we elect to present on gross basis, as well as the locations of these instruments on our consolidated balance sheets as of the dates presented: Fair Values December 31, 2021 December 31, 2020 Type Balance Sheet Location Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Interest rate contracts Derivative assets/liabilities – current $ — $ 1,480 $ — $ 3,655 Commodity contracts Derivative assets/liabilities – current 11,478 48,892 75,506 81,451 Interest rate contracts Derivative assets/liabilities – non-current — — — 1,645 Commodity contracts Derivative assets/liabilities – non-current 2,092 23,815 25,449 26,789 $ 13,570 $ 74,187 $ 100,955 $ 113,540 As of December 31, 2021, we reported net commodity derivative liabilities of $59.1 million and net Interest Rate Swap liabilities of $1.5 million. The contracts associated with these positions are with eight counterparties for commodity derivatives and four counterparties for Interest Rate Swaps, all of which are investment grade financial institutions and are participants in the Credit Facility. This concentration may impact our overall credit risk in that these counterparties may be similarly affected by changes in economic or other conditions. Non-performance risk is incorporated by utilizing discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is in a liability position. The agreements underlying our derivative instruments include provisions for the netting of settlements with the counterparties for contracts of similar type. We have neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. Furthermore, our derivative contracts are not subject to margin calls or similar accelerations. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties. See Note 13 for information regarding the fair value of our derivative instruments.

Property and Equipment

Property and Equipment	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Property and Equipment	Note 7 – Property and Equipment The following table summarizes our property and equipment as of the dates presented: December 31, 2021 2020 Oil and gas properties: Proved $ 2,327,686 $ 1,545,910 Unproved 57,900 49,935 Total oil and gas properties 2,385,586 1,595,845 Other property and equipment 1 31,055 27,746 Total properties and equipment 2,416,641 1,623,591 Accumulated depreciation, depletion, amortization and impairments (1,033,293) (900,042) Total property and equipment, net $ 1,383,348 $ 723,549 _______________________ 1 Excludes the corporate office building and related assets acquired in connection with the Lonestar Acquisition that were classified as Assets held for sale on the consolidated balance sheets as of December 31, 2021. Unproved property costs of $57.9 million and $49.9 million have been excluded from amortization as of December 31, 2021 and December 31, 2020, respectively. An additional $1.2 million of costs, associated with wells in-progress for which we had not previously recognized any proved undeveloped reserves, were excluded from amortization as of December 31, 2020. The total costs not subject to amortization as of December 31, 2021 were incurred in the following periods: $8.4 million in 2021, $0.7 million in 2020, zero in 2019 and $37.3 million prior to 2018 as well as $11.5 million of capitalized interest applied thereto. We transferred $17.8 million and $8.3 million of undeveloped leasehold costs, including capitalized interest, associated with proved undeveloped reserves, acreage unlikely to be drilled or expiring acreage, from unproved properties to the full cost pool during the years ended December 31, 2021 and 2020, respectively. We capitalized internal costs of $4.1 million, $2.1 million and $4.1 million and interest of $3.6 million, $2.7 million and $4.1 million during the years ended December 31, 2021, 2020 and 2019 respectively, in accordance with our accounting policies. Average DD&A per boe of proved oil and gas properties was $12.96, $15.83 and $17.25 for the years ended December 31, 2021, 2020 and 2019, respectively. Certain events such as the novel coronavirus (“COVID-19”) pandemic and the decisions by the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, collectively “OPEC+”) have negatively impacted the oil and gas industry with significant declines in crude oil prices and oversupply of crude oil and may continues to negatively affect our business. Because the Ceiling Test utilizes commodity prices based on a trailing 12 month average, the decline in commodity prices as a result of COVID-19 and macroeconomic factors resulted in impairments of our oil and gas properties of $1.8 million and $391.8 million, respectively, during the years ended December 31, 2021 and 2020. We did not record any impairments of its oil and gas properties during the year ended December 31, 2019.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	The following table reconciles our AROs as of the dates presented, which are included within Other liabilities on our consolidated balance sheets: Year Ended December 31, 2021 2020 Balance at beginning of period $ 5,461 $ 4,934 Changes in estimates — 33 Liabilities incurred 226 121 Liabilities settled (228) — Acquisitions of properties 2,508 16 Accretion expense 446 357 Balance at end of period $ 8,413 $ 5,461

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Long-Term Debt	Note 9 – Long-Term Debt The following table summarizes our long-term debt as of the dates presented: December 31, 2021 December 31, 2020 Credit Facility $ 208,000 $ 314,400 Second Lien Term Loan — 200,000 9.25% Senior Notes due 2026 400,000 — Mortgage debt 1 8,438 — Other 2 2,516 — Total 618,954 514,400 Less: Unamortized discount 3 (3,720) (1,604) Less: Unamortized deferred issuance costs 3, 4 (9,853) (3,299) Total, net $ 605,381 $ 509,497 Less: Current portion (4,129) — Long-term debt, net $ 601,252 $ 509,497 _______________________ 1 The mortgage debt relates to the corporate office building and related assets acquired in connection with the Lonestar Acquisition for which assets are held as collateral for such debt. As of December 31, 2021, these assets met the held for sale criteria and were classified as Assets held for sale on the consolidated balance sheets. 2 Other includes approximately $2.2 million related to a PPP loan assumed in the Lonestar Acquisition which was fully forgiven subsequent to December 31, 2021. 3 Prior to the repayment of the Second Lien Term Loan as discussed below, discount and issuance costs of the Second Lien Term Loan were amortized over the term of the underlying loan using the effective-interest method. The discount and issuance costs of the 9.25% Senior Notes due 2026 are being amortized over its respective term using the effective-interest method. 4 Excludes issuance costs associated with the Credit Facility, which represent costs attributable to the access to credit over its contractual term, that have been presented as a component of Other assets (see Note 12) and are being amortized over the term of the Credit Facility using the straight-line method. Credit Facility As of December 31, 2021, the Credit Facility had a $1.0 billion revolving commitment and a $725 million borrowing base, with aggregate elected commitments of $400 million, and a $25 million sublimit for the issuance of letters of credit. Availability under the Credit Facility may not exceed the lesser of the aggregate elected commitments or the borrowing base less outstanding advances and letters of credit; The borrowing base under the Credit Facility is redetermined semi-annually, generally in the Spring and Fall of each year. Additionally, we and the Credit Facility lenders may, upon request, initiate a redetermination at any time during the six-month period between scheduled redeterminations. The Credit Facility is available to us for general corporate purposes, including working capital. In August 2021, we entered into the Master Assignment, Agreement and Amendment No. 11 to Credit Agreement (the “Eleventh Amendment”). The Eleventh Amendment, in addition to other changes described therein, amended the Credit Facility to, effective on the closing of the Lonestar Acquisition and satisfaction of other conditions set forth therein, (1) increase the borrowing base from $375 million to $600 million, with aggregate elected commitments of $400 million, (2) remove certain availability restrictions, (3) remove minimum hedging requirements, (4) remove the first lien leverage ratio covenant, (5) remove the Partnership and PV Energy Holdings GP, LLC as guarantors, and (6) extend the maturity date from May 2024 to the date that is the four year anniversary of the date such amendment became effective, or October 6, 2025. Subsequent to the Eleventh Amendment, the borrowing base was further increased to $725 million effective December 31, 2021, with aggregate elected commitments remaining at $400 million. The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 1.50% to 2.50%, determined based on the utilization level under the Credit Facility or (b) a Eurodollar rate, including LIBOR through 2023, plus an applicable margin ranging from 2.50% to 3.50%, determined based on the utilization level under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on Eurodollar borrowings is payable every one three The Credit Facility requires us to maintain (1) a minimum current ratio (as defined in the Credit Facility, which considers the unused portion of the total commitment as a current asset), measured as of the last day of each fiscal quarter of 1.00 to 1.00 and (2) a maximum leverage ratio (consolidated indebtedness to adjusted earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses, both as defined in the Credit Facility), measured as of the last day of each fiscal quarter, of 3.50 to 1.00. The Credit Facility also contains other customary affirmative and negative covenants as well as events of default and remedies. If we do not comply with the financial and other covenants in the Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Credit Facility. As of December 31, 2021 and 2020, we had $0.9 million and $0.4 million in letters of credit outstanding under the Credit Facility. In the years ended December 31, 2021 and 2020, we incurred and capitalized issue costs of $2.6 million and $0.1 million, respectively, in connection with amendments to the Credit Facility. Additionally, during 2021, we wrote off $0.8 million of previously deferred debt issue costs associated with the Eleventh Amendment and during 2020, we wrote off $0.9 million of previously deferred debt issue costs due to a decrease in the borrowing base associated with an amendment during the first half of 2020. Second Lien Term Loan We entered into the $200 million Second Lien Term Loan in September 2017 to fund a significant acquisition as well as related fees and expenses. In January 2021, the amendment dated November 2, 2020 (the “Second Lien Amendment”) became effective at which time we made a $50.0 million prepayment as well as a $1.3 million principal payment to a single participant lender to liquidate their interest in the Second Lien Term Loan. The Second Lien Amendment provided for (i) the extension of the maturity date of the Second Lien Term Loan to September 29, 2024, (ii) an increase to the margin applicable to advances under the Second Lien Term Loan; (iii) the imposition of certain limitations on capital expenditures, acquisitions and investments if the Asset Coverage Ratio (as defined therein) at the end of any fiscal quarter is less than 1.25 to 1.00, (iv) the requirement for maximum and, in certain circumstances as described therein, minimum hedging arrangements, (v) beginning in 2021, a requirement to make quarterly amortization payments equal to $1.875 million and (vi) a provision for the replacement of the LIBOR interest rate upon its expiration. During 2021, we incurred and capitalized $1.4 million of issue costs in connection with the Second Lien Amendment and wrote off $1.2 million of previously capitalized issue costs and original issue discount allocable to the aforementioned prepayments as a loss on extinguishment of debt. The outstanding borrowings under the Second Lien Term Loan bore interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin of 7.25% or (b) a Eurodollar rate, including LIBOR, with a floor of 1.00%, plus an applicable margin of 8.25%; provided that the applicable margin would increase to 8.25% and 9.25%, respectively, during any quarter in which the quarterly amortization payment was not made. Interest on reference rate borrowings was payable quarterly in arrears and computed on the basis of a year of 365/366 days, and interest on Eurodollar borrowings was payable every one or three months (including in three month intervals if we select a six-month interest period), at our election and computed on the basis of a 360-day year. The Second Lien Term Loan was collateralized by substantially all of our operating subsidiaries’ assets with lien priority subordinated to the liens securing the Credit Facility. On October 5, 2021, Holdings repaid all of its outstanding obligations under the Second Lien Term Loan and terminated the Second Lien Term Loan. In accordance with the Second Lien Term Loan, we incurred a prepayment premium of 102% as a result of repayment. In connection with the repayment of the Second Lien Term Loan, we incurred costs related to the premium and write off of unamortized discount and issuance costs of $6.9 million recorded as a loss on extinguishment of debt. 9.25% Senior Notes due 2026 On August 10, 2021, our indirect, wholly-owned subsidiary Penn Virginia Escrow LLC (the “Escrow Issuer”) completed an offering of $400 million aggregate principal amount of senior unsecured notes due 2026 (the “9.25% Senior Notes due 2026”) that bear interest at 9.25% and were sold at 99.018% of par. The proceeds of the offering, net of discount, and other funds were initially deposited in an escrow account pending satisfaction of certain conditions, including the consummation of the Lonestar Acquisition on or prior to November 26, 2021. In connection with the consummation of the Lonestar Acquisition, the net proceeds from the offering of the 9.25% Senior Notes due 2026 and certain additional funds totaling $411.5 million were released from escrow on October 5, 2021. Obligations under the 9.25% Senior Notes due 2026 were assumed by Holdings, as borrower, and are guaranteed by the subsidiaries of Holdings that guarantee the Credit Facility. The net proceeds from the 9.25% Senior Notes due 2026 were used to repay and discharge $249.8 million of Lonestar’s long-term debt including accrued interest and related expenses, and the remainder, along with cash on hand, of $146.2 million was used to repay the Second Lien Term Loan including a prepayment premium and accrued interest and related expenses. During 2021, we incurred and capitalized $10.4 million of issue costs in connection with the 9.25% Senior Notes due 2026. See Note 4 for additional information. The indenture governing the 9.25% Senior Notes due 2026 (the “Indenture”) also contains other customary affirmative and negative covenants as well as events of default and remedies.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income Taxes	Note 10 – Income Taxes The following table summarizes our provision for income taxes for the periods presented: Year Ended December 31, 2021 2020 2019 Current income tax expense (benefit) Federal $ — $ (1,236) $ (1,236) State 311 357 — Total current income tax expense (benefit) 311 (879) (1,236) Deferred income tax expense (benefit) Federal — 1,236 1,236 State 1,249 (2,660) 2,137 Total deferred income tax expense (benefit) 1,249 (1,424) 3,373 Income tax expense (benefit) $ 1,560 $ (2,303) $ 2,137 The following table reconciles the difference between the income tax expense (benefit) computed by applying the statutory tax rate to our income (loss) before income taxes and our reported income tax expense (benefit) for the periods presented: Year Ended December 31, 2021 2020 2019 Computed at federal statutory rate $ 21,100 21.0 % $ (65,701) 21.0 % $ 15,272 21.0 % State income taxes, net of federal income tax benefit 1,560 1.6 % (1,856) 0.6 % 1,494 2.1 % Change in valuation allowance (9,348) (9.3) % 64,062 (20.5) % (14,240) (19.6) % Noncontrolling interest (12,501) (12.4) % — — % — — % Other, net 749 0.7 % 1,192 (0.4) % (389) (0.5) % $ 1,560 1.6 % $ (2,303) 0.7 % $ 2,137 3.0 % The following table summarizes the principal components of our deferred income tax assets and liabilities as of the dates presented: December 31, 2021 2020 Deferred tax assets: Net operating loss (“NOL”) carryforwards $ 203,243 $ 180,531 Asset retirement obligations 63 1,188 Property and equipment 24,585 — Pension and postretirement benefits — 301 Share-based compensation — 467 Fair value of derivative instruments 493 2,737 Interest expense limitation 13,747 — ROU assets — 564 Other 18 1,484 Total deferred tax assets 242,149 187,272 Less: Valuation allowance (205,617) (179,006) Total net deferred tax assets $ 36,532 $ 8,266 Deferred tax liabilities: Property and equipment $ 3,357 $ 7,728 Investment in the Partnership 35,968 — ROU obligations — 538 Total deferred tax liabilities $ 39,325 $ 8,266 Net deferred tax liabilities $ (2,793) $ — Income Tax Provision For the year ended December 31, 2021, we did not have any current federal tax benefits. The provision for the years ended December 31, 2020 and 2019 includes current federal benefits of $1.2 million and $1.2 million attributable to refunds of AMT credits for the 2020 and 2019 tax years, respectively. The amounts attributable to 2020 combined the amounts attributable to 2019, which had been recognized on our consolidated balance sheets as of December 31, 2019 as a current asset, were received in 2020 as an acceleration of all AMT credits in connection with certain provisions of the CARES Act. In addition, we have recognized deferred state tax expense (benefits) of $1.2 million, $(2.7) million and $2.1 million primarily attributable to property and equipment as well as $0.3 million, $0.4 million and zero current state expense attributable to the Texas margin tax for the years ended December 31, 2021, 2020 and 2019, respectively. Our overall effective tax rates were 1.6%, 0.7% and 3.0% for the years ended December 31, 2021, 2020 and 2019, respectively. Deferred Tax Assets and Liabilities As of December 31, 2021, we had federal NOL carryforwards of approximately $746.8 million, a substantial portion of which, if not utilized, expire between 2032 and 2037. NOLs incurred after January 1, 2018 can be carried forward indefinitely. Because of the change in ownership provisions of the Code, use of a portion of our federal NOLs may be limited in future periods. As of December 31, 2021, we carried a valuation allowance against our federal and state deferred tax assets of $205.6 million, which includes an increase of $24.8 million related to the Lonestar Acquisition. We considered both the positive and negative evidence in determining whether it was more likely than not that some portion or all of our deferred tax assets will be realized. The amount of deferred tax assets considered realizable could, however, be adjusted if estimates of future taxable income during the carryforward period are reduced or increased or if objective negative evidence is no longer present and additional weight is given to subjective positive evidence, including projections for growth. The valuation allowance along with $39.3 million of deferred tax liabilities fully offset our deferred tax assets. The net deferred tax liability recognized on our consolidated balance sheets as of December 31, 2021 is attributable to certain state deferred tax liabilities associated with property and equipment and unrealized hedges. The valuation allowance related to all other net deferred tax assets remains in full as of December 31, 2021 and 2020. Following the Juniper Transactions, Ranger Oil is a holding company and all of its operating assets are held within the Partnership. Certain of the federal deferred tax assets and liabilities were reclassified to investment in partnership deferred tax liability. Other Income Tax Matters We had no liability for unrecognized tax benefits as of December 31, 2021 and 2020. There were no interest and penalty charges recognized during the years ended December 31, 2021, 2020 and 2019. Tax years from 2015 forward remain open for examination by the Internal Revenue Service and various state jurisdictions.

Leases

Leases	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Lessee, Operating Leases	Note 11 – Leases We generally have lease arrangements for office facilities and certain office equipment, certain field equipment including compressors, drilling rigs, crude oil storage tank capacity, land easements and similar arrangements for rights-of-way, and certain gas gathering and gas lift assets. Our short-term leases included in the disclosures below are primarily comprised of our contractual arrangements with certain vendors for operated drilling rigs, crude oil storage tank capacity and our field compressors. Our primary variable lease was represented by our field gas gathering and gas lift agreement with a midstream service provider and the lease payments are charged on a volumetric basis at a contractual fixed rate. The following table summarizes the components of our total lease cost for the periods presented: Year Ended December 31, 2021 2020 2019 Operating lease cost $ 891 $ 979 $ 773 Short-term lease cost 24,655 23,721 36,202 Variable lease cost 24,807 21,932 23,762 Less: Amounts charged as drilling costs 1 (21,213) (20,708) (33,354) Total lease cost recognized in the consolidated statement of operations 2 $ 29,140 $ 25,924 $ 27,383 ___________________ 1 Represents the combined gross amounts paid and (i) capitalized as drilling costs for our working interest share and (ii) billed to joint interest partners for their working interest share for short-term leases of operated drilling rigs. 2 Includes $10.8 million, $11.2 million and $12.1 million recognized in GPT, $17.4 million, $13.8 million and $14.5 million recognized in Lease operating expense (“LOE”) and $0.9 million, $1.0 million and $0.8 million recognized in G&A for the years ended December 31, 2021, 2020, and 2019, respectively. The following table summarizes supplemental cash flow information related to leases for the periods presented: Year Ended December 31, 2021 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 981 $ 943 $ 659 ROU assets obtained in exchange for operating lease obligations 1 $ — $ 388 $ 3,325 ___________________ 1 Includes $2.5 million recognized upon adoption of ASC Topic 842, Leases and $0.8 million obtained during the twelve months ended December 31, 2019. The following table summarizes supplemental balance sheet information related to leases as of the dates presented: December 31, Leases Balance Sheet Location 2021 2020 Assets ROU assets – operating leases Other assets $ 1,671 $ 2,432 Liabilities Current operating lease obligations Accounts payable and accrued liabilities $ 914 $ 936 Non-current operating lease obligations Other non-current liabilities 975 1,752 Total operating lease obligations $ 1,889 $ 2,688 The following table presents other information as it relates to operating leases as of the dates presented: December 31, 2021 2020 Weighted-average remaining lease term – operating leases 2.1 years 3.1 years Weighted-average discount rate – operating leases 3.13 % 3.24 % As of December 31, 2021, maturities of our operating lease liabilities consisted of the following: December 31, 2021 2022 $ 930 2023 878 2024 146 2025 — 2026 — Total undiscounted lease payments 1,954 Less: imputed interest (65) Total operating lease obligations $ 1,889

Supplemental Balance Sheet Deta

Supplemental Balance Sheet Detail	12 Months Ended
	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Additional Balance Sheet Detail	Note 12 – Supplemental Balance Sheet Detail The following table summarizes components of selected balance sheet accounts as of the dates presented: December 31, 2021 2020 Prepaid and other current assets: Inventories 1 $ 10,305 $ 4,274 Prepaid expenses 2 10,693 14,771 $ 20,998 $ 19,045 Other assets: Deferred issuance costs of the Credit Facility, net of amortization $ 3,308 $ 2,349 Right-of-use assets – operating leases 1,671 2,432 Other 38 127 $ 5,017 $ 4,908 Accounts payable and accrued liabilities: Trade accounts payable $ 32,452 $ 7,055 Drilling and other lease operating costs 35,045 16,088 Revenue and royalties payable 95,521 26,615 Production, ad valorem and other taxes 7,905 3,094 Derivative settlements to counterparties 6,117 321 Compensation and benefits 13,942 4,222 Interest 15,321 504 Environmental remediation liability 3 2,287 — Current operating lease obligations 914 936 Other 4 4,877 4,254 $ 214,381 $ 63,089 Other non-current liabilities: Asset retirement obligations $ 8,413 $ 5,461 Non-current operating lease obligations 975 1,752 Postretirement benefit plan obligations 970 1,149 $ 10,358 $ 8,362 _______________________ 1 Includes tubular inventory and well materials of $9.5 million and $3.9 million and crude oil volumes in storage of $0.8 million and $0.4 million as of December 31, 2021 and 2020, respectively. 2 The balance as of December 31, 2021 and 2020 includes $9.6 million and $13.6 million, respectively, for the prepayment of drilling and completion services and materials. 3 The balance as of December 31, 2021 represents estimated costs associated with remediation activities for certain wells and tanks acquired as part of the Lonestar Acquisition. 4 The balance as of December 31, 2021 includes liabilities assumed as part of the Lonestar Acquisition of $2.5 million. The balance as of December 31, 2020 includes $3.5 million of accrued costs attributable to Juniper Transaction expenses.
Components of Selected Balance Sheet Accounts	The following table summarizes components of selected balance sheet accounts as of the dates presented: December 31, 2021 2020 Prepaid and other current assets: Inventories 1 $ 10,305 $ 4,274 Prepaid expenses 2 10,693 14,771 $ 20,998 $ 19,045 Other assets: Deferred issuance costs of the Credit Facility, net of amortization $ 3,308 $ 2,349 Right-of-use assets – operating leases 1,671 2,432 Other 38 127 $ 5,017 $ 4,908 Accounts payable and accrued liabilities: Trade accounts payable $ 32,452 $ 7,055 Drilling and other lease operating costs 35,045 16,088 Revenue and royalties payable 95,521 26,615 Production, ad valorem and other taxes 7,905 3,094 Derivative settlements to counterparties 6,117 321 Compensation and benefits 13,942 4,222 Interest 15,321 504 Environmental remediation liability 3 2,287 — Current operating lease obligations 914 936 Other 4 4,877 4,254 $ 214,381 $ 63,089 Other non-current liabilities: Asset retirement obligations $ 8,413 $ 5,461 Non-current operating lease obligations 975 1,752 Postretirement benefit plan obligations 970 1,149 $ 10,358 $ 8,362

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 13 – Fair Value Measurements We apply the authoritative accounting provisions included in GAAP for measuring fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date. We use a hierarchy that prioritizes the inputs we use to measure fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below. Fair value measurements are classified and disclosed in one of the following three categories: • Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Level 1 inputs generally provide the most reliable evidence of fair value. • Level 2: Quoted prices in markets that are not active or inputs, which are observable, either directly or indirectly, for substantially the full term of the asset or liability. • Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Our financial instruments, including cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to their short-term maturities. As of December 31, 2021 and 2020, the carrying values of the borrowings outstanding under our credit facilities approximate fair value as the borrowings bear interest at variables rates tied to current market rates and the applicable margins represent market rates. The fair value of our fixed rate 9.25% Senior Notes due 2026 is estimated based on the published market prices for issuances of similar risk and tenor and is categorized as Level 2 within the fair value hierarchy. As of December 31, 2021, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $619.0 million and $634.6 million, respectively. As of December 31, 2020, the estimated fair value of total debt (before amortization of issuance costs) approximated the carrying value of $514.4 million. Recurring Fair Value Measurements The fair values of our derivative instruments are measured at fair value on a recurring basis on our consolidated balance sheets. The following tables summarize the valuation of those financial assets and (liabilities) as of the dates presented: As of December 31, 2021 Level 1 Level 2 Level 3 Total Financial assets: Commodity derivative assets – current $ — $ 11,478 $ — $ 11,478 Commodity derivative assets – non-current — 2,092 — 2,092 Total financial assets $ — $ 13,570 $ — $ 13,570 Financial liabilities: Interest rate swap liabilities – current $ — $ (1,480) $ — $ (1,480) Commodity derivative liabilities – current — (48,892) — (48,892) Commodity derivative liabilities – non-current — (23,815) — (23,815) Total financial liabilities $ — $ (74,187) $ — $ (74,187) As of December 31, 2020 Level 1 Level 2 Level 3 Total Financial assets: Commodity derivative assets – current $ — $ 75,506 $ — $ 75,506 Commodity derivative assets – non-current — 25,449 — 25,449 Total financial assets $ — $ 100,955 $ — $ 100,955 Financial liabilities: Interest rate swap liabilities – current $ — $ (3,655) $ — $ (3,655) Interest rate swap liabilities – non-current — (1,645) — (1,645) Commodity derivative liabilities – current — (81,451) — (81,451) Commodity derivative liabilities – non-current — (26,789) — (26,789) Total financial liabilities $ — $ (113,540) $ — $ (113,540) We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below: • Commodity derivatives : We determine the fair values of our commodity derivative instruments using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatilities, time value and non-performance risk. For the current market prices, we use third-party quoted forward prices, as applicable, for NYMEX WTI, MEH crude oil and NYMEX HH natural gas and OPIS Mt Belv Ethane natural gas liquids closing prices as of the end of the reporting periods. Each of these is a level 2 input. • Interest rate swaps : We determine the fair values of our interest rate swaps using an income valuation approach valuation technique which discounts future cash flows back to a single present value. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these is a Level 2 input. Non-performance risk is incorporated by utilizing discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is in a liability position. See Note 6 for additional details on our derivative instruments. Non-Recurring Fair Value Measurements In addition to the fair value measurements applied with respect to assets contributed in the Juniper Transactions and acquired with the Lonestar Acquisition, as described in Note 4, the most significant non-recurring fair value measurements utilized in the preparation of our consolidated financial statements are those attributable to the initial determination of AROs associated with the ongoing development of new oil and gas properties and certain share-based compensation awards. The determination of the fair value of AROs is based upon regional market and facility specific information. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these significant fair value inputs are typically not observable, we have categorized the initial estimates as level 3 inputs.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 14 – Commitments and Contingencies The following table sets forth our significant commitments as of December 31, 2021, by category, for the next 5 years and thereafter: Year Gathering and Intermediate Transportation Commitments Other Commitments 2022 $ 13,937 $ 380 2023 13,937 143 2024 13,976 56 2025 13,937 — 2026 7,794 — Thereafter 15,808 — Total $ 79,389 $ 579 Drilling and Completion Commitments As of December 31, 2021, we had contractual commitments on a pad-to-pad basis for two drilling rigs. Gathering and Intermediate Transportation Commitments We have long-term agreements that provide us with field gathering and intermediate pipeline transportation services for a majority of our crude oil and condensate production in Lavaca and Gonzales Counties, Texas. We also have volume capacity support for certain downstream interstate pipeline transportation. The following table provides details on these contractual arrangements as of December 31, 2021: Description of contractual arrangement Expiration Minimum Expiration of Minimum Volume Commitment Field gathering agreement February 2041 8,000 February 2031 Intermediate pipeline transportation services February 2026 8,000 February 2026 Volume capacity support April 2026 8,000 April 2026 Each of these arrangements also contain an obligation to deliver the first 20,000 gross barrels of oil per day produced from Gonzales, Lavaca, Fayette and DeWitt Counties, Texas. For certain of our crude oil volumes gathered under the field gathering agreement, our rate includes an adjustment based on NYMEX WTI prices. As crude oil prices increase, up to a cap of $90 per bbl, the gathering rate escalates pursuant to the field gathering agreement. Under each of the arrangements, credits for deliveries of volumes in excess of the volume commitment may be applied to any deficiency arising in the succeeding 12-month period. During the years ended December 31, 2021, 2020 and 2019, we recorded expense of $36.0 million, $34.5 million and $31.9 million, respectively, for these contractual obligations in connection with these arrangements. Crude Oil Storage As a component of the crude oil gathering agreement referenced above, we have access to approximately 180,000 barrels of dedicated tank capacity for no additional charge at the service provider’s central delivery point facility (“CDP”), in Lavaca County, Texas through February 2041. In addition, we have access for up to a maximum of 340,000 barrels of tank capacity through April 2022 and evergreen month-to-month at several locations in the South Texas region. We have also contracted for access to an additional 70,000 barrels of tank capacity at the CDP on a month-to-month basis, which can be terminated by either party with 45-days’ notice to the counterparty. We have also contracted for crude oil storage capacity for up to 90,000 barrels with a downstream interstate pipeline at a facility in DeWitt County, Texas, on a month-to-month basis which can be terminated by either party with 45-days’ notice to the counterparty. Finally, we have an agreement with a marketing affiliate of the aforementioned downstream interstate pipeline to utilize up to 62,000 barrels of capacity within their system on a firm basis and an additional 120,000 barrels, if available, on a flexible basis. Costs associated with these agreements are in the form of monthly fixed rate short-term leases and are charged as incurred on a monthly basis to GPT in our consolidated statements of operations. Other Agreements We have a long-term dedication of certain specific leases to a crude purchase and throughput terminal agreement into 2032. Under the agreement, we have rights to transfer dedicated oil for delivery to a gulf coast terminal in Point Comfort, Texas or oil may be transferred at alternate locations to third parties and pay the terminal fee. We have agreements that provide us with field gathering, compression and short-haul transportation services for our natural gas production and gas lift for our hydrocarbon production under various terms through 2039. We also have agreements that provide us with services to process our wet gas production into NGL products and dry, or residue, gas. Several agreements covering the majority of our wet gas production extend beyond three years, including one significant agreement that extends into 2029. Legal We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. As of December 31, 2021, we had an estimated reserve in the amount of $0.1 million for certain claims made against us regarding previously divested operations included in Accounts payable and accrued liabilities on our consolidated balance sheets. Environmental Compliance Extensive federal, state and local laws govern oil and gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as plugging of abandoned wells. As of December 31, 2021, we had AROs of $8.4 million and environmental remediation liabilities assumed in the Lonestar Acquisition of $2.3 million attributable to these activities. The regulatory burden on the oil and gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material impact on our financial condition or results of operations. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws, including any significant limitation on the use of hydraulic fracturing, have the potential to adversely affect our operations. Other Commitments We have entered into certain contractual arrangements for other products and services. We have purchase commitments for certain materials as well as minimum commitments under information technology licensing and service agreements, among others.

Shareholders' Equity

Shareholders' Equity	12 Months Ended
	Dec. 31, 2021
Equity [Abstract]
Shareholders' Equity	Note 15 – Shareholders’ Equity Capital Stock Prior to the Lonestar Acquisition, the Company’s authorized capital stock consisted of 115,000,000 shares including (i) 110,000,000 shares of common stock, par value $0.01 per share and (ii) 5,000,000 shares of Series A Preferred Stock, par value $0.01 per share. On October 6, 2021, in connection with the consummation of the Lonestar Acquisition, the Company effected a recapitalization (the “Recapitalization”), pursuant to which (i) the Company’s common stock was renamed and reclassified as Class A Common Stock, (ii) the authorized number of shares of capital stock of the Company was increased to 145,000,000 shares, (iii) 30,000,000 shares of Class B Common Stock, par value of $0.01 per share, a new class of capital stock of the Company, was authorized, (iv) all 225,489.98 outstanding shares of the Series A Preferred Stock were exchanged for 22,548,998 newly issued shares of Class B Common Stock, and (v) the designation of the Series A Preferred Stock was cancelled. We have not paid any cash dividends on our common stock. In addition, our Credit Facility and the Indenture have restrictive covenants that limit our ability to pay dividends. Paid-in Capital Paid-in capital represents the value of consideration we received in excess of par value for the original issuance of our common stock net of costs directly attributable to the issuance transactions. In addition, paid-in capital includes amounts attributable to the amortized cost of share-based awards that have been granted to our employees and directors, net of any adjustments with the ultimate vesting of such awards. Accumulated Other Comprehensive Income (Loss) Accumulated other comprehensive income and losses are entirely attributable to our pension and postretirement health care benefit obligations. For further details on our pension and postretirement health care plans, see Note 16.

Share-Based Compensation and Ot

Share-Based Compensation and Other Benefit Plans	12 Months Ended
	Dec. 31, 2021
Share-based Payment Arrangement [Abstract]
Share-based Compensation and Other Benefit Plans	Note 16 – Share-Based Compensation and Other Benefit Plans We reserved 4,424,600 shares of Class A Common Stock for issuance under the Ranger Oil Management Incentive Plan (the “Incentive Plan”) for share-based compensation awards. A total of 762,259 time-vested restricted stock units (“RSUs”) and 484,197 performance-based restricted stock units (“PRSUs”) have been granted to employees and directors through December 31, 2021. The Merger Agreement provided the terms in which Lonestar share-based awards held by Lonestar employees were replaced with share-based awards of the Company (“replacement awards”) on the acquisition date. For accounting purposes, the fair value of the replacement awards must be allocated between each employee’s pre-combination and post-combination services. Amounts allocated to pre-combination services have been included as consideration transferred as part of the Lonestar Acquisition. See Note 4 for a summary of consideration transferred. Compensation costs of $10.4 million allocated to post-combination services were recorded as stock-based compensation expense from the immediate vesting of these awards pursuant to the terms of the Merger Agreement. We recognized $15.6 million (including $10.4 million and $1.9 million as a result of the change-in-control events associated with the Lonestar Acquisition and the Juniper Transactions, respectively), $3.3 million and $4.1 million of share-based compensation expense for the years ended December 31, 2021, 2020 and 2019, respectively, and $0.5 million, $0.1 million and $0.1 million of related income tax benefits for the years ended December 31, 2021, 2020 and 2019, respectively. All of our share-based compensation awards are classified as equity instruments because they result in the issuance of common stock on the date of grant, upon exercise or are otherwise payable in common stock upon vesting, as applicable. The compensation cost attributable to these awards has been measured at the grant date and recognized over the applicable vesting periods as a non-cash expense. Time-Vested Restricted Stock Units The RSUs entitle the grantee to receive a share of common stock upon the achievement of the applicable service period vesting requirement. The grant date fair value of our time-vested RSU awards are recognized on a straight-line basis over the applicable vesting period, which is generally over a three The following table summarizes activity for our most recent fiscal year with respect to awarded RSUs: Restricted Stock Weighted-Average Balance at beginning of year 319,280 $ 13.56 Granted 120,262 $ 14.12 Vested (174,972) $ 20.81 Forfeited (34,053) $ 10.65 Balance at end of year 230,517 $ 9.20 As of December 31, 2021, we had $1.5 million of unrecognized compensation cost attributable to RSUs. We expect that cost to be recognized over a weighted-average period of 1.85 years. The total grant date fair values of RSUs that vested in 2021, 2020 and 2019 were $3.6 million, $2.8 million and $3.0 million, respectively. Performance Restricted Stock Units The PRSUs entitle the grantee to receive a share of common stock upon the achievement of both service and market conditions. The table below presents information pertaining to PRSUs granted in the following periods: 2021 2020 2019 PRSUs granted 1 225,206 145,399 15,066 Monte Carlo grant date fair value 2 $17.74 to $33.31 $2.40 to $16.02 $ 34.02 Average grant date fair value 3 $13.63 not applicable not applicable ___________________ 1 The 2020 PRSU grants include one executive officers’ inducement award originally granted in August 2020 that was amended in April 2021 to conform vesting conditions to other PRSU awards granted in 2021. 2 Represents the Monte Carlo grant date fair value of 2021 and 2020 PRSU grants based on the Company’s TSR performance (as defined below). 3 Represents the average grant date fair value of 2021 PRSU grants based on the Company’s ROCE performance (as defined below). Compensation expense for PRSUs with a market condition is being charged to expense on a straight-line basis for the 2021 grants and graded-vesting for the 2020 and 2019 grants, over a range of less than one The 2021 PRSU grants are based 50% on the Company’s return on average capital employed (“ROCE”) relative to a defined peer group and 50% based on the Company’s absolute total shareholder return and total shareholder return (“TSR”) relative to a defined peer group over the three year performance period. The 2021 PRSUs cliff vest from 0% to 200% of the original grant at the end of a three-year performance period based on satisfaction of the respective underlying conditions. Vesting of PRSUs granted in 2020 and 2019 range from 0% to 200% of the original grant based on TSR relative to a defined peer group over the three 2021 1 2020 1 2019 Expected volatility 131.74% to 134.74% 101.32% to 117.71% 49.90 % Dividend yield 0.0 % 0.0 % 0.0 % Risk-free interest rate 0.22% to 0.29% 0.18% to 0.51% 1.66 % Performance period 2021-2023 2020-2022 2020-2022 ___________________ 1 One executive officer’s inducement award originally granted in August 2020 was amended in April 2021 to conform vesting conditions to other PRSU awards granted in 2021. The Monte Carlo assumptions for both years are included above. The following table summarizes activity for our most recent fiscal year with respect to PRSUs: Performance Restricted Stock Weighted-Average Grant Date Balance at beginning of year 173,532 $ 13.68 Granted 225,206 $ 22.44 Vested (9,816) $ 26.60 Forfeited (43,853) $ 14.90 Balance at end of year 345,069 $ 16.20 As of December 31, 2021, we had $5.0 million of unrecognized compensation cost attributable to PRSUs. We expect that cost to be recognized over a weighted-average period of 1.96 years. Executive Transition and Retirement In August 2020, we appointed Darrin Henke our new president and chief executive officer, or CEO, and director following the retirement of John Brooks. We incurred incremental G&A costs of approximately $1.2 million, in connection with Mr. Henke’s appointment and Mr. Brooks’ separation. In addition to those incremental costs, we recognized $0.7 million during the year ended December 31, 2020 for the accelerated vesting of certain share-based compensation awards of Mr. Brooks in connection with his retirement. In December 2019, Steven A. Hartman separated from the Company. In accordance with his separation and transition agreement (“Hartman Separation Agreement”), we recorded a charge of $0.5 million for severance and other cash benefits that were paid in the first quarter of 2020. The Hartman Separation Agreement also provided for the accelerated vesting of certain share-based compensation awards for which we recognized accelerated expense of $0.2 million during the year ended December 31, 2019. The costs associated with the Hartman Separation Agreement, including the share-based compensation charges, were included as a component of General and administrative expenses in our consolidated statements of operations for the year ended December 31, 2019. Defined Contribution Plan We maintain the Penn Virginia Corporation and Affiliated Companies Employees 401(k) Plan (the “401(k) Plan”), a defined contribution plan, which covers substantially all of our employees. We provide matching contributions on our employees’ elective deferral contributions up to 6% of compensation up to the maximum statutory limits. The 401(k) Plan also provides for discretionary employer contributions. The expense recognized with respect to the 401(k) Plan was $1.0 million, $0.9 million, $0.9 million for the years ended December 31, 2021, 2020 and 2019, respectively, and is included as a component of General and administrative expenses in our consolidated statements of operations. Amounts representing accrued obligations to the 401(k) Plan of $0.3 million and $0.2 million are included within Accounts payable and accrued expenses on our consolidated balance sheets as of December 31, 2021 and 2020, respectively. Defined Benefit Pension and Postretirement Health Care Plans We maintain unqualified legacy defined benefit pension and defined benefit postretirement health care plans which cover a limited population of former employees that retired prior to January 1, 2000. The combined expense recognized with respect to these plans was less than $0.1 million for each year ended December 31, 2021, 2020 and 2019, and is included as a component of Other, net in our consolidated statements of operations. The combined unfunded benefit obligations under these plans were $1.1 million and $1.3 million as of December 31, 2021 and 2020, respectively, and are included within the Accounts payable and accrued liabilities (current portion) and Other liabilities (non-current portion) on our consolidated balance sheets.

Earnings per Share

Earnings per Share	12 Months Ended
	Dec. 31, 2021
Earnings Per Share [Abstract]
Earnings per Share	Note 17 – Earnings Per Share Basic net earnings (loss) per share is calculated by dividing the net income (loss) available to common shareholders, excluding net income or loss attributable to Noncontrolling interest, as applicable to the year ended December 31, 2021 (see Note 4), by the weighted average common shares outstanding for the period. In computing diluted earnings (loss) per share, basic net earnings (loss) per share is adjusted based on the assumption that dilutive RSUs and PRSUs have vested and outstanding Common Units held by Juniper as a Noncontrolling interest in the Partnership are exchanged for common shares, as applicable to the year ended December 31, 2021 (see Note 4. Accordingly, our reported net income (loss) attributable to common shareholders is adjusted to reflect the reallocation of the net income (loss) attributable to the Noncontrolling interest assuming exchange of the Common Units held by Noncontrolling interest. The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings per share for the periods presented: Year Ended December 31, 2021 2020 2019 Net income (loss) $ 98,918 $ (310,557) $ 70,589 Net income attributable to Noncontrolling interest (58,689) — — Net income (loss) attributable to common shareholders (basic) 40,229 (310,557) 70,589 Reallocation of Noncontrolling interest net income 58,689 — — Net income (loss) attributable to common shareholders (diluted) $ 98,918 $ (310,557) $ 70,589 Weighted-average shares – basic 16,695 15,176 15,110 Effect of dilutive securities: Common Units exchangeable for common shares — — — RSUs and PRSUs 470 — 16 Weighted-average shares – diluted 1 17,165 15,176 15,126 _____________________________________________ 1 For the year ended December 31, 2021, approximately 22.5 million potentially dilutive Common Units, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per share. For the year ended December 31, 2020, approximately 0.1 million potentially dilutive securities, represented by RSUs and PRSUs, respectively, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per share. Change in Ownership of Consolidated Subsidiaries The following table summarizes changes in the ownership interest in consolidated subsidiaries during the period: Year Ended December 31, 2021 2020 2019 Net income (loss) attributable to common shareholders $ 40,229 $ (310,557) $ 70,589 Change in ownership of consolidated subsidiaries 1 (57,604) N/A N/A Change from net income (loss) attributable to common shareholders and transfers to Noncontrolling interest $ (17,375) $ (310,557) $ 70,589 _____________________________________________ 1 The year ended December 31, 2021 includes an adjustment to Noncontrolling interest for the Lonestar Acquisition of $57.6 million and to Additional paid-in-capital of $57.6 million to reflect the change in ownership structure that was effective at October 5, 2021 relating to the noncontrolling interest arising from the Juniper Transactions on January 15, 2021. The adjustment had no impact on earnings. See Note 4 for further details.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Principles of Consolidation	Principles of Consolidation Our consolidated financial statements include the accounts of Ranger Oil and all of its subsidiaries. Intercompany balances and transactions have been eliminated.
Use of Estimates	Use of Estimates Preparation of our consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Such estimates include certain asset and liability valuations as further described in these notes. Actual results could differ from those estimates.
Cash and Cash Equivalents	Cash and Cash EquivalentsWe consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Some of our account balances exceed the FDIC coverage limits. We believe our cash and cash equivalents are not subject to any material interest rate risk, equity price risk, credit risk or other market risk.
Derivative Instruments	Derivative Instruments We utilize derivative instruments, which are placed with financial institutions that we believe are of acceptable credit risk, to mitigate our financial exposure to commodity price and interest rate volatility. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by our board of directors.
Oil and Gas Properties	Property and Equipment Oil and Gas Properties We apply the full cost method of accounting for our oil and gas properties. Under this method, all productive and nonproductive costs incurred in the exploration, development and acquisition of oil and gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical, or seismic, drilling, completion and equipment costs. Internal costs incurred that are directly attributable to exploration, development and acquisition activities undertaken by us for our own account, and which are not attributable to production, general corporate overhead or similar activities are also capitalized. Future development costs are estimated on a property-by-property basis based on current economic conditions and are amortized as a component of depreciation, depletion and amortization (“DD&A”). Unproved properties not being amortized include unevaluated leasehold costs and associated capitalized interest. These costs are reviewed quarterly to determine whether or not and to what extent proved reserves have been assigned to a property or if an impairment has occurred due to lease expirations, general economic conditions and other factors, in which case the related costs along with associated capitalized interest are reclassified to the proved oil and gas properties subject to DD&A. At the end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated after-tax discounted future net revenues from proved properties adjusted for costs excluded from amortization (the “Ceiling Test”). The estimated after-tax discounted future net revenues are determined using the prior 12-month’s average commodity prices based on closing prices on the first day of each month, adjusted for differentials, discounted at 10%. The calculation of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are significant uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production, timing and plan of development. DD&A of our oil and gas properties is computed using the units-of-production method. We apply this method by multiplying the unamortized cost of our proved oil and gas properties, net of estimated salvage plus future development costs, by a rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves at the beginning of the period. Other Property and Equipment Other property and equipment consists primarily of gathering systems and related support equipment, vehicles, leasehold improvements, information technology hardware and capitalized software costs. Other property and equipment are carried at cost and include expenditures for additions and improvements which increase the productive lives of existing assets. Renewals and betterments, which extend the useful life of the properties, are also capitalized. Maintenance and repair costs are charged to expense as incurred. We compute depreciation and amortization of property and equipment using the straight-line method over the estimated useful life of each asset as follows: Gathering systems – 15 to 20 years and Other property and equipment – three
Other Property and Equipment	Other property and equipment consists primarily of gathering systems and related support equipment, vehicles, leasehold improvements, information technology hardware and capitalized software costs. Other property and equipment are carried at cost and include expenditures for additions and improvements which increase the productive lives of existing assets. Renewals and betterments, which extend the useful life of the properties, are also capitalized. Maintenance and repair costs are charged to expense as incurred. We compute depreciation and amortization of property and equipment using the straight-line method over the estimated useful life of each asset as follows: Gathering systems – 15 to 20 years and Other property and equipment – three
Leases	Leases We determine if a contractual arrangement is a lease at inception and whether it is classified as operating or financing based on whether that contract conveys the right to control the use of an identified asset in exchange for consideration for a period of time. Leases are included in Other assets, Accounts payable and accrued liabilities and Other liabilities on our consolidated balance sheets and are identified as Right-of-use (“ROU”) assets, Current lease obligations and Noncurrent lease obligations, respectively, in Note 11 and Note 12. ROU assets represent our right to use an underlying asset for the lease term and lease obligations represent our obligation to make lease payments arising from the underlying contractual arrangement. Operating lease ROU assets and obligations are recognized at the commencement date based on the present value of lease payments over the lease term. The operating lease ROU assets include any lease payments made in advance and excludes lease incentives. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise such options. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Most of our leasing arrangements do not identify or otherwise provide for an implicit interest rate. Accordingly, we utilize a secured incremental borrowing rate based on information available at the commencement date in the determination of the present value of the lease payments. As most of our lease arrangements have terms ranging from two We have lease arrangements that include lease and certain non-lease components, including amounts for related taxes, insurance, common area maintenance and similar terms. We apply a practical expedient provided in Accounting Standards Codification (“ASC”) Topic 842, Leases , to not separate the lease and non-lease components. Accordingly, the ROU assets and lease obligations for such leases will include the present value of the estimated payments for the non-lease components over the lease term. Certain of our lease arrangements with contractual terms of 12 months or less are classified as short-term leases. Accordingly, we do not include the underlying ROU assets and lease obligations on our consolidated balance sheets. The associated costs are aggregated with all of our other lease arrangements and are disclosed in the tables in Note 11. Certain of our lease arrangements result in variable lease payments which, in accordance with ASC Topic 842, do not give rise to lease obligations. Rather, the basis and terms and conditions upon which such variable lease payments are determined are disclosed in Note 11.
Asset Retirement Obligations	Asset Retirement Obligations We recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. Associated asset retirement costs are capitalized as part of the carrying cost of the asset. Our AROs relate to the plugging and abandonment of oil and gas wells and the associated asset is recorded as a component of oil and gas properties. After recording these amounts, the ARO is accreted to its future estimated value, and the additional capitalized costs are depreciated over the productive life of the assets. Both the accretion of the ARO and the depreciation of the related long-lived assets are included in the DD&A expense caption in our consolidated statements of operations.
Income Taxes	Income Taxes We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company’s financial statements or tax returns. Using this method, deferred tax assets and liabilities are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates. In assessing our deferred tax assets, we consider whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is assessed at each reporting period and is dependent upon the generation of future taxable income and our ability to utilize operating loss carryforwards during the periods in which the temporary differences become deductible. We also consider the scheduled reversal of deferred tax liabilities and available tax planning strategies. We recognize interest attributable to income taxes, to the extent it may be incurred, as a component of interest expense and penalties as a component of income tax expense. We are subject to ongoing tax examinations in numerous domestic jurisdictions. Accordingly, we may record incremental tax expense based upon the more-likely-than-not outcomes of uncertain tax positions. In addition, when applicable, we adjust the previously recorded tax expense to reflect examination results when the position is effectively settled. Our ongoing assessments of the more-likely-than-not outcomes of the examinations and related tax positions require judgment and can increase or decrease our effective tax rate, as well as impact our operating results. The specific timing of when the resolution of each tax position will be reached is uncertain.
Noncontrolling Interest	Noncontrolling interest Noncontrolling interest in the accompanying consolidated financial statements represents the ownership interest held by Juniper and is presented as a component of equity. When the Company’s relative ownership interest in the Partnership change, adjustments to noncontrolling interest and additional paid-in-capital, tax effected, will occur. Because these changes in the ownership interest in the Partnership do not result in a change of control, the transactions are accounted for as equity transactions under ASC Topic 810, Consolidation
Revenue Recognition and Associated Costs	Revenue Recognition and Associated Costs The Company recognizes revenue in accordance with ASC Topic 606, Revenue from Contracts with Customers which includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. We record revenue in the month that our oil and gas production is delivered to our customers. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. See Note 5 for further discussion. Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. We apply a practical expedient which provides for an exemption 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. Under our commodity product sales contracts, we bill our customers and recognize revenue when our performance obligations have been satisfied. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do not create material contract assets or liabilities. Crude oil . We sell our crude oil production to our customers at either the wellhead or a contractually agreed-upon delivery point, including certain regional central delivery point terminals or pipeline inter-connections. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality, location differentials and, if applicable, deductions for intermediate transportation. Costs incurred by us for gathering and transporting the products to an agreed-upon delivery point are recognized as a component of gathering, processing and transportation expense (“GPT”). NGLs . We have natural gas processing contracts in place with certain midstream processing vendors. We deliver “wet” natural gas to our midstream processing vendors at the inlet of their processing facilities through gathering lines, certain of which we own and others which are owned by gathering service providers. Subsequent to processing, NGLs are delivered or transported to a third-party customer. Depending upon the nature of the contractual arrangements with the midstream processing vendors regarding the marketing of the NGL products, we recognize revenue for NGL products on either a gross or net basis. For those contracts where we have determined that we are the principal, and the ultimate third party is our customer, we recognize revenue on a gross basis, with associated processing costs presented as GPT expenses. For those contracts where we have determined that we are the agent and the midstream processing vendor is our customer, we recognize NGL product revenues on a net basis with processing costs presented as a reduction of revenue. Natural gas . Subsequent to the processing of “wet” natural gas and the separation of NGL products, the “dry” or residue gas is purchased by the processor or delivered to us at the tailgate of the midstream processing vendors’ facilities and sold to a third-party customer. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality and location differentials, as applicable. Costs incurred by us for gathering and transportation from the wellhead through the processing facilities are recognized as a component of GPT expenses. Marketing and water disposal services . We provide marketing and water disposal services to certain of our joint venture partners and other third parties with respect to oil and gas production for which we are the operator. Pricing for such services represents a fixed rate fee based, in the case of marketing services, on the sales price of the underlying oil and gas products and, in the case of water services, on the quantity of water volume processed. Marketing revenue is recognized simultaneously with the sale of our commodity production to our customers while water service revenue is recognized in the month that the service is rendered. Direct costs associated with our marketing efforts are included in G&A expenses and direct costs associated with our water service efforts are netted against the underlying revenue.
Credit Losses	Credit Losses We monitor and assess our portfolio of accounts receivable, including those from our customers, our joint interest partners and others, when applicable, for credit losses on a monthly basis as we originate the underlying financial assets. Our review process and related internal controls take into appropriate consideration (i) past events and historical experience with the identified portfolio segments, (ii) current economic and related conditions within the broad energy industry as well as those factors with broader applicability and (iii) reasonable supportable forecasts consistent with other estimates that are inherent in our financial statements. In order to facilitate our processes for the review and assessment of credit losses, we have identified the following portfolio segments: (i) customers for our commodity production and (ii) joint interest partners which are further stratified into the following sub-segments: (a) mutual operators which includes joint interest partners with whom we are a non-operating joint interest partner in properties for which they are the operator, (b) large partners consisting of those legal entities that maintain a working interest of at least 10% in properties for which we are the operator and (c) all others which includes legal entities that maintain working interests of less than 10% in properties for which we are the operator as well as legal entities with whom we no longer have an active joint interest relationship, but continue to have transactions, including joint venture audit settlements, that from time-to-time give rise to the origination of new accounts receivable.
Share-Based Compensation	Share-Based Compensation Our stock compensation plans permit the grant of incentive and nonqualified stock options, common stock, deferred common stock units, restricted stock and restricted stock units to our employees and directors. We measure the cost of employee services received in exchange for an award of equity-classified instruments based on the grant-date fair value of the award. Compensation cost associated with equity-classified awards are generally amortized on a straight-line basis over the applicable vesting period except for those that are based on performance which are amortized on a graded basis over the term of the applicable performance periods. Compensation cost associated with liability-classified awards is measured at the end of each reporting period and recognized based on the period of time that has elapsed during the applicable performance period. We recognize forfeitures as they occur. We recognize share-based compensation expense related to our share-based compensation plans as a component of General and administrative expenses (“G&A”) in our consolidated statements of operations.
Recent Accounting Pronouncements	Recent Accounting Pronouncements We consider the applicability and impact of all Accounting Standard Updates (“ASUs”). ASUs not listed below were assessed and determined to be not applicable. Recently Issued Accounting Pronouncements Not Yet Adopted In October 2021, the Financial Accounting Standards Board issued ASU 2021-08, Business Combinations (Topic 805): (“ASU 2021-08”): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers. ASU 2021-08 amends Topic 805 to require the acquirer in a business combination to record contract assets and contract liabilities in accordance with Revenue from Contracts with Customers (Topic 606) at acquisition as as if it had originated the contract, rather than at fair value. This update is effective for public companies beginning after December 15, 2022, with early adoption permitted. Adoption should be applied prospectively to business combinations occurring on or after the effective date of the amendments unless early adoption occurs during an interim period in which other application rules apply. We do not expect the adoption of this update to have a material impact to our financial statements.
Fair Value of Measurements	We apply the authoritative accounting provisions included in GAAP for measuring fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date. We use a hierarchy that prioritizes the inputs we use to measure fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below. Fair value measurements are classified and disclosed in one of the following three categories: • Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Level 1 inputs generally provide the most reliable evidence of fair value. • Level 2: Quoted prices in markets that are not active or inputs, which are observable, either directly or indirectly, for substantially the full term of the asset or liability. • Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below: • Commodity derivatives : We determine the fair values of our commodity derivative instruments using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatilities, time value and non-performance risk. For the current market prices, we use third-party quoted forward prices, as applicable, for NYMEX WTI, MEH crude oil and NYMEX HH natural gas and OPIS Mt Belv Ethane natural gas liquids closing prices as of the end of the reporting periods. Each of these is a level 2 input. • Interest rate swaps : We determine the fair values of our interest rate swaps using an income valuation approach valuation technique which discounts future cash flows back to a single present value. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these is a Level 2 input. Non-performance risk is incorporated by utilizing discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is in a liability position. See Note 6 for additional details on our derivative instruments.

Transactions (Tables)

Transactions (Tables)	12 Months Ended
	Dec. 31, 2021
Transactions [Abstract]
Purchase Price Allocation	The following table sets forth the Company’s preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date. Preliminary Purchase Price Allocation Consideration: Fair value of the Company’s common stock issued 1 $ 173,576 Less: Replacement awards attributable to post-combination compensation cost 2 (10,394) Total consideration transferred $ 163,182 Assets: Other current assets $ 50,044 Proved oil and gas properties 476,743 ARO asset 1,239 Corporate office building and related assets 3 11,400 Other property and equipment 2,582 Other non-current assets 37 Total assets acquired $ 542,045 Liabilities: Current portion of long-term debt $ 24,187 Other current liabilities 66,150 Derivative liabilities 4 49,554 Asset retirement obligations 2,494 Long-term debt 236,478 Total liabilities assumed $ 378,863 Net Assets Acquired $ 163,182 __________________________________________________________________________________ 1 Includes the fair value of the replacement equity awards to the extent services were provided by employees of Lonestar prior to closing of $4.5 million. See Note 16 for additional information about the replacement equity awards. 2 Represents the fair value of the replacement equity awards considered post-combination services. See Note 16 for further details. 3 As of December 31, 2021, these assets met the held for sale criteria and were classified as Assets held for sale on the respective consolidated balance sheet. 4 Immediately following the Lonestar Acquisition, we paid approximately $50 million to restructure certain of Lonestar’s derivatives which were novated or terminated. We reset the majority of the swaps to reflect then current market pricing.
Pro Forma Information	The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Lonestar Acquisition taken place on January 1, 2020 and is not intended to be a projection of future results. December 31, 2021 2020 Total revenues $ 729,026 $ 389,495 Net income (loss) attributable to common shareholders $ 74,355 $ (321,951)
Expenses Related to Acquisition	The following table summarizes expenses related to the Lonestar Acquisition incurred for the year ended December 31, 2021: Year Ended Bank, legal and consulting fees $ 9,856 Employee severance and related costs 7,563 Replacement awards stock-based compensation costs 10,394 Integration and rebranding costs 1,746 Total acquisition-related expenses $ 29,559
Reconciliation of Initial Investment and CV of NCI	The following table reconciles the initial investment by Juniper and the carrying value of their Noncontrolling interest as of the Juniper Closing Date (after post-closing adjustments): Cash contribution $ 150,000 Issue costs paid for Noncontrolling interest securities (3,758) Transaction costs paid on behalf of Noncontrolling interest (5,543) Fair value of Rocky Creek oil and gas properties contributed 38,561 Revenues received attributable to contributed properties 1,160 Suspense revenues attributable to the contributed properties (146) Asset retirement obligations of the contributed properties (14) Fair value of capital contributions 180,260 Income tax adjustment attributable to the Juniper Transactions (708) Total shareholders’ equity prior to the Juniper Closing Date 205,558 $ 385,110 Juniper voting power through Series A Preferred Stock 59.6 % Noncontrolling interest as of the Juniper Closing Date $ 229,620

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2021
Receivables [Abstract]
Summary of Accounts Receivable	The following table summarizes our accounts receivable by type as of the dates presented: December 31, 2021 2020 Customers $ 96,195 $ 39,672 Joint interest partners 21,755 3,079 Derivative settlements from counterparties 1,037 3,287 Other 18 8 Total 119,005 46,046 Less: Allowance for credit losses (411) (197) Accounts receivable, net of allowance for credit losses $ 118,594 $ 45,849

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Derivative Positions	The following table sets forth our commodity derivative contracts as of December 31, 2021: Commodity Derivatives 1Q2022 2Q2022 3Q2022 4Q2022 1Q2023 2Q2023 3Q2023 4Q2023 1Q2024 2Q2024 NYMEX WTI Crude Swaps Average Volume Per Day (bbl) 3,250 3,000 3,000 3,000 2,500 2,400 2,807 2,657 462 462 Weighted Average Swap Price ($/bbl) $ 75.16 $ 74.12 $ 73.01 $ 69.20 $ 54.40 $ 54.26 $ 54.92 $ 54.93 $ 58.75 $ 58.75 NYMEX WTI Crude Collars Average Volume Per Day (bbl) 17,083 14,423 7,745 6,114 2,917 2,885 Weighted Average Purchased Put Price ($/bbl) $ 56.10 $ 54.29 $ 47.37 $ 45.33 $ 40.00 $ 40.00 Weighted Average Sold Call Price ($/bbl) $ 70.49 $ 72.84 $ 64.60 $ 60.87 $ 50.00 $ 50.00 NYMEX WTI Purchased Puts Average Volume Per Day (bbl) 9,444 Weighted Average Purchased Put Price ($/bbl) $ 65.74 NYMEX WTI Crude CMA Roll Basis Swaps Average Volume Per Day (bbl) 13,333 13,187 6,522 6,522 Weighted Average Swap Price ($/bbl) $ 0.880 $ 0.880 $ 1.135 $ 1.135 NYMEX HH Swaps Average Volume Per Day (MMBtu) 17,500 12,500 12,500 12,500 10,000 7,500 Weighted Average Swap Price ($/MMBtu) $ 4.349 $ 3.727 $ 3.745 $ 3.793 $ 3.620 $ 3.690 NYMEX HH Collars Average Volume Per Day (MMBtu) 3,333 13,187 13,043 13,043 11,538 11,413 11,413 11,538 11,538 Weighted Average Purchased Put Price ($/MMBtu) $ 4.150 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.328 Weighted Average Sold Call Price ($/MMBtu) $ 5.750 $ 3.220 $ 3.220 $ 3.220 $ 2.682 $ 2.682 $ 2.682 $ 3.650 $ 3.000 OPIS Mt Belv Ethane Swaps Average Volume per Day (gal) 28,022 27,717 27,717 98,901 34,239 34,239 34,615 Weighted Average Fixed Price ($/gal) $ 0.2500 $ 0.2500 $ 0.2500 $ 0.2288 $ 0.2275 $ 0.2275 $ 0.2275
Impact of Derivative Activities on Condensed Consolidated Statements of Income	The impact of our derivatives activities on income is included within Derivatives on our consolidated statements of operations. Derivative contracts that have expired at the end of a period, but for which cash had not been received or paid as of the balance sheet date, have been recognized as components of Accounts receivable (see Note 5) and Accounts payable and accrued liabilities (see Note 12) on the consolidated balance sheets. The effects of derivative gains and (losses) and cash settlements are reported as adjustments to reconcile net income (loss) to net cash provided by operating activities. These items are recorded within the Derivative contracts section of our consolidated statements of cash flows under Net (gains) losses and Cash settlements and premiums received (paid), net. The following table summarizes the effects of our derivative activities for the periods presented: Year Ended December 31, 2021 2020 2019 Interest Rate Swap losses recognized in the consolidated statements of operations $ (2) $ (7,510) $ — Commodity gains (losses) recognized in the consolidated statements of operations (136,997) 95,932 (68,131) $ (136,999) $ 88,422 $ (68,131) Interest rate cash settlements recognized in the consolidated statements of cash flows $ (3,822) $ (2,210) $ — Commodity cash settlements and premiums received (paid) recognized in the consolidated statements of cash flows (77,099) 80,297 (4,136) Commodity cash settlements paid for acquired derivatives recognized in the consolidated statements of cash flows (49,554) — — $ (130,475) $ 78,087 $ (4,136)
Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets	The following table summarizes the fair value of our derivative instruments, which we elect to present on gross basis, as well as the locations of these instruments on our consolidated balance sheets as of the dates presented: Fair Values December 31, 2021 December 31, 2020 Type Balance Sheet Location Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Interest rate contracts Derivative assets/liabilities – current $ — $ 1,480 $ — $ 3,655 Commodity contracts Derivative assets/liabilities – current 11,478 48,892 75,506 81,451 Interest rate contracts Derivative assets/liabilities – non-current — — — 1,645 Commodity contracts Derivative assets/liabilities – non-current 2,092 23,815 25,449 26,789 $ 13,570 $ 74,187 $ 100,955 $ 113,540

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Summary of Property and Equipment	The following table summarizes our property and equipment as of the dates presented: December 31, 2021 2020 Oil and gas properties: Proved $ 2,327,686 $ 1,545,910 Unproved 57,900 49,935 Total oil and gas properties 2,385,586 1,595,845 Other property and equipment 1 31,055 27,746 Total properties and equipment 2,416,641 1,623,591 Accumulated depreciation, depletion, amortization and impairments (1,033,293) (900,042) Total property and equipment, net $ 1,383,348 $ 723,549 _______________________ 1 Excludes the corporate office building and related assets acquired in connection with the Lonestar Acquisition that were classified as Assets held for sale on the consolidated balance sheets as of December 31, 2021.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
Reconciliation of Asset Retirement Obligations which are Included in Other Liabilities	Note 8 – Asset Retirement Obligations The following table reconciles our AROs as of the dates presented, which are included within Other liabilities on our consolidated balance sheets: Year Ended December 31, 2021 2020 Balance at beginning of period $ 5,461 $ 4,934 Changes in estimates — 33 Liabilities incurred 226 121 Liabilities settled (228) — Acquisitions of properties 2,508 16 Accretion expense 446 357 Balance at end of period $ 8,413 $ 5,461

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Carrying Amount of Components of Long-term Debt	Note 9 – Long-Term Debt The following table summarizes our long-term debt as of the dates presented: December 31, 2021 December 31, 2020 Credit Facility $ 208,000 $ 314,400 Second Lien Term Loan — 200,000 9.25% Senior Notes due 2026 400,000 — Mortgage debt 1 8,438 — Other 2 2,516 — Total 618,954 514,400 Less: Unamortized discount 3 (3,720) (1,604) Less: Unamortized deferred issuance costs 3, 4 (9,853) (3,299) Total, net $ 605,381 $ 509,497 Less: Current portion (4,129) — Long-term debt, net $ 601,252 $ 509,497 _______________________ 1 The mortgage debt relates to the corporate office building and related assets acquired in connection with the Lonestar Acquisition for which assets are held as collateral for such debt. As of December 31, 2021, these assets met the held for sale criteria and were classified as Assets held for sale on the consolidated balance sheets. 2 Other includes approximately $2.2 million related to a PPP loan assumed in the Lonestar Acquisition which was fully forgiven subsequent to December 31, 2021. 3 Prior to the repayment of the Second Lien Term Loan as discussed below, discount and issuance costs of the Second Lien Term Loan were amortized over the term of the underlying loan using the effective-interest method. The discount and issuance costs of the 9.25% Senior Notes due 2026 are being amortized over its respective term using the effective-interest method. 4 Excludes issuance costs associated with the Credit Facility, which represent costs attributable to the access to credit over its contractual term, that have been presented as a component of Other assets (see Note 12) and are being amortized over the term of the Credit Facility using the straight-line method.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Summary of Provision for Income Taxes from Continuing Operations	The following table summarizes our provision for income taxes for the periods presented: Year Ended December 31, 2021 2020 2019 Current income tax expense (benefit) Federal $ — $ (1,236) $ (1,236) State 311 357 — Total current income tax expense (benefit) 311 (879) (1,236) Deferred income tax expense (benefit) Federal — 1,236 1,236 State 1,249 (2,660) 2,137 Total deferred income tax expense (benefit) 1,249 (1,424) 3,373 Income tax expense (benefit) $ 1,560 $ (2,303) $ 2,137
Income Taxes Reconciliation	The following table reconciles the difference between the income tax expense (benefit) computed by applying the statutory tax rate to our income (loss) before income taxes and our reported income tax expense (benefit) for the periods presented: Year Ended December 31, 2021 2020 2019 Computed at federal statutory rate $ 21,100 21.0 % $ (65,701) 21.0 % $ 15,272 21.0 % State income taxes, net of federal income tax benefit 1,560 1.6 % (1,856) 0.6 % 1,494 2.1 % Change in valuation allowance (9,348) (9.3) % 64,062 (20.5) % (14,240) (19.6) % Noncontrolling interest (12,501) (12.4) % — — % — — % Other, net 749 0.7 % 1,192 (0.4) % (389) (0.5) % $ 1,560 1.6 % $ (2,303) 0.7 % $ 2,137 3.0 %
Summary of Principal Components of Net Deferred Income Tax Liability	The following table summarizes the principal components of our deferred income tax assets and liabilities as of the dates presented: December 31, 2021 2020 Deferred tax assets: Net operating loss (“NOL”) carryforwards $ 203,243 $ 180,531 Asset retirement obligations 63 1,188 Property and equipment 24,585 — Pension and postretirement benefits — 301 Share-based compensation — 467 Fair value of derivative instruments 493 2,737 Interest expense limitation 13,747 — ROU assets — 564 Other 18 1,484 Total deferred tax assets 242,149 187,272 Less: Valuation allowance (205,617) (179,006) Total net deferred tax assets $ 36,532 $ 8,266 Deferred tax liabilities: Property and equipment $ 3,357 $ 7,728 Investment in the Partnership 35,968 — ROU obligations — 538 Total deferred tax liabilities $ 39,325 $ 8,266 Net deferred tax liabilities $ (2,793) $ —

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Schedule of Lease, Cost	The following table summarizes supplemental balance sheet information related to leases as of the dates presented: December 31, Leases Balance Sheet Location 2021 2020 Assets ROU assets – operating leases Other assets $ 1,671 $ 2,432 Liabilities Current operating lease obligations Accounts payable and accrued liabilities $ 914 $ 936 Non-current operating lease obligations Other non-current liabilities 975 1,752 Total operating lease obligations $ 1,889 $ 2,688	The following table summarizes the components of our total lease cost for the periods presented: Year Ended December 31, 2021 2020 2019 Operating lease cost $ 891 $ 979 $ 773 Short-term lease cost 24,655 23,721 36,202 Variable lease cost 24,807 21,932 23,762 Less: Amounts charged as drilling costs 1 (21,213) (20,708) (33,354) Total lease cost recognized in the consolidated statement of operations 2 $ 29,140 $ 25,924 $ 27,383 ___________________ 1 Represents the combined gross amounts paid and (i) capitalized as drilling costs for our working interest share and (ii) billed to joint interest partners for their working interest share for short-term leases of operated drilling rigs. 2 Includes $10.8 million, $11.2 million and $12.1 million recognized in GPT, $17.4 million, $13.8 million and $14.5 million recognized in Lease operating expense (“LOE”) and $0.9 million, $1.0 million and $0.8 million recognized in G&A for the years ended December 31, 2021, 2020, and 2019, respectively.
Schedule of Supplemental Cash Flow Information Related to Leases [Table Text Block]	The following table summarizes supplemental cash flow information related to leases for the periods presented: Year Ended December 31, 2021 2020 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 981 $ 943 $ 659 ROU assets obtained in exchange for operating lease obligations 1 $ — $ 388 $ 3,325 ___________________ 1 Includes $2.5 million recognized upon adoption of ASC Topic 842, Leases and $0.8 million obtained during the twelve months ended December 31, 2019.
Schedule of Cash Flow, Supplemental Disclosures	The following table presents other information as it relates to operating leases as of the dates presented: December 31, 2021 2020 Weighted-average remaining lease term – operating leases 2.1 years 3.1 years Weighted-average discount rate – operating leases 3.13 % 3.24 %
Schedule of Lessee, Operating Lease, Liability, Maturity	As of December 31, 2021, maturities of our operating lease liabilities consisted of the following: December 31, 2021 2022 $ 930 2023 878 2024 146 2025 — 2026 — Total undiscounted lease payments 1,954 Less: imputed interest (65) Total operating lease obligations $ 1,889

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	As of December 31, 2021 Level 1 Level 2 Level 3 Total Financial assets: Commodity derivative assets – current $ — $ 11,478 $ — $ 11,478 Commodity derivative assets – non-current — 2,092 — 2,092 Total financial assets $ — $ 13,570 $ — $ 13,570 Financial liabilities: Interest rate swap liabilities – current $ — $ (1,480) $ — $ (1,480) Commodity derivative liabilities – current — (48,892) — (48,892) Commodity derivative liabilities – non-current — (23,815) — (23,815) Total financial liabilities $ — $ (74,187) $ — $ (74,187) As of December 31, 2020 Level 1 Level 2 Level 3 Total Financial assets: Commodity derivative assets – current $ — $ 75,506 $ — $ 75,506 Commodity derivative assets – non-current — 25,449 — 25,449 Total financial assets $ — $ 100,955 $ — $ 100,955 Financial liabilities: Interest rate swap liabilities – current $ — $ (3,655) $ — $ (3,655) Interest rate swap liabilities – non-current — (1,645) — (1,645) Commodity derivative liabilities – current — (81,451) — (81,451) Commodity derivative liabilities – non-current — (26,789) — (26,789) Total financial liabilities $ — $ (113,540) $ — $ (113,540)

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Schedule of Loss Contingencies by Contingency	The following table sets forth our significant commitments as of December 31, 2021, by category, for the next 5 years and thereafter: Year Gathering and Intermediate Transportation Commitments Other Commitments 2022 $ 13,937 $ 380 2023 13,937 143 2024 13,976 56 2025 13,937 — 2026 7,794 — Thereafter 15,808 — Total $ 79,389 $ 579
Purchase Commitment, Excluding Long-term Commitment [Table Text Block]	The following table provides details on these contractual arrangements as of December 31, 2021: Description of contractual arrangement Expiration Minimum Expiration of Minimum Volume Commitment Field gathering agreement February 2041 8,000 February 2031 Intermediate pipeline transportation services February 2026 8,000 February 2026 Volume capacity support April 2026 8,000 April 2026

Share-Based Compensation and _2

Share-Based Compensation and Other Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Activity of Awarded Restricted Stock Units	The table below presents information pertaining to PRSUs granted in the following periods: 2021 2020 2019 PRSUs granted 1 225,206 145,399 15,066 Monte Carlo grant date fair value 2 $17.74 to $33.31 $2.40 to $16.02 $ 34.02 Average grant date fair value 3 $13.63 not applicable not applicable ___________________ 1 The 2020 PRSU grants include one executive officers’ inducement award originally granted in August 2020 that was amended in April 2021 to conform vesting conditions to other PRSU awards granted in 2021. 2 Represents the Monte Carlo grant date fair value of 2021 and 2020 PRSU grants based on the Company’s TSR performance (as defined below). 3 Represents the average grant date fair value of 2021 PRSU grants based on the Company’s ROCE performance (as defined below).
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Activity of Awarded Restricted Stock Units	The following table summarizes activity for our most recent fiscal year with respect to awarded RSUs: Restricted Stock Weighted-Average Balance at beginning of year 319,280 $ 13.56 Granted 120,262 $ 14.12 Vested (174,972) $ 20.81 Forfeited (34,053) $ 10.65 Balance at end of year 230,517 $ 9.20
Performance Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Share-based Payment Award, Equity Instruments Other than Options, Valuation Assumptions	The ranges for the assumptions used in the Monte Carlo model for the PRSUs granted during 2021, 2020 and 2019 are presented as follows: 2021 1 2020 1 2019 Expected volatility 131.74% to 134.74% 101.32% to 117.71% 49.90 % Dividend yield 0.0 % 0.0 % 0.0 % Risk-free interest rate 0.22% to 0.29% 0.18% to 0.51% 1.66 % Performance period 2021-2023 2020-2022 2020-2022 ___________________ 1 One executive officer’s inducement award originally granted in August 2020 was amended in April 2021 to conform vesting conditions to other PRSU awards granted in 2021. The Monte Carlo assumptions for both years are included above.
Activity of Awarded Performance-based RSUs	The following table summarizes activity for our most recent fiscal year with respect to PRSUs: Performance Restricted Stock Weighted-Average Grant Date Balance at beginning of year 173,532 $ 13.68 Granted 225,206 $ 22.44 Vested (9,816) $ 26.60 Forfeited (43,853) $ 14.90 Balance at end of year 345,069 $ 16.20

Earnings per Share (Tables)

Earnings per Share (Tables)	12 Months Ended
	Dec. 31, 2021
Earnings Per Share [Abstract]
Components of Calculation of Basic and Diluted Earnings Per Share	The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings per share for the periods presented: Year Ended December 31, 2021 2020 2019 Net income (loss) $ 98,918 $ (310,557) $ 70,589 Net income attributable to Noncontrolling interest (58,689) — — Net income (loss) attributable to common shareholders (basic) 40,229 (310,557) 70,589 Reallocation of Noncontrolling interest net income 58,689 — — Net income (loss) attributable to common shareholders (diluted) $ 98,918 $ (310,557) $ 70,589 Weighted-average shares – basic 16,695 15,176 15,110 Effect of dilutive securities: Common Units exchangeable for common shares — — — RSUs and PRSUs 470 — 16 Weighted-average shares – diluted 1 17,165 15,176 15,126 _____________________________________________
Schedule of Changes in Ownership Interest in Consolidated Subsidiaries	The following table summarizes changes in the ownership interest in consolidated subsidiaries during the period: Year Ended December 31, 2021 2020 2019 Net income (loss) attributable to common shareholders $ 40,229 $ (310,557) $ 70,589 Change in ownership of consolidated subsidiaries 1 (57,604) N/A N/A Change from net income (loss) attributable to common shareholders and transfers to Noncontrolling interest $ (17,375) $ (310,557) $ 70,589 _____________________________________________ 1 The year ended December 31, 2021 includes an adjustment to Noncontrolling interest for the Lonestar Acquisition of $57.6 million and to Additional paid-in-capital of $57.6 million to reflect the change in ownership structure that was effective at October 5, 2021 relating to the noncontrolling interest arising from the Juniper Transactions on January 15, 2021. The adjustment had no impact on earnings. See Note 4 for further details.

Nature of Operations (Details)

Nature of Operations (Details)	12 Months Ended
	Dec. 31, 2021segment$ / shares	Oct. 05, 2021$ / shares	Dec. 31, 2020$ / shares
Class of Stock [Line Items]
Number of Reportable Segments | segment	1
Common stock, par value (in dollars per share)		$ 0.01
Class A Common Stock
Class of Stock [Line Items]
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01

Summary of Significant Accoun_3

Summary of Significant Accounting Policies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2021
Minimum
Property, Plant and Equipment [Line Items]
Lessee, Operating Lease, Term of Contract	2 years
Maximum
Property, Plant and Equipment [Line Items]
Lessee, Operating Lease, Term of Contract	5 years
Other Capitalized Property Plant and Equipment [Member] | Minimum
Property, Plant and Equipment [Line Items]
Useful life	3 years
Other Capitalized Property Plant and Equipment [Member] | Maximum
Property, Plant and Equipment [Line Items]
Useful life	20 years
Gas Gathering and Processing Equipment [Member] | Minimum
Property, Plant and Equipment [Line Items]
Useful life	15 years
Gas Gathering and Processing Equipment [Member] | Maximum
Property, Plant and Equipment [Line Items]
Useful life	20 years

Summary of Significant Accoun_4

Summary of Significant Accounting Policies Lessee, Lease, Description (Details)	Dec. 31, 2021
Maximum
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract	5 years
Minimum
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract	2 years

Transactions - Additional Infor

Transactions - Additional Information - Lonestar (Detail) $ / shares in Units, $ in Thousands	Oct. 05, 2021USD ($)$ / shares	Aug. 10, 2021USD ($)	Dec. 31, 2021USD ($)
Senior Notes Due 2026 | Senior Notes
Significant Acquisitions and Disposals
Interest rate		9.25%
Second Lien Term Loan
Significant Acquisitions and Disposals
Repayments of long-term debt		$ 146,200
Other Long Term Debt
Significant Acquisitions and Disposals
Repayments of long-term debt		$ 249,800
Lonestar
Significant Acquisitions and Disposals
Acquisition, share ratio	0.51
Acquisition, share price (in dollars per share) | $ / shares	$ 30.19
Acquisition, share value	$ 173,576
Funds released from escrow	$ 411,500
Revenue of acquiree since acquisition date			$ 62,500
Direct operating expenses of acquireee since acquisition date			34,000
Acquisition-related costs			$ 29,559

Transactions - Purchase Price A

Transactions - Purchase Price Allocation - Lonestar (Details) - USD ($) $ in Thousands	Oct. 05, 2021	Dec. 31, 2021
Liabilities:
Payments to restructure derivative instruments	$ 50,000
Lonestar
Business Acquisition [Line Items]
Fair value of the Company's common stock issued	173,576
Less: Replacement awards attributable to post-combination compensation cost	(10,394)
Total consideration transferred	163,182
Assets:
Other current assets	50,044
Proved oil and gas properties	476,743
ARO asset	1,239
Boland building and related assets	11,400
Other property and equipment	2,582
Other non-current assets	37
Total assets acquired	542,045
Liabilities:
Current portion of long-term debt	24,187
Other current liabilities	66,150
Derivative liabilities - non-current	49,554
Asset retirement obligations	2,494
Long-term debt	236,478
Total liabilities assumed	378,863	$ 2,500
Net Assets Acquired	163,182
Fair value of replacement awards for services provided prior to closing	$ 4,500

Transactions - Acquisition Rela

Transactions - Acquisition Related Costs (Details) - Lonestar $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs, Bank, Legal and Consulting Fees	$ 9,856
Business Combination, Acquisition Related Costs, Employee Severance and Related Costs	7,563
Business Combination, Acquisition Related Costs, Replacement Awards Stock Based Compensation Costs	10,394
Business Combination, Acquisition Related Costs, Integration and Rebranding Costs	1,746
Business Combination, Acquisition Related Costs	$ 29,559

Transactions - Pro Forma Inform

Transactions - Pro Forma Information - Lonestar (Details) - Lonestar - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Business Acquisition [Line Items]
Total revenues	$ 729,026	$ 389,495
Net income (loss) attributable to common shareholders	$ 74,355	$ (321,951)

Transactions - Juniper Transact

Transactions - Juniper Transaction (Details) - USD ($) $ / shares in Units, $ in Thousands	Jan. 15, 2021	Jan. 15, 2021	Mar. 31, 2021	Dec. 31, 2021	Apr. 01, 2021	Jan. 14, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Common Unit, Issued	15,268,686	15,268,686
Proceeds from Contributed Capital	$ 150,000
Contribution Agreement - Common Shares	17,142,857	17,142,857
Contribution Agreement - Preferred Shares	171,428.57	171,428.57
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01		$ 0.01			$ 0.01
Asset Agreement - Common Shares	5,405,252	5,405,252			5,406,141
Asset Agreement - Preferred Shares	54,052.52	54,052.52			54,061.41
Common Units Placed in Indemnity Escrow	495,900	495,900
Preferred Shares Placed in Indemnity Escrow	4,959	4,959
Cash Received Related to Revenues Attributable to Production from RCR	$ 1,160	$ 1,200
Suspense revenues attributable to RCR	(146)
Issue costs of noncontrolling interest securities paid	(3,758)
Transaction costs of noncontrolling interest paid	(5,543)
Oil and Gas Property Contributed	38,561
Asset Retirement Obligations of Contributed Property	(14)
Capital contributions Fair Value	180,260
Shareholder's equity, noncontrolling interest	$ 385,110	$ 385,110		$ 669,508		$ 205,558	$ 212,838	$ 520,745	$ 447,355
Percentage of ownership after transaction	59.60%	59.60%
Noncontrolling interest	$ 229,620	$ 229,620		$ 345,976			$ 0
Juniper Transaction
Business Acquisition [Line Items]
Professional Fees And Other Costs	19,000
Income Tax Adjustment	(708)
Juniper Transaction | Costs And Services Incurred In Current Period
Business Acquisition [Line Items]
Professional Fees And Other Costs	14,000
Juniper Transaction | Contingent Transaction Costs To Be Paid Upon Closing
Business Acquisition [Line Items]
Professional Fees And Other Costs	5,500
Juniper Transaction | Costs Related to Issuance of Preferred Shares and Common Units
Business Acquisition [Line Items]
Professional Fees And Other Costs	3,800
Juniper Transaction | Costs And Services - G&A
Business Acquisition [Line Items]
Professional Fees And Other Costs	$ 5,000		$ 4,700

Transactions - Eagle Ford Worki

Transactions - Eagle Ford Working Interests (Details) $ in Millions	Dec. 31, 2019USD ($)
Working Interests Acquisition [Member] [Domain]
Asset Acquisition, Contingent Consideration [Line Items]
Cash Paid on Date of Acquisition	$ 6.5

Revenue Recognition - Summary o

Revenue Recognition - Summary of Accounts Receivable (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Receivables [Abstract]
Customers	$ 96,195	$ 39,672
Joint interest partners	21,755	3,079
Derivative settlements from counterparties	1,037	3,287
Other	18	8
Total	119,005	46,046
Less: Allowance for credit losses	(411)	(197)
Accounts receivable, net of allowance for credit losses	$ 118,594	$ 45,849

Revenue Recognition - Additiona

Revenue Recognition - Additional Information (Detail) - Revenue Benchmark - Customer Concentration Risk - Customer	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accounts, Notes, Loans and Financing Receivable [Line Items]
Number of major customers	3	3	4
Three Major Customers
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration risk, percentage	48.00%	56.00%
Four Major Customers
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration risk, percentage			76.00%
Major Customer 1
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration risk, percentage	22.00%	27.00%	37.00%
Major Customer 2
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration risk, percentage	14.00%	19.00%	18.00%
Major Customer 3
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration risk, percentage	12.00%	10.00%	11.00%
Major Customer 4
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration risk, percentage			10.00%

Derivative Instruments - Additi

Derivative Instruments - Additional Information (Detail)	Dec. 31, 2021USD ($)Entity	Dec. 31, 2020USD ($)
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative Liability	$ 74,187,000	$ 113,540,000
Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, Notional Amount	$ 300,000,000
Derivative, Average Fixed Interest Rate	1.36%
Derivative Liability	$ 1,500,000
Number Of Derivative Counterparty | Entity	4
Commodity contracts
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative Liability	$ 59,100,000
Number Of Derivative Counterparty | Entity	8

Commodity Derivative Positions

Commodity Derivative Positions (Detail)	Dec. 31, 2021bblMMBtugal$ / bbl$ / MMBtu$ / gal
First Quarter 2022 | Crude Oil | Swap
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	3,250
Derivative, Swap Type, Average Fixed Price	75.16
First Quarter 2022 | Crude Oil | 2-Way Collars
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	17,083
Derivative, Floor Price	56.10
Derivative, Cap Price	70.49
First Quarter 2022 | Crude Oil | Purchased Put
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	9,444
Derivative, Swap Type, Average Fixed Price	65.74
First Quarter 2022 | Crude Oil | CMA Roll Basis Swap
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	13,333
Derivative, CMA Roll Basis Swap, Price	0.880
First Quarter 2022 | Crude Oil | NYMEX HH Swaps
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | MMBtu	17,500
Derivative, NYMEX HH Swap, Price | $ / MMBtu	4.349
First Quarter 2022 | Natural Gas | 2-Way Collars
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | MMBtu	3,333
Derivative, Floor Price | $ / MMBtu	4.150
Derivative, Cap Price | $ / MMBtu	5.750
Second Quarter 2022 | Crude Oil | Swap
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	3,000
Derivative, Swap Type, Average Fixed Price	74.12
Second Quarter 2022 | Crude Oil | 2-Way Collars
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	14,423
Derivative, Floor Price	54.29
Derivative, Cap Price	72.84
Second Quarter 2022 | Crude Oil | CMA Roll Basis Swap
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	13,187
Derivative, CMA Roll Basis Swap, Price	0.880
Second Quarter 2022 | Crude Oil | NYMEX HH Swaps
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | MMBtu	12,500
Derivative, NYMEX HH Swap, Price | $ / MMBtu	3.727
Second Quarter 2022 | Crude Oil | OPIS Mt Belv Ethane Swaps
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | gal	28,022
Derivative, OPIS Mt Belv Ethane Swaps, Price | $ / gal	0.2500
Second Quarter 2022 | Natural Gas | 2-Way Collars
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | MMBtu	13,187
Derivative, Floor Price | $ / MMBtu	2.500
Derivative, Cap Price | $ / MMBtu	3.220
Third Quarter 2022 | Crude Oil | Swap
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	3,000
Derivative, Swap Type, Average Fixed Price	73.01
Third Quarter 2022 | Crude Oil | 2-Way Collars
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	7,745
Derivative, Floor Price	47.37
Derivative, Cap Price	64.60
Third Quarter 2022 | Crude Oil | CMA Roll Basis Swap
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	6,522
Derivative, CMA Roll Basis Swap, Price	1.135
Third Quarter 2022 | Crude Oil | NYMEX HH Swaps
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | MMBtu	12,500
Derivative, NYMEX HH Swap, Price | $ / MMBtu	3.745
Third Quarter 2022 | Crude Oil | OPIS Mt Belv Ethane Swaps
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | gal	27,717
Derivative, OPIS Mt Belv Ethane Swaps, Price | $ / gal	0.2500
Third Quarter 2022 | Natural Gas | 2-Way Collars
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | MMBtu	13,043
Derivative, Floor Price | $ / MMBtu	2.500
Derivative, Cap Price | $ / MMBtu	3.220
Fourth Quarter 2022 | Crude Oil | Swap
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	3,000
Derivative, Swap Type, Average Fixed Price	69.20
Fourth Quarter 2022 | Crude Oil | 2-Way Collars
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	6,114
Derivative, Floor Price	45.33
Derivative, Cap Price	60.87
Fourth Quarter 2022 | Crude Oil | CMA Roll Basis Swap
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	6,522
Derivative, CMA Roll Basis Swap, Price	1.135
Fourth Quarter 2022 | Crude Oil | NYMEX HH Swaps
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | MMBtu	12,500
Derivative, NYMEX HH Swap, Price | $ / MMBtu	3.793
Fourth Quarter 2022 | Crude Oil | OPIS Mt Belv Ethane Swaps
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | gal	27,717
Derivative, OPIS Mt Belv Ethane Swaps, Price | $ / gal	0.2500
Fourth Quarter 2022 | Natural Gas | 2-Way Collars
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | MMBtu	13,043
Derivative, Floor Price | $ / MMBtu	2.500
Derivative, Cap Price | $ / MMBtu	3.220
First Quarter 2023 | Crude Oil | Swap
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	2,500
Derivative, Swap Type, Average Fixed Price	54.40
First Quarter 2023 | Crude Oil | 2-Way Collars
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	2,917
Derivative, Floor Price	40
Derivative, Cap Price	50
First Quarter 2023 | Crude Oil | NYMEX HH Swaps
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | MMBtu	10,000
Derivative, NYMEX HH Swap, Price | $ / MMBtu	3.620
Second Quarter 2023 | Crude Oil | Swap
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	2,400
Derivative, Swap Type, Average Fixed Price	54.26
Second Quarter 2023 | Crude Oil | 2-Way Collars
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	2,885
Derivative, Floor Price	40
Derivative, Cap Price	50
Second Quarter 2023 | Crude Oil | NYMEX HH Swaps
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | MMBtu	7,500
Derivative, NYMEX HH Swap, Price | $ / MMBtu	3.690
Second Quarter 2023 | Crude Oil | OPIS Mt Belv Ethane Swaps
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | gal	98,901
Derivative, OPIS Mt Belv Ethane Swaps, Price | $ / gal	0.2288
Second Quarter 2023 | Natural Gas | 2-Way Collars
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | MMBtu	11,538
Derivative, Floor Price | $ / MMBtu	2.500
Derivative, Cap Price | $ / MMBtu	2.682
Third Quarter 2023 | Crude Oil | Swap
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	2,807
Derivative, Swap Type, Average Fixed Price	54.92
Third Quarter 2023 | Crude Oil | OPIS Mt Belv Ethane Swaps
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | gal	34,239
Derivative, OPIS Mt Belv Ethane Swaps, Price | $ / gal	0.2275
Third Quarter 2023 | Natural Gas | 2-Way Collars
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | MMBtu	11,413
Derivative, Floor Price | $ / MMBtu	2.500
Derivative, Cap Price | $ / MMBtu	2.682
Fourth Quarter 2023 | Crude Oil | Swap
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	2,657
Derivative, Swap Type, Average Fixed Price	54.93
Fourth Quarter 2023 | Crude Oil | OPIS Mt Belv Ethane Swaps
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | gal	34,239
Derivative, OPIS Mt Belv Ethane Swaps, Price | $ / gal	0.2275
Fourth Quarter 2023 | Natural Gas | 2-Way Collars
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | MMBtu	11,413
Derivative, Floor Price | $ / MMBtu	2.500
Derivative, Cap Price | $ / MMBtu	2.682
First Quarter 2024 | Crude Oil | Swap
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	462
Derivative, Swap Type, Average Fixed Price	58.75
First Quarter 2024 | Crude Oil | OPIS Mt Belv Ethane Swaps
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | gal	34,615
Derivative, OPIS Mt Belv Ethane Swaps, Price | $ / gal	0.2275
First Quarter 2024 | Natural Gas | 2-Way Collars
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | MMBtu	11,538
Derivative, Floor Price | $ / MMBtu	2.500
Derivative, Cap Price | $ / MMBtu	3.650
Second Quarter 2024 | Crude Oil | Swap
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	462
Derivative, Swap Type, Average Fixed Price	58.75
Second Quarter 2024 | Natural Gas | 2-Way Collars
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | MMBtu	11,538
Derivative, Floor Price | $ / MMBtu	2.328
Derivative, Cap Price | $ / MMBtu	3

Impact of Derivative Activities

Impact of Derivative Activities on Condensed Consolidated Statements of Income (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Interest Rate Swap losses recognized in the consolidated statements of operations	$ (2)	$ (7,510)	$ 0
Gain (Loss) on Commodity Derivative Instruments	(136,997)	95,932	(68,131)
Derivatives	(136,999)	88,422	(68,131)
Interest rate cash settlements recognized in the consolidated statements of cash flows	(3,822)	(2,210)	0
Commodity cash settlements and premiums received (paid) recognized in the consolidated statements of cash flows	(77,099)	80,297	(4,136)
Commodity cash settlements paid for acquired derivatives recognized in the consolidated statements of cash flows	(49,554)	0	0
Commodity cash settlements and premiums received (paid) recognized in the consolidated statements of cash flows	$ (130,475)	$ 78,087	$ (4,136)

Fair Value of Derivative Instru

Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Commodity derivative assets – current	$ 11,478	$ 75,506
Derivative liabilities	50,372	85,106
Derivative assets	2,092	25,449
Derivative liabilities	23,815	28,434
Total financial assets	13,570	100,955
Derivative liabilities	74,187	113,540
Interest Rate Swap
Derivatives, Fair Value [Line Items]
Derivative liabilities	1,500
Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative liabilities	59,100
Derivative assets/liabilities - current | Interest Rate Swap
Derivatives, Fair Value [Line Items]
Commodity derivative assets – current	0	0
Derivative liabilities	1,480	3,655
Derivative assets/liabilities - current | Commodity contracts
Derivatives, Fair Value [Line Items]
Commodity derivative assets – current	11,478	75,506
Derivative liabilities	48,892	81,451
Derivative assets/liabilities - noncurrent | Interest Rate Swap
Derivatives, Fair Value [Line Items]
Derivative assets	0	0
Derivative liabilities	0	1,645
Derivative assets/liabilities - noncurrent | Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative assets	2,092	25,449
Derivative liabilities	$ 23,815	$ 26,789

Summary of Property and Equipme

Summary of Property and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Oil and gas properties:
Proved Oil and Gas Property, Full Cost Method	$ 2,327,686	$ 1,545,910
Unproved Oil and Gas Property, Full Cost Method	57,900	49,935
Oil and Gas Property, Full Cost Method, Gross	2,385,586	1,595,845
Other property and equipment 1	31,055	27,746
Total properties and equipment	2,416,641	1,623,591
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	(1,033,293)	(900,042)
Total property and equipment, net	$ 1,383,348	$ 723,549

Property and Equipment - Additi

Property and Equipment - Additional Information (Details)	12 Months Ended
	Dec. 31, 2021USD ($)$ / bbl	Dec. 31, 2020USD ($)$ / bbl	Dec. 31, 2019USD ($)$ / bbl	Dec. 31, 2018USD ($)
Property, Plant and Equipment [Abstract]
Unproved Oil and Gas Property excluded	$ 57,900,000	$ 49,900,000
Costs Associated With Wells In Progress, Excluded From Amortization		1,200,000
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative	8,400,000	700,000	$ 0	$ 37,300,000
Capitalized Interest Remaining	11,500,000
Undeveloped Leasehold Costs Transferred	17,800,000	8,300,000
Capitalized Costs, Proved Properties	4,100,000	2,100,000	4,100,000
Interest Costs Capitalized	$ 3,600,000	$ 2,700,000	$ 4,100,000
Amortization Expense Per Physical Unit of Production | $ / bbl	12.96	15.83	17.25
Impairments of oil and gas properties	$ 1,811,000	$ 391,849,000	$ 0

Reconciliation of Asset Retirem

Reconciliation of Asset Retirement Obligations which are Included in Other Liabilities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of period	$ 5,461	$ 4,934
Changes in estimates	0	33
Liabilities incurred	226	121
Liabilities settled	(228)	0
Acquisitions of properties	(2,508)	(16)
Accretion expense	446	357
Balance at end of period	$ 8,413	$ 5,461

Summary of Long-Term Debt (Deta

Summary of Long-Term Debt (Detail) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Jan. 31, 2021	Dec. 31, 2021	Oct. 05, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 618,954		$ 514,400
Debt Instrument, Unamortized Discount		(3,720)		(1,604)
Unamortized Debt Issuance Expense		(9,853)		(3,299)
Long-term Debt		605,381		509,497
Current portion of long-term debt		(4,129)		0
Long-term debt, net		601,252		509,497
Lonestar
Debt Instrument [Line Items]
Business combination, recognized identifiable assets acquired and liabilities assumed, long-term debt, gross		2,200
Revolving credit facility
Debt Instrument [Line Items]
Long-term Debt, Gross		208,000		314,400
Term Loan
Debt Instrument [Line Items]
Long-term Debt, Gross		0		200,000
Senior Notes
Debt Instrument [Line Items]
Long-term Debt, Gross		400,000		0
Mortgages
Debt Instrument [Line Items]
Long-term Debt, Gross		8,438		0
Other Long Term Debt
Debt Instrument [Line Items]
Long-term Debt, Gross		$ 2,516		$ 0
Second Lien Facility
Debt Instrument [Line Items]
Credit facility interest rate option one, applicable margin rate over Adjusted LIBOR	9.25%	8.25%
Unamortized Debt Issuance Expense			$ (6,900)

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail)	Aug. 10, 2021USD ($)	Jan. 31, 2021USD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Oct. 05, 2021USD ($)	Aug. 31, 2021USD ($)	May 03, 2019USD ($)	Sep. 29, 2017USD ($)
Debt Disclosure [Line Items]
Debt Issuance Costs, Line of Credit Arrangements, Gross			$ 2,600,000	$ 100,000
Required covenant, current ratio			1
Accelerated Deferred Debt Issuance Cost			$ 800,000	900,000
Second Lien Facility								$ 200,000,000
Amortization Payment		$ 1,875,000
Unamortized Debt Issuance Expense			9,853,000	3,299,000
Eleventh Amendment | Revolving Credit Facility
Debt Disclosure [Line Items]
Maximum borrowing capacity						$ 600,000,000
Revolving Credit Facility
Debt Disclosure [Line Items]
Maximum borrowing capacity			725,000,000			$ 375,000,000	$ 1,000,000,000
Debt Instrument, Aggregate Elected Commitments			400,000,000
Letter of credit amount outstanding			$ 900,000	$ 400,000
Line of Credit Facility, Interest Rate at Period End			3.26%
Required covenant, debt to EBITDAX ratio			3.50
Revolving Credit Facility | Minimum
Debt Disclosure [Line Items]
Credit facility interest rate option one, applicable margin rate over Adjusted LIBOR			1.50%
Revolving Credit Facility | Maximum
Debt Disclosure [Line Items]
Credit facility interest rate option one, applicable margin rate over Adjusted LIBOR			2.50%
Credit facility interest rate option two, applicable margin rate			3.50%
Commitment fees for undrawn credit facility			0.50%
Second Lien Facility
Debt Disclosure [Line Items]
Debt Issuance Costs, Line of Credit Arrangements, Gross		$ 1,400,000
Credit facility interest rate option one, applicable margin rate over Adjusted LIBOR		9.25%	8.25%
Credit facility interest rate option two, applicable margin rate		8.25%	7.25%
Prepayment Premium					102.00%
Repayments of Debt		$ 1,300,000
Asset Coverage Ratio		1.25
Payment for Debt Extinguishment or Debt Prepayment Cost		$ 50,000,000
Interest Rate Floor			1.00%
Write off Deferred Debit Issuance and Original Issuance Costs		$ 1,200,000
Unamortized Debt Issuance Expense					$ 6,900,000
Second Lien Facility | Interest Payable One [Member]
Debt Disclosure [Line Items]
Debt Instrument, Interest Payable Period			1 month
Second Lien Facility | Interest Payable Two [Member]
Debt Disclosure [Line Items]
Debt Instrument, Interest Payable Period			3 months
Second Lien Facility | Interest Payable Three [Member]
Debt Disclosure [Line Items]
Debt Instrument, Interest Payable Period			6 months
Letter of Credit
Debt Disclosure [Line Items]
Maximum borrowing capacity			$ 25,000,000
Senior Notes Due 2026 | Senior Notes
Debt Disclosure [Line Items]
Interest rate	9.25%
Debt Instrument, Face Amount	$ 400,000,000
Debt Instrument, Redemption Price, Percentage	99.018%
Amortization of Debt Issuance Costs			$ 10,400,000

Summary of Provision for Income

Summary of Provision for Income Taxes from Continuing Operations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Federal	$ 0	$ (1,236)	$ (1,236)
Current State and Local Tax Expense (Benefit)	311	357	0
Current Income Tax Expense (Benefit)	311	(879)	(1,236)
Current income tax expense (benefit), total	311	(879)	(1,236)
Deferred Federal Income Tax Expense (Benefit)	0	1,236	1,236
Deferred State and Local Income Tax Expense (Benefit)	1,249	(2,660)	2,137
Deferred income tax benefit, total	1,249	(1,424)	3,373
Income tax benefit	$ 1,560	$ (2,303)	$ 2,137

Income Taxes Reconciliation (De

Income Taxes Reconciliation (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Computed at federal statutory rate	$ 21,100	$ (65,701)	$ 15,272
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount	(1,560)	1,856	(1,494)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	9,348	(64,062)	14,240
Noncontrolling interest	(12,501)	0	0
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount	749	1,192	(389)
Income tax benefit	$ 1,560	$ (2,303)	$ 2,137
Effective Income Tax Rate Reconciliation, Percent	1.60%	0.70%	3.00%
Computed at federal statutory rate	(21.00%)	(21.00%)	(21.00%)
State income taxes, net of federal income tax benefit	1.60%	0.60%	2.10%
Deferred Federal Income Tax Expense (Benefit)	$ 0	$ 1,236	$ 1,236
Change in valuation allowance	9.30%	20.50%	19.60%
Effective Income Tax Rate Reconciliation, Noncontrolling Interest Income (Loss), Percent	(12.40%)	0.00%	0.00%
Other, net	0.70%	(0.40%)	(0.50%)
Computed at federal statutory rate	21.00%	21.00%	21.00%

Summary of Principal Components

Summary of Principal Components of Net Deferred Income Tax Liability (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Deferred income taxes	$ 2,793	$ 0
Deferred Tax Assets, Operating Loss Carryforwards	203,243	180,531
Total net deferred tax assets	36,532	8,266
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Asset Retirement Obligations	63	1,188
Deferred Tax Assets, Property, Plant and Equipment	24,585	0
Deferred Tax Liabilities, Property, Plant and Equipment	3,357	7,728
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Postretirement Benefits	0	301
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	0	467
Deferred Tax Liabilities, Investments	35,968	0
Deferred Tax Liabilities, ROU Obligations	0	538
Less: Valuation allowance	(205,617)	(179,006)
Deferred Tax Asset, Interest Carryforward	13,747	0
Deferred Tax Assets, Other	18	1,484
Deferred Tax Assets, ROU Assets	0	564
Deferred Tax Assets, Gross	242,149	187,272
Deferred Tax Assets, Derivative Instruments	493	2,737
Deferred Tax and Other Liabilities, Noncurrent	$ 39,325	$ 8,266

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Valuation Allowance [Line Items]
Computed at federal statutory rate	21.00%	21.00%	21.00%
Deferred State and Local Income Tax Expense (Benefit)	$ 1,249,000	$ (2,660,000)	$ 2,137,000
Current State and Local Tax Expense (Benefit)	311,000	357,000	0
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount	749,000	1,192,000	(389,000)
Liabilities for unrecognized tax benefits	0	0
Deferred Tax Assets, Valuation Allowance	205,617,000	179,006,000
Income Tax Examination, Penalties and Interest Expense	$ 0	$ 0	$ 0
Effective Income Tax Rate Reconciliation, Percent	1.60%	0.70%	3.00%
Deferred Federal Income Tax Expense (Benefit)	$ 0	$ 1,236,000	$ 1,236,000
Federal	0	(1,236,000)	(1,236,000)
Deferred income taxes	2,793,000	0
Deferred Tax and Other Liabilities, Noncurrent	39,325,000	8,266,000
Lonestar
Valuation Allowance [Line Items]
Deferred Tax Assets, Valuation Allowance	24,800,000
TEXAS
Valuation Allowance [Line Items]
Current State and Local Tax Expense (Benefit)	300,000	$ 400,000	$ 0
Federal
Valuation Allowance [Line Items]
Operating Loss Carryforwards	$ 746,800,000

Leases (Details)

Leases (Details) - USD ($) $ in Thousands	Jan. 01, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Operating Lease, Cost		$ 891	$ 979	$ 773
Short-term Lease, Cost		24,655	23,721	36,202
Variable Lease, Cost		24,807	21,932	23,762
Amounts charged as dilling costs		(21,213)	(20,708)	(33,354)
Lease, Cost		29,140	25,924	27,383
Operating Lease, Payments		981	943	659
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	$ 2,500	$ 0	388	3,325
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability, During the Year			$ 800
Operating Lease, Weighted Average Remaining Lease Term		2 years 1 month 6 days	3 years 1 month 6 days
Operating Lease, Weighted Average Discount Rate, Percent		3.13%	3.24%
Natural Gas, Gathering, Transportation, Marketing and Processing [Member]
Lessee, Lease, Description [Line Items]
Lease, Cost		$ 10,800	$ 11,200	12,100
Operating Expense
Lessee, Lease, Description [Line Items]
Lease, Cost		17,400	13,800	14,500
General and Administrative Expense
Lessee, Lease, Description [Line Items]
Lease, Cost		$ 900	$ 1,000	$ 800

Leases - Balance Sheet Composit

Leases - Balance Sheet Composition (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Assets
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	Other assets	Other assets
ROU assets – operating leases	$ 1,671	$ 2,432
Liabilities
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Accounts payable and accrued liabilities	Accounts payable and accrued liabilities
Current operating lease obligations	$ 914	$ 936
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other non-current liabilities	Other non-current liabilities
Non-current operating lease obligations	$ 975	$ 1,752
Total operating lease obligations	$ 1,889	$ 2,688

Leases - Future Minimum Operati

Leases - Future Minimum Operating Lease Payments (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
2022	$ 930
2023	878
2024	146
2025	0
2026	0
Total undiscounted lease payments	1,954
Less: imputed interest	(65)
Total operating lease obligations	$ 1,889	$ 2,688

Supplemental Balance Sheet De_2

Supplemental Balance Sheet Detail (Details) - USD ($)	Dec. 31, 2021	Oct. 05, 2021	Dec. 31, 2020
Prepaid and other current assets:
Inventory, Net	$ 10,305,000		$ 4,274,000
Prepaid Expense, Current	10,693,000		14,771,000
Other current assets	20,998,000		19,045,000
Other assets:
Debt Issuance Costs, Noncurrent, Net	3,308,000		2,349,000
ROU assets – operating leases	1,671,000		2,432,000
Other	38,000		127,000
Other Assets, Noncurrent, Total	5,017,000		4,908,000
Accounts payable and accrued liabilities:
Trade accounts payable	32,452,000		7,055,000
Accounts Payable, Other, Current	35,045,000		16,088,000
Accrued Royalties, Current	95,521,000		26,615,000
Production, ad valorem and other taxes	7,905,000		3,094,000
Derivative settlements to counterparties	6,117,000		321,000
Compensation-related	13,942,000		4,222,000
Interest Payable, Current	15,321,000		504,000
Environmental remediation liability	2,287,000		0
Operating Lease, Liability, Current	914,000		936,000
Other Accrued Liabilities, Current	4,877,000		4,254,000
Accounts Payable and Accrued Liabilities, Current, Total	214,381,000		63,089,000
Other non-current liabilities:
Asset Retirement Obligations, Noncurrent	8,413,000		5,461,000
Operating Lease, Liability, Noncurrent	975,000		1,752,000
Postretirement health care benefit obligations	970,000		1,149,000
Other Liabilities, Noncurrent, Total	10,358,000		8,362,000
Tubular inventory and well materials	9,500,000		3,900,000
Crude oil volumes in storage	800,000		400,000
Drilling and Completion Prepayment	9,600,000		$ 13,600,000
Accrued Expenses - Juniper Transaction	3,500,000
Lonestar
Business Acquisition [Line Items]
Liabilities assumed	$ 2,500,000	$ 378,863,000

Fair Value Measurements (Detail

Fair Value Measurements (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Aug. 10, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Gross	$ 618,954		$ 514,400
Long-term Debt, Fair Value			634,600
Financial assets:
Commodity derivative assets – current	11,478		75,506
Derivative assets	2,092		25,449
Total financial assets	13,570		100,955
Financial liabilities:
Derivative liabilities, current	50,372		85,106
Derivative liabilities, noncurrent	23,815		28,434
Derivative Liability	74,187		113,540
Commodity contracts
Financial liabilities:
Derivative Liability	$ 59,100
Commodity contracts | Crude Oil
Financial liabilities:
Underlying basis	WTI
Commodity contracts | MEH
Financial liabilities:
Underlying basis	MEH
Interest Rate Swap
Financial liabilities:
Derivative Liability	$ 1,500
Fair Value, Measurements, Recurring | Commodity contracts
Financial assets:
Commodity derivative assets – current	11,478		75,506
Derivative assets	2,092		25,449
Total financial assets	13,570		100,955
Financial liabilities:
Derivative liabilities, current	(48,892)		(81,451)
Derivative liabilities, noncurrent	(23,815)		26,789
Derivative Liability	(74,187)		113,540
Fair Value, Measurements, Recurring | Commodity contracts | Level 1
Financial assets:
Commodity derivative assets – current	0		0
Derivative assets	0		0
Total financial assets	0		0
Financial liabilities:
Derivative liabilities, current	0		0
Derivative liabilities, noncurrent	0		0
Derivative Liability	0		0
Fair Value, Measurements, Recurring | Commodity contracts | Level 2
Financial assets:
Commodity derivative assets – current	11,478		75,506
Derivative assets	2,092		25,449
Total financial assets	13,570		100,955
Financial liabilities:
Derivative liabilities, current	(48,892)		(81,451)
Derivative liabilities, noncurrent	(23,815)		26,789
Derivative Liability	(74,187)		113,540
Fair Value, Measurements, Recurring | Commodity contracts | Level 3
Financial assets:
Commodity derivative assets – current	0		0
Derivative assets	0		0
Total financial assets	0		0
Financial liabilities:
Derivative liabilities, current	0		0
Derivative liabilities, noncurrent	0		0
Derivative Liability	0		0
Fair Value, Measurements, Recurring | Interest Rate Swap
Financial liabilities:
Derivative liabilities, current	(1,480)		(3,655)
Derivative liabilities, noncurrent			1,645
Fair Value, Measurements, Recurring | Interest Rate Swap | Level 1
Financial liabilities:
Derivative liabilities, current	0		0
Derivative liabilities, noncurrent			0
Fair Value, Measurements, Recurring | Interest Rate Swap | Level 2
Financial liabilities:
Derivative liabilities, current	(1,480)		(3,655)
Derivative liabilities, noncurrent			1,645
Fair Value, Measurements, Recurring | Interest Rate Swap | Level 3
Financial liabilities:
Derivative liabilities, current	0		0
Derivative liabilities, noncurrent			0
Senior Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Gross	$ 400,000		$ 0
Senior Notes | Senior Notes Due 2026
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Interest rate		9.25%

Significant Commitments by Cate

Significant Commitments by Category (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)
Commitments and Contingencies Disclosure [Line Items]
Number of drilling rigs	2
Commitments
Commitment length	5 years
Estimated Litigation Liability, Current	$ 100
Gathering and Intermediate Transportation Commitments
Commitments
2020	13,937
2021	13,937
2022	13,976
2023	13,937
2024	7,794
Thereafter	15,808
Total	79,389
Other Commitments
Commitments
2020	380
2021	143
2022	56
2023	0
2024	0
Thereafter	0
Total	$ 579

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2021USD ($)bbl	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Commitments and Contingencies Disclosure [Line Items]
Commitment length	5 years
Number of drilling rigs	2
Estimated Litigation Liability, Current | $	$ 100,000
Asset retirement obligations | $	8,413,000	$ 5,461,000	$ 4,934,000
Unrecorded Unconditional Purchase Obligation, Purchases | $	36,000,000
Unrecorded Unconditional Purchase Obligation, Change of Amount as Result of Variable Components | $	$ 90
Field gathering agreement [Member]
Commitments and Contingencies Disclosure [Line Items]
Minimum commitment	8,000
Intermediate pipeline transportation services [Member]
Commitments and Contingencies Disclosure [Line Items]
Minimum commitment	8,000
Nuevo Dos Gathering and Transportation, LLC [Member] | Crude Oil Storage Capacity [Member]
Commitments and Contingencies Disclosure [Line Items]
Minimum commitment	180,000
Nuevo Dos Gathering and Transportation, LLC [Member] | Crude Oil Storage Capacity With Downstream Interstate Pipeline [Member]
Commitments and Contingencies Disclosure [Line Items]
Minimum commitment	90,000
Nuevo Dos Gathering and Transportation, LLC [Member] | Tank Capacity [Member]
Commitments and Contingencies Disclosure [Line Items]
Minimum commitment	70,000
South Texas Region | Crude Oil Storage Capacity [Member]
Commitments and Contingencies Disclosure [Line Items]
Minimum commitment	340,000
Nuevo Dos Gathering and Transportation, LLC-Marketing Affiliate [Member] | Crude Oil Storage Capacity With Downstream Interstate Pipeline [Member]
Commitments and Contingencies Disclosure [Line Items]
Minimum commitment	62,000
Nuevo Dos Gathering and Transportation, LLC-Marketing Affiliate [Member] | Additional Crude Oil Storage Capacity With Downstream Interstate Pipeline
Commitments and Contingencies Disclosure [Line Items]
Minimum commitment	120,000
Gonzales, Lavaca and Fayette Counties, Texas | Field gathering agreement [Member]
Commitments and Contingencies Disclosure [Line Items]
Minimum commitment	20,000
Gonzales, Lavaca and Fayette Counties, Texas | Intermediate pipeline transportation services [Member]
Commitments and Contingencies Disclosure [Line Items]
Minimum commitment	20,000
Gathering and Intermediate Transportation Commitments
Commitments and Contingencies Disclosure [Line Items]
Contractual Commitments Future Minimum Payments Due | $	$ 79,389,000
Contractual Commitments Future Minimum Payments Due Current | $	$ 13,937,000

Contractual Arrangements (Detai

Contractual Arrangements (Details)	12 Months Ended
	Dec. 31, 2021bbl
Field gathering agreement [Member]
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Minimum commitment	8,000
Intermediate pipeline transportation services [Member]
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Minimum commitment	8,000
Volume capacity support [Member]
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Minimum commitment	8,000

Shareholders' Equity - Addition

Shareholders' Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	Oct. 06, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Oct. 05, 2021	Aug. 10, 2021	Jan. 15, 2021
Class of Stock [Line Items]
Capital Stock, Shares Authorized	145,000,000				115,000,000
Change in pension and postretirement obligations, net of tax		$ 20	$ (72)	$ (141)
Preferred stock, issued (in shares)		0	0
Preferred stock, authorized (in shares)		5,000,000	5,000,000
Accumulated other comprehensive loss		$ (111)	$ (131)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, after Tax		(20)	72	141
Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest		$ 98,938	$ (310,629)	$ 70,448
Preferred stock, par value (in dollars per share)		$ 0.01	$ 0.01				$ 0.01
Common stock, authorized (in shares)					110,000,000
Common stock, par value (in dollars per share)					$ 0.01
Senior Notes Due 2026 | Senior Notes
Class of Stock [Line Items]
Interest rate						9.25%
Preferred Class A
Class of Stock [Line Items]
Preferred stock, shares outstanding	225,489.98
Preferred stock, authorized (in shares)					5,000,000
Preferred stock, par value (in dollars per share)					$ 0.01
Preferred Class B
Class of Stock [Line Items]
Common stock, authorized (in shares)	30,000,000
Common stock, par value (in dollars per share)	$ 0.01
Class B Common Stock
Class of Stock [Line Items]
Common stock, issued (in shares)		22,548,998
Common stock, authorized (in shares)		30,000,000	30,000,000
Common stock, par value (in dollars per share)		$ 0.01	$ 0.01
Class B Common Stock | Common Stock
Class of Stock [Line Items]
Stock Issued During Period, Shares, New Issues	22,548,998

Share-Based Compensation and _3

Share-Based Compensation and Other Benefit Plans - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended		3 Months Ended	4 Months Ended	12 Months Ended
	Aug. 31, 2020	Dec. 31, 2019	Dec. 31, 2021	Dec. 31, 2016	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Payment Arrangement, Accelerated Cost						$ 700	$ 200
Share-based compensation (equity-classified)			$ (10,400)	$ (4,100)	$ (15,589)	(3,284)	(4,082)
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period					3 years
Defined Contribution Plan, Cost					$ 1,000	900	900
Compensation			$ 13,942		13,942	4,222
Officer Severance Costs		$ 500
Executive Transition Costs	$ 1,200
Share-based Payment Arrangement, Expense, Tax Benefit					500	$ 100	$ 100
Lonestar
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation (equity-classified)					(10,400)
Juniper Transaction
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation (equity-classified)					$ (1,900)
Time Vested Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)			762,259		762,259
Performance Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)		15,066	225,206		225,206	145,399	15,066
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized			484,197		484,197
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount			$ 5,000		$ 5,000
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition					1 year 11 months 15 days
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period					225,206
Average grant-date fair value (in dollars per share)					$ 22.44
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition					1 year 10 months 6 days
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount			1,500		$ 1,500
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period					120,262
Average grant-date fair value (in dollars per share)					$ 14.12
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value					$ 3,600	$ 2,800	$ 3,000
Restricted Stock Units (RSUs) | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangements By Share-based Payment Award, Award Amortization Period					1 year
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period					3 years
Performance Shares | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares expected to vest at grant date					0.00%	0.00%	0.00%
Performance Shares | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares expected to vest at grant date					200.00%	200.00%	200.00%
Share-based Compensation Arrangements By Share-based Payment Award, Award Amortization Period					3 years
Share-based Payment Arrangement, Tranche One | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Average grant-date fair value (in dollars per share)							$ 34.02
Share-based Payment Arrangement, Tranche One | Performance Shares | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Average grant-date fair value (in dollars per share)					$ 17.74	$ 2.40
Share-based Payment Arrangement, Tranche One | Performance Shares | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Average grant-date fair value (in dollars per share)					$ 33.31	$ 16.02
Other Pension, Postretirement and Supplemental Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)					$ 100	$ 100	$ 100
Liability, Defined Benefit Plan, Noncurrent		$ 1,100	1,100		$ 1,100	1,300	$ 1,100
Pension Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay					6.00%
Compensation			$ 300		$ 300	$ 200
Employees and Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)			4,424,600		4,424,600

Share-Based Compensation and _4

Share-Based Compensation and Other Benefit Plans (Detail) - USD ($) $ in Thousands	3 Months Ended	4 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2016	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Payment Arrangement, Accelerated Cost				$ 700	$ 200
Defined Contribution Plan, Cost			$ 1,000	900	900
Share-based compensation	$ 10,400	$ 4,100	15,589	$ 3,284	$ 4,082
Restricted Stock Units (RSUs)
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount	1,500		$ 1,500
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period			120,262
Stock Options
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition			1 year 10 months 6 days
Performance Restricted Stock Units
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount	$ 5,000		$ 5,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period			225,206
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Period for Recognition			1 year 11 months 15 days
Granted (in shares)	225,206		225,206	145,399	15,066
Other Pension, Postretirement and Supplemental Plans [Member]
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Liability, Defined Benefit Plan, Noncurrent	$ 1,100		$ 1,100	$ 1,300	$ 1,100
Pension and Other Postretirement Benefits Cost (Reversal of Cost)			$ 100	$ 100	$ 100

Share-Based Compensation and _5

Share-Based Compensation and Other Benefit Plans - Fair Value of Each Award Estimated on Date of Grant Using Black-Scholes-Merton Option-Pricing Formula (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Performance Restricted Stock Units
Schedule of Benefit Obligations Weighted Average Assumptions [Line Items]
Expected volatility, min	131.74%	101.32%
Expected volatility, max	134.74%	117.71%
Expected volatility			49.90%
Dividend yield	0.00%	0.00%	0.00%
Risk-free interest rate, min	0.22%	0.18%
Risk-free interest rate, max	0.29%	0.51%
Risk-free interest rate			1.66%
Average grant-date fair value (in dollars per share)	$ 22.44
Granted (in shares)	225,206	145,399	15,066
Performance Shares | Share-based Payment Arrangement, Tranche One
Schedule of Benefit Obligations Weighted Average Assumptions [Line Items]
Average grant-date fair value (in dollars per share)			$ 34.02
Performance Shares | Share-based Payment Arrangement, Tranche One | Minimum
Schedule of Benefit Obligations Weighted Average Assumptions [Line Items]
Average grant-date fair value (in dollars per share)	$ 17.74	$ 2.40
Performance Shares | Share-based Payment Arrangement, Tranche One | Maximum
Schedule of Benefit Obligations Weighted Average Assumptions [Line Items]
Average grant-date fair value (in dollars per share)	33.31	$ 16.02
ROCE
Schedule of Benefit Obligations Weighted Average Assumptions [Line Items]
Average grant-date fair value (in dollars per share)	$ 13.63

Share-Based Compensation and _6

Share-Based Compensation and Other Benefit Plans - Activity of Awarded Restricted Stock Units (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Restricted Stock Units (RSUs)
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	$ 3.6	$ 2.8	$ 3
Number of shares
Balance at beginning of year (in shares)	319,280
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	120,262
Vested (in shares)	(174,972)
Forfeited (in shares)	(34,053)
Balance at end of year (in shares)	230,517	319,280
Weighted-Average Grant Date Fair Value
Balance at beginning of year (in dollars per share)	$ 13.56
Average grant-date fair value (in dollars per share)	14.12
Vested (in dollars per share)	20.81
Forfeited (in dollars per share)	10.65
Balance at end of year (in dollars per share)	$ 9.20	$ 13.56
Performance Restricted Stock Units
Number of shares
Balance at beginning of year (in shares)	173,532
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	225,206
Vested (in shares)	(9,816)
Forfeited (in shares)	(43,853)
Balance at end of year (in shares)	345,069	173,532
Weighted-Average Grant Date Fair Value
Balance at beginning of year (in dollars per share)	$ 13.68
Average grant-date fair value (in dollars per share)	22.44
Vested (in dollars per share)	26.60
Forfeited (in dollars per share)	14.90
Balance at end of year (in dollars per share)	$ 16.20	$ 13.68
Dividend yield	0.00%	0.00%	0.00%
Risk-free interest rate, max	0.29%	0.51%
Risk-free interest rate, min	0.22%	0.18%
Expected volatility, min	131.74%	101.32%
Expected volatility, max	134.74%	117.71%
Performance Shares | Share-based Payment Arrangement, Tranche One
Weighted-Average Grant Date Fair Value
Average grant-date fair value (in dollars per share)			$ 34.02
Minimum | Performance Shares
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares, Expected to Vest, Percentage	0.00%	0.00%	0.00%
Minimum | Performance Shares | Share-based Payment Arrangement, Tranche One
Weighted-Average Grant Date Fair Value
Average grant-date fair value (in dollars per share)	$ 17.74	$ 2.40
Maximum | Performance Shares
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares, Expected to Vest, Percentage	200.00%	200.00%	200.00%
Maximum | Performance Shares | Share-based Payment Arrangement, Tranche One
Weighted-Average Grant Date Fair Value
Average grant-date fair value (in dollars per share)	$ 33.31	$ 16.02

Components of Calculation of Ba

Components of Calculation of Basic and Diluted Earnings Per Share (Detail) - USD ($) shares in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net loss attributable to common shareholders		$ 40,229,000	$ (310,557,000)	$ 70,589,000
Weighted-average shares – basic		16,695	15,176	15,110
Weighted average shares outstanding – diluted		17,165	15,176	15,126
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		22,500	100
Net income (loss)		$ 98,918,000	$ (310,557,000)	$ 70,589,000
Net income attributable to Noncontrolling interest		(58,689,000)	0	0
Net Income (Loss) Available to Common Stockholders, Diluted		$ 98,918,000	$ (310,557,000)	$ 70,589,000
Incremental Common Shares Attributable to Dilutive Effect of Conversion of Preferred Stock		0	0	0
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements	[1]	470	0	16
Change in Ownership of Consolidated Subsidiaries
Change in ownership related to the Lonestar Acquisition		$ (40,000)
Additional Paid-in Capital [Member]
Change in Ownership of Consolidated Subsidiaries
Change in ownership related to the Lonestar Acquisition		57,604,000
Additional Paid-in Capital [Member] | Juniper Transactions
Change in Ownership of Consolidated Subsidiaries
Change in ownership related to the Lonestar Acquisition		57,600,000
Additional Paid-in Capital [Member] | Lonestar
Change in Ownership of Consolidated Subsidiaries
Change in ownership related to the Lonestar Acquisition		(57,600,000)
Subsidiaries [Member]
Change in Ownership of Consolidated Subsidiaries
Net Income (Loss) Attributable to Parent		40,229,000	$ (310,557,000)	$ 70,589,000
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Change Due to Net Income Attributable to Parent and Effects of Changes, Net		$ (17,375,000)	$ (310,557,000)	$ 70,589,000
[1]