Ranger Oil (ROCC) 10-Q 9 May 23 2023 Q1 Quarterly report Financial data

Cover

Cover - shares	3 Months Ended
	Mar. 31, 2023	May 03, 2023
Document Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2023
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
Entity Address, Address Line Two	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 Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q1
Entity Central Index Key	0000077159
Current Fiscal Year End Date	--12-31
Common Class A
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		19,008,710
Common Class B
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		22,548,998

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – UNAUDITED - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Revenues
Total revenues and other	$ 258,148	$ 256,455
Operating expenses
Lease operating	29,990	18,102
Gathering, processing and transportation	10,180	9,040
Production and ad valorem taxes	16,042	13,140
General and administrative	12,668	9,779
Depreciation, depletion and amortization	85,303	50,893
Total operating expenses	154,183	100,954
Operating income	103,965	155,501
Other income (expense)
Interest expense, net of amounts capitalized	(14,718)	(10,697)
Gain on extinguishment of debt	0	2,157
Derivative gains (losses)	25,658	(167,887)
Other, net	(123)	76
Income (loss) before income taxes	114,782	(20,850)
Income tax (expense) benefit	(991)	189
Net income (loss)	113,791	(20,661)
Net (income) loss attributable to Noncontrolling interest	(61,792)	10,676
Net income (loss) attributable to Class A common shareholders	$ 51,999	$ (9,985)
Net income (loss) per share attributable to Class A common shareholders:
Basic (in dollars per share)	$ 2.74	$ (0.47)
Diluted (in dollars per share)	$ 2.67	$ (0.47)
Weighted average shares outstanding – basic (in shares)	18,975	21,107
Weighted average shares outstanding – diluted (in shares)	19,623	21,107
Crude oil
Revenues
Revenues	$ 236,932	$ 226,732
Natural gas liquids
Revenues
Revenues	12,154	16,740
Natural gas
Revenues
Revenues	8,345	12,127
Other operating income, net
Revenues
Revenues	$ 717	$ 856

CONDENSED CONSOLIDATED STATEM_2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) – UNAUDITED - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2023	Mar. 31, 2022
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ 113,791	$ (20,661)
Other comprehensive income (loss):
Change in pension and postretirement obligations, net of tax	[1]	32	0
Comprehensive income (loss)		113,823	(20,661)
Net (income) loss attributable to Noncontrolling interest		(61,792)	10,676
Other comprehensive income attributable to Noncontrolling interest	[1]	(17)	0
Comprehensive income (loss) attributable to Class A common shareholders		$ 52,014	$ (9,985)
[1]The amounts for 2022 are minimal and round down to zero

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS – UNAUDITED - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022
Current assets
Cash and cash equivalents	$ 12,354	$ 7,592
Accounts receivable, net of allowance for credit losses	138,546	139,715
Derivative assets	23,756	29,714
Prepaid and other current assets	18,460	22,264
Assets held for sale	1,186	1,186
Total current assets	194,302	200,471
Property and equipment, net	1,874,836	1,809,000
Derivative assets	216	316
Other assets	17,278	4,420
Total assets	2,086,632	2,014,207
Current liabilities
Accounts payable and accrued liabilities	239,792	265,609
Derivative liabilities	32,286	67,933
Total current liabilities	272,078	333,542
Deferred income taxes	7,022	6,216
Derivative liabilities	1,320	3,416
Other non-current liabilities	13,131	9,934
Long-term debt, net	629,480	604,077
Commitments and contingencies (Note 11)
Equity
Preferred stock of $0.01 par value – 5,000,000 shares authorized; none issued as of March 31, 2023 and December 31, 2022	0	0
Paid-in capital	216,941	220,062
Retained earnings	314,801	264,256
Accumulated other comprehensive loss	(96)	(111)
Ranger Oil shareholders’ equity	531,838	484,399
Noncontrolling interest	631,763	572,623
Total equity	1,163,601	1,057,022
Total liabilities and equity	2,086,632	2,014,207
Common Class A
Equity
Common stock	190	190
Common Class B
Equity
Common stock	$ 2	$ 2

CONDENSED CONSOLIDATED BALANC_2

CONDENSED CONSOLIDATED BALANCE SHEETS – UNAUDITED (Parenthetical) - $ / shares	Mar. 31, 2023	Dec. 31, 2022
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized (in shares)	5,000,000	5,000,000
Preferred stock, issued (in shares)	0	0
Common Class A
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, authorized (in shares)	110,000,000	110,000,000
Common stock, issued (in shares)	18,982,425	19,074,864
Common stock, outstanding (in shares)	18,982,425	19,074,864
Common Class B
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	22,548,998
Common stock, outstanding (in shares)	22,548,998	22,548,998

CONDENSED CONSOLIDATED STATEM_3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – UNAUDITED - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Cash flows from operating activities
Net income (loss)	$ 113,791	$ (20,661)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Gain on extinguishment of debt	0	(2,157)
Depreciation, depletion and amortization	85,303	50,893
Derivative contracts:
Net (gains) losses	(25,658)	167,887
Cash settlements and premiums paid, net	(7,358)	(29,408)
Deferred income tax expense (benefit)	806	(721)
Non-cash interest expense	933	800
Share-based compensation	2,051	924
Other, net	349	(182)
Changes in operating assets and liabilities, net	(9,968)	(33,540)
Net cash provided by operating activities	160,249	133,835
Cash flows from investing activities
Capital expenditures	(171,464)	(71,173)
Proceeds from sales of assets and other, net	447	656
Net cash used in investing activities	(171,017)	(70,517)
Cash flows from financing activities
Proceeds from credit facility borrowings	156,000	50,000
Repayments of credit facility borrowings	(131,000)	(130,000)
Repayments of acquired and other debt	(238)	(83)
Payments for share repurchases	(4,816)	0
Distributions to Noncontrolling interest	(1,691)	0
Dividends paid	(1,438)	0
Withholding taxes for share-based compensation	(1,287)	(445)
Debt issuance costs paid	0	(113)
Net cash provided by (used in) financing activities	15,530	(80,641)
Net increase (decrease) in cash and cash equivalents	4,762	(17,323)
Cash and cash equivalents – beginning of period	7,592	23,681
Cash and cash equivalents – end of period	12,354	6,358
Cash paid for:
Interest, net of amounts capitalized	22,997	20,214
Non-cash investing and financing activities:
Changes in accrued liabilities related to capital expenditures	(22,408)	9,361
ROU assets obtained in exchange for lease obligations:
Operating leases	$ 15,865	$ 0

CONDENSED CONSOLIDATED STATEM_4

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - UNAUDITED - USD ($) $ in Thousands		Total	Common Class A	Common Class B	Preferred Stock	Common Stock Common Class A	Common Stock Common Class B	Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Loss	Noncontrolling Interest
Balance at beginning of period (in shares) at Dec. 31, 2021					0
Balance at beginning of period (in shares) at Dec. 31, 2021						21,090,000	22,549,000
Balance at beginning of period at Dec. 31, 2021		$ 669,508			$ 0	$ 729	$ 2	$ 273,329	$ 49,583	$ (111)	$ 345,976
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		(20,661)							(9,985)		(10,676)
Common stock issued related to share-based compensation and other, net (in shares)	[1]					56,000
Common stock issued related to share-based compensation and other, net	[1]	478						478
Balance at end of period (in shares) at Mar. 31, 2022					0
Balance at end of period (in shares) at Mar. 31, 2022						21,146,000	22,549,000
Balance at end of period at Mar. 31, 2022		649,325			$ 0	$ 729	$ 2	273,807	39,598	(111)	335,300
Balance at beginning of period (in shares) at Dec. 31, 2022					0
Balance at beginning of period (in shares) at Dec. 31, 2022			19,074,864	22,548,998		19,075,000	22,549,000
Balance at beginning of period at Dec. 31, 2022		1,057,022			$ 0	$ 190	$ 2	220,062	264,256	(111)	572,623
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		113,791							51,999		61,792
Repurchase of Class A Common Stock (in shares)						(122,000)
Repurchase of Class A Common Stock		(4,864)				$ (1)		(4,863)
Change in ownership, net		0						978			(978)
Distributions to Noncontrolling interest		(1,691)									(1,691)
Dividends declared ($0.075 per share of Class A common stock)		(1,454)	$ (3,100)						(1,454)
Common stock issued related to share-based compensation and other, net (in shares)						29,000
Common stock issued related to share-based compensation and other, net		$ 797				$ 1		764		15	17
Balance at end of period (in shares) at Mar. 31, 2023		0			0
Balance at end of period (in shares) at Mar. 31, 2023			18,982,425	22,548,998		18,982,000	22,549,000
Balance at end of period at Mar. 31, 2023		$ 1,163,601			$ 0	$ 190	$ 2	$ 216,941	$ 314,801	$ (96)	$ 631,763
[1]Includes equity-classified share-based compensation of $0.9 million during the three months ended March 31, 2022. During the three months ended March 31, 2022, 55,971 of Class A Common Stock were issued in connection with the vesting of certain RSUs, net of shares withheld for income taxes. No shares of Class A Common Stock were issued in connection with the vesting of PRSUs during the three months ended March 31, 2022.

CONDENSED CONSOLIDATED STATEM_5

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - UNAUDITED (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Cash dividend declared (in dollars per share)	$ 0.075
Share-based compensation	$ 2,051	$ 924
Common Class A
Common stock, par value (in dollars per share)	$ 0.01
Performance-Based Restricted Stock Units and Restricted Stock Units (RSUs) | Common Class A
Stock issued during period (in shares)	29,418
Common stock, par value (in dollars per share)	$ 0.01
Restricted Stock Units (RSUs) | Common Class A
Stock issued during period (in shares)		55,971
Performance-Based Restricted Stock Units | Common Class A
Stock issued during period (in shares)		0

Organization and Description of

Organization and Description of Business	3 Months Ended
	Mar. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Description of Business	Note 1 – Organization and Description of Business 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. Juniper Capital Advisors, L.P. (“Juniper Capital”), through its affiliates, JSTX Holdings, LLC (“JSTX”) and Rocky Creek Resources, LLC (“Rocky Creek” and together with JSTX and Juniper Capital, “Juniper”), beneficially owned as of March 31, 2023 an approximate 54% equity interest in the Company through its ownership of 22,548,998 shares of our Class B common stock, par value of $0.01 per share (“Class B Common Stock”) and 22,548,998 common units (the “Common Units”) in our Up-C partnership subsidiary, ROCC Energy Holdings, L.P. (the “Partnership”). See Note 2 for further information.

Basis of Presentation and Signi

Basis of Presentation and Significant Accounting Policies	3 Months Ended
	Mar. 31, 2023
Accounting Policies [Abstract]
Basis of Presentation and Significant Accounting Policies	Note 2 – Basis of Presentation and Significant Accounting Policies Basis of Presentation Our unaudited condensed consolidated financial statements include the accounts of Ranger Oil and all of our subsidiaries as of the relevant dates. Intercompany balances and transactions have been eliminated. A substantial noncontrolling interest in our subsidiaries is provided for in our condensed consolidated statements of operations and comprehensive income (loss) and our condensed consolidated balance sheets for the periods presented. Our condensed 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 Exchange Commission (the “SEC”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments considered necessary for a fair presentation of our condensed consolidated financial statements have been included. Our condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2022 (“2022 Annual Report”). Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. Principles of Consolidation Ranger Oil is organized as an Up-C structure whereby Juniper owns all of the shares of the Company’s Class B Common Stock which are non-economic voting only shares of the Company. Juniper’s economic interest in the Company is held through its ownership of limited partner interests, the Common Units, in the Partnership. Pursuant to the amended and restated limited partnership agreement of the Partnership (the “Partnership Agreement”), the Company’s ownership of Common Units in the Partnership at all times equals the number of shares of the Company’s Class A Common Stock then outstanding, and Juniper’s ownership of Common Units in the Partnership at all times equals the number of shares of Class B Common Stock then outstanding. The Partnership was formed for the purpose of executing the Company’s reorganization with Juniper into an Up-C structure. The Partnership, through its subsidiaries, owns, operates, and manages oil and gas properties in Texas and manages the Company’s outstanding debt and derivative instruments. The Company’s wholly-owned subsidiary, ROCC Energy Holdings GP LLC (the “GP”), is the general partner of the Partnership. Subsidiaries of the Partnership own and operate all our oil and gas assets. Ranger Oil and the Partnership are holding companies with no other operations, material cash flows, or material assets or liabilities other than the equity interests in their subsidiaries. The Common Units are redeemable (concurrently with the cancellation of an equivalent number of shares of Class B Common Stock) by Juniper at any time on a one-for-one basis in exchange for shares of Class A Common Stock or, if the Partnership elects, cash based on the 5-day average volume-weighted closing price for the Class A Common Stock immediately prior to the redemption. In determining whether to make a cash election, the Company would consider the interests of the holders of the Class A Common Stock, the Company’s financial condition, results of operations, earnings, projections, liquidity and capital requirements, management’s assessment of the intrinsic value of the Class A Common Stock, the trading price of the Class A Common Stock, legal requirements, covenant compliance, restrictions in the Company’s debt agreements and other factors it deems relevant. The Partnership is considered a variable interest entity for which the Company is the primary beneficiary. The Company has benefits in the Partnership through the Common Units, and it has power over the activities most significant to the Partnership’s economic performance through its 100% controlling interest in the GP (which, accordingly, is acting as an agent on behalf of the Company). This conclusion was based on a qualitative analysis that considered the Partnership’s governance structure and the GP’s control over operations of the Partnership. The GP manages the business and affairs of the Partnership, including key Partnership decision-making, and the limited partners do not possess any substantive participating or kick-out rights that would allow Juniper to block or participate in certain operational and financial decisions that most significantly impact the Partnership’s economic performance or that would remove the GP. As such, because the Company has both power and benefits in the Partnership, the Company determined it is the primary beneficiary of the Partnership and consolidates the Partnership in the Company’s condensed consolidated financial statements. The Company reflects a noncontrolling interest in the condensed consolidated financial statements based on the proportion of Common Units owned by Juniper relative to the total number of Common Units outstanding. The noncontrolling interest is presented as a component of equity in the accompanying condensed consolidated financial statements and represents the ownership interest held by Juniper in the Partnership (the “Noncontrolling interest”). Noncontrolling Interest The noncontrolling interest percentage may be affected by the issuance of shares of Class A Common Stock, repurchases or cancellation of Class A Common Stock, the exchange of Class B Common Stock and the redemption of Common Units (and concurrent cancellation of Class B Common Stock), among other things. The percentage is based on the proportionate number of Common Units held by Juniper relative to the total Common Units outstanding. As of March 31, 2023, the Company owned 18,982,425 Common Units, representing a 45.7% limited partner interest in the Partnership, and Juniper owned 22,548,998 Common Units, representing the remaining 54.3% limited partner interest. As of December 31, 2022, the Company owned 19,074,864 Common Units, representing a 45.8% limited partner interest in the Partnership, and Juniper owned 22,548,998 Common Units, representing the remaining 54.2% limited partner interest. During the three months ended March 31, 2023, changes in the ownership interests were the result of share repurchases and issuances of Class A Common Stock in connection with the vesting of employees’ share-based compensation. See Note 12 for information regarding share repurchases and Note 13 for vesting of share-based compensation. When the Company’s relative ownership interest in the Partnership changes, adjustments to Noncontrolling interest and 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 Accounting Standards Codification 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. Additionally, based on the Partnership Agreement, there are no substantive profit sharing arrangements that would cause distributions to be other than pro rata. Therefore, profits and losses are attributed to the Class A common shareholders and noncontrolling interest pro rata based on ownership interests in the Partnership. Significant Accounting Policies The Company’s significant accounting policies are described in “Note 3 – Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in its 2022 Annual Report and are supplemented by the notes included in this Quarterly Report on Form 10-Q. The financial statements and related notes included in this report should be read in conjunction with the Company’s 2022 Annual Report. 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. Adoption of Recently Issued Accounting Pronouncements Effective January 1, 2023, we adopted 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 if it had originated the contract, rather than at fair value. As required, ASU 2021-08 will be applied prospectively to business combinations occurring on or after December 15, 2022. We adopted this update on January 1, 2023 and it did not have a material impact on our financial statements.

Transactions

Transactions	3 Months Ended
	Mar. 31, 2023
Business Combination and Asset Acquisition [Abstract]
Transactions	Note 3 – Transactions Pending Baytex Merger On February 27, 2023, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Baytex Energy Corp. (“Baytex”) pursuant to which, among other things, the Company will merge with and into a wholly-owned subsidiary of Baytex with the Company surviving the merger as a wholly-owned subsidiary of Baytex (the “Baytex Merger”). Subject to the terms and conditions of the Merger Agreement, each share of our Class A Common Stock issued and outstanding immediately prior to the effective time of the closing of the Baytex Merger (including shares of our Class A Common Stock to be issued in connection with the exchange of the Class B Common Stock and Common Units for Class A Common Stock), will be converted automatically into the right to receive: (i) 7.49 Baytex common shares and (ii) $13.31 in cash. The transaction was unanimously approved by the board of directors of each company and JSTX and Rocky Creek delivered a support agreement to vote their outstanding shares in favor of the Baytex Merger. The Baytex Merger is expected to close in late second quarter or early third quarter of 2023, subject to the satisfaction of customary closing conditions, including the requisite shareholder and regulatory approvals.

Revenue Recognition

Revenue Recognition	3 Months Ended
	Mar. 31, 2023
Receivables [Abstract]
Revenue Recognition	Note 4 – Revenue Recognition Revenue from Contracts with Customers 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 (“CDP”) 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”) in our condensed consolidated statements of operations. 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 in our condensed consolidated statements of operations. We record revenue in the month that our oil and gas production is delivered to our customers. However, 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 sold. 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. 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 contract assets or liabilities. Accounts Receivable from Contracts with Customers 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 60 days. The following table summarizes our accounts receivable by type as of the dates presented: March 31, 2023 December 31, 2022 Customers $ 111,726 $ 109,149 Joint interest partners 26,501 30,730 Derivative settlements from counterparties 1 732 437 Other 132 114 Total 139,091 140,430 Less: Allowance for credit losses (545) (715) Accounts receivable, net of allowance for credit losses $ 138,546 $ 139,715 _______________________

Derivative Instruments

Derivative Instruments	3 Months Ended
	Mar. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Note 5 – 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 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 1 The following table sets forth our commodity derivative positions, presented on a net basis by period of maturity, as of March 31, 2023: 2Q2023 3Q2023 4Q2023 1Q2024 2Q2024 NYMEX WTI Crude Swaps Average Volume Per Day (bbl) 2,400 2,807 2,657 462 462 Weighted Average Swap Price ($/bbl) $ 54.26 $ 54.92 $ 54.93 $ 58.75 $ 58.75 NYMEX WTI Crude Collars Average Volume Per Day (bbl) 23,214 16,304 8,967 Weighted Average Purchased Put Price ($/bbl) $ 67.81 $ 72.50 $ 72.27 Weighted Average Sold Call Price ($/bbl) $ 78.89 $ 88.35 $ 87.57 MEH WTI CMA Crude Differential Swaps Average Volume Per Day (bbl) 13,187 Weighted Average Swap Price ($/bbl) $ 2.03 NYMEX HH Swaps Average Volume Per Day (MMBtu) 7,500 Weighted Average Swap Price ($/MMBtu) $ 3.690 NYMEX HH Collars Average Volume Per Day (MMBtu) 11,538 11,413 11,413 11,538 11,538 Weighted Average Purchased Put Price ($/MMBtu) $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.328 Weighted Average Sold Call Price ($/MMBtu) $ 2.682 $ 2.682 $ 2.682 $ 3.650 $ 3.000 HSC Basis Swaps Average Volume Per Day (MMBtu) 19,038 11,413 11,413 HSC Basis Average Fixed Price ($/MMBtu) $ (0.153) $ (0.153) $ (0.153) HSC Index Swap Average Volume Per Day (MMBtu) 6,319 HSC Index Average Fixed Price ($/MMBtu) $ (0.045) OPIS Mt. Belvieu Ethane Swaps Average Volume per Day (gal) 98,901 34,239 34,239 34,615 Weighted Average Fixed Price ($/gal) $ 0.2288 $ 0.2275 $ 0.2275 $ 0.2275 _______________________ 1 NYMEX WTI refers to New York Mercantile Exchange West Texas Intermediate and MEH refers to Magellan East Houston that serve as benchmarks for crude oil. NYMEX HH refers to NYMEX Henry Hub that serves as the benchmark for natural gas. HSC refers to Houston Ship Channel that serves as another benchmark for natural gas. OPIS Mt. Belvieu refers to Oil Price Information Service Mt. Belvieu that serves as the benchmark for ethane which represents a commodity proxy for NGLs. Interest Rate Derivatives Through May 2022, 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 totaled $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. As of March 31, 2023, we did not have any interest rate derivatives. Financial Statement Impact of Derivatives The impact of our derivative activities on net income (loss) is included within Derivatives gains (losses) on our condensed 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, net of allowance for credit losses (see Note 4) and Accounts payable and accrued liabilities (see Note 9) on the condensed consolidated balance sheets. Adjustments to reconcile net income (loss) to net cash provided by operating activities include derivative gains and losses and cash settlements that are reported under Net (gains) losses and Cash settlements and premiums paid, net, on our condensed consolidated statements of cash flows, respectively. The following table summarizes the effects of our derivative activities for the periods presented: Three Months Ended March 31, 2023 2022 Interest rate swap gains recognized in the condensed consolidated statements of operations $ — $ 83 Commodity gains (losses) recognized in the condensed consolidated statements of operations 25,658 (167,970) $ 25,658 $ (167,887) Interest rate cash settlements recognized in the condensed consolidated statements of cash flows $ — $ (938) Commodity cash settlements and premiums paid recognized in the condensed consolidated statements of cash flows (7,358) (28,470) $ (7,358) $ (29,408) The following table summarizes the fair values of our derivative instruments, which we elect to present on a gross basis, as well as the locations of these instruments on our condensed consolidated balance sheets as of the dates presented: Fair Values March 31, 2023 December 31, 2022 Type Balance Sheet Location Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Commodity contracts Derivative assets/liabilities – current $ 23,756 $ 32,286 $ 29,714 $ 67,933 Commodity contracts Derivative assets/liabilities – non-current 216 1,320 316 3,416 $ 23,972 $ 33,606 $ 30,030 $ 71,349 As of March 31, 2023, we reported net commodity derivative liabilities of $9.6 million. The contracts associated with these positions are with seven counterparties for commodity derivatives, all of which are investment grade financial institutions and are participants in our revolving credit facility (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 10 for information regarding the fair value of our derivative instruments.

Property and Equipment, Net

Property and Equipment, Net	3 Months Ended
	Mar. 31, 2023
Property, Plant and Equipment [Abstract]
Property and Equipment, Net	Note 6 – Property and Equipment, Net The following table summarizes our property and equipment as of the dates presented: March 31, 2023 December 31, 2022 Oil and gas properties (full cost accounting method): Proved $ 3,163,277 $ 3,013,854 Unproved 43,158 41,882 Total oil and gas properties 3,206,435 3,055,736 Other property and equipment 1 31,307 30,969 Total properties and equipment 3,237,742 3,086,705 Accumulated depreciation, depletion, amortization and impairments (1,362,906) (1,277,705) Total property and equipment, net $ 1,874,836 $ 1,809,000 _______________________ 1 As of March 31, 2023 and December 31, 2022, we had $1.2 million classified as Assets held for sale excluded from above. Unproved property costs of $43.2 million and $41.9 million have been excluded from amortization as of March 31, 2023 and December 31, 2022, respectively. We transferred $0.9 million and $0.7 million of unproved leasehold costs, including capitalized interest, associated with proved undeveloped reserves, and acreage unlikely to be drilled or expiring acreage, to the full cost pool during the three months ended March 31, 2023 and 2022, respectively. We capitalized internal costs of $1.6 million and $1.4 million and interest of $0.9 million and $1.1 million during the three months ended March 31, 2023 and 2022, respectively, in accordance with our accounting policies. Average depreciation, depletion and amortization per barrel of oil equivalent of proved oil and gas properties was $19.45 and $14.98 for the three months ended March 31, 2023 and 2022, respectively. Ceiling Test Throughout 2022 and into 2023, commodity prices remained volatile due to supply disruptions resulting from the Russia-Ukraine war and related sanctions that began in first quarter of 2022 as well as shifts in production levels by the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, “OPEC+”). Beginning with an announcement in April 2022 of production cuts which took effect in November 2022, OPEC+ changed its strategy from one which had seen gradually increasing production throughout most of 2022 to cutting production. Then in April 2023, OPEC+ announced a surprise oil output cut of approximately 1.16 million barrels of oil per day (“MMbbl/d”) bringing the total volume cuts by OPEC+ to over 3.66 MMbbl/d until the end of 2023. During 2022 and through the first quarter of 2023, WTI crude oil and natural gas prices ranged from over $120 per barrel (“bbl”) and over $9 per million British thermal units (“MMBtu”), respectively, to lows of approximately $67 per bbl and under $2 per MMBtu, respectively, due to factors discussed above. 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 Ceiling Test utilizes an average of commodity prices based on the closing prices on the first day of each month for the previous 12 months. We did not record any impairments of our oil and gas properties during the three months ended March 31, 2023 or 2022.

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2023
Debt Disclosure [Abstract]
Long-Term Debt	Note 7 – Long-Term Debt The following table summarizes our debt obligations as of the dates presented: March 31, 2023 December 31, 2022 Credit Facility $ 240,000 $ 215,000 9.25% Senior Notes due 2026 400,000 400,000 Other — 238 Total 640,000 615,238 Less: Unamortized discount ¹ (2,878) (3,055) Less: Unamortized deferred issuance costs 1, 2 (7,642) (8,106) Long-term debt $ 629,480 $ 604,077 _______________________ ¹ 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. ² Excludes issuance costs associated with the Credit Facility, which represents costs attributable to the access to credit over its contractual term, that have been presented as a component of Other assets (see Note 9) and are being amortized over the term of the Credit Facility using the straight-line method. Credit Facility As of March 31, 2023, the Credit Facility had a $1.0 billion revolving commitment and a $950 million borrowing base with aggregate elected commitments of $500 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. 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 term Secured Overnight Financing Rate (“SOFR”) reference rate, 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 March 31, 2023, we were in compliance with all debt covenants under the Credit Facility. We had $240.0 million in outstanding borrowings and $1.0 million in outstanding letters of credit under the Credit Facility as of March 31, 2023. Factoring in the outstanding letters of credit, we had $259.0 million of availability under the Credit Facility as of March 31, 2023. During the three months ended March 31, 2022, we incurred and capitalized approximately $0.4 million of issue costs associated with amendments to the Credit Facility. We did not incur any issue costs associated with the Credit Facility during the three months ended March 31, 2023. 9.25% Senior Notes due 2026 On August 10, 2021, our indirect, wholly-owned subsidiary 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. Obligations under the 9.25% Senior Notes due 2026 were assumed by ROCC Holdings, LLC (formerly, Penn Virginia Holdings, LLC, hereinafter referred to as “Holdings”), as borrower, and are guaranteed by the subsidiaries of Holdings that guarantee the Credit Facility. Interest on the 9.25% Senior Notes due 2026 is payable semi-annually in arrears on February 15 and August 15 of each year. We may redeem the 9.25% Senior Notes due 2026 at any time in whole or in part from time to time at specified redemption prices. 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. As of March 31, 2023, we were in compliance with all debt covenants under the Indenture. Other Debt During the three months ended March 31, 2023, we settled $0.2 million of other debt. During the three months ended March 31, 2022, $2.2 million of other debt was extinguished and recorded as a gain on extinguishment of debt.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2023
Income Tax Disclosure [Abstract]
Income Taxes	Note 8 – Income Taxes The income tax provision resulted in an expense of $1.0 million for the three months ended March 31, 2023. The federal portion was fully offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of 0.9%, which is fully attributable to the State of Texas. Our net deferred income tax liability balance of $7.0 million as of March 31, 2023 is also fully attributable to the State of Texas and primarily related to property. The income tax provision resulted in a benefit of $0.2 million for the three months ended March 31, 2022. The federal portion was fully offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of 0.9%, which was fully attributable to the State of Texas. We had no liability for unrecognized tax benefits as of March 31, 2023 and December 31, 2022. There were no interest and penalty charges recognized during the three months ended March 31, 2023 and 2022. Tax years from 2018 forward remain open to examination by the major taxing jurisdictions to which the Company is subject; however, net operating losses originating in prior years are subject to examination when utilized.

Supplemental Balance Sheet Deta

Supplemental Balance Sheet Detail	3 Months Ended
	Mar. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Supplemental Balance Sheet Detail	Note 9 – Supplemental Balance Sheet Detail The following table summarizes components of selected balance sheet accounts as of the dates presented: March 31, 2023 December 31, 2022 Prepaid and other current assets: Inventories 1 $ 16,305 $ 19,341 Prepaid expenses 2 2,155 2,923 $ 18,460 $ 22,264 Other assets: Deferred issuance costs of the Credit Facility, net of amortization $ 2,926 $ 3,218 Right-of-use assets – operating leases 3 14,197 989 Other 155 213 $ 17,278 $ 4,420 Accounts payable and accrued liabilities: Trade accounts payable $ 50,366 $ 58,592 Drilling and other lease operating costs 50,318 62,842 Revenue and royalties payable 101,418 104,512 Production, ad valorem and other taxes 11,764 10,547 Derivative settlements to counterparties 3,074 4,109 Compensation and benefits 3,197 6,927 Interest 5,432 14,655 Current operating lease obligations 3 11,043 907 Other 3,180 2,518 $ 239,792 $ 265,609 Other non-current liabilities: Asset retirement obligations $ 8,960 $ 8,849 Non-current operating lease obligations 3 3,373 200 Postretirement benefit plan obligations 798 885 $ 13,131 $ 9,934 _______________________ 1 Includes tubular inventory and well materials of $15.7 million and $18.7 million as of March 31, 2023 and December 31, 2022, respectively, and crude oil volumes in storage of $0.6 million as of both March 31, 2023 and December 31, 2022. 2 The balances as of March 31, 2023 and December 31, 2022 include $0.5 million in each period for the prepayment of drilling and completion materials and services. 3 The balances as of March 31, 2023 primarily relate to an amended drilling rig lease contract.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2023
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 10 – Fair Value Measurements We apply the authoritative accounting provisions included in GAAP for measuring the 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. Our financial instruments, including cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to their short-term maturities. As of March 31, 2023 and December 31, 2022, the carrying values of the borrowings outstanding under our Credit Facility 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 March 31, 2023, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $640.0 million and $661.5 million, respectively. As of December 31, 2022, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $615.2 million and $616.4 million, respectively. Recurring Fair Value Measurements The fair values of our derivative instruments are measured at fair value on a recurring basis on our condensed consolidated balance sheets. The following tables summarize the valuation of those assets and liabilities as of the dates presented: As of March 31, 2023 Level 1 Level 2 Level 3 Total Financial assets: Commodity derivative assets – current $ — $ 23,756 $ — $ 23,756 Commodity derivative assets – non-current — 216 — 216 Total financial assets $ — $ 23,972 $ — $ 23,972 Financial liabilities: Commodity derivative liabilities – current $ — $ 32,286 $ — $ 32,286 Commodity derivative liabilities – non-current — 1,320 — 1,320 Total financial liabilities $ — $ 33,606 $ — $ 33,606 As of December 31, 2022 Level 1 Level 2 Level 3 Total Financial assets: Commodity derivative assets – current $ — $ 29,714 $ — $ 29,714 Commodity derivative assets – non-current — 316 — 316 Total financial assets $ — $ 30,030 $ — $ 30,030 Financial liabilities: Commodity derivative liabilities – current $ — $ 67,933 $ — $ 67,933 Commodity derivative liabilities – non-current — 3,416 — 3,416 Total financial liabilities $ — $ 71,349 $ — $ 71,349 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 and MEH crude oil, NYMEX HH natural gas, HSC natural gas and OPIS Mt. Belvieu 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 determined the fair values of our interest rate swaps using an income approach valuation technique which discounts future cash flows back to a single present value. We estimated the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these was a Level 2 input. All interest rate swaps matured in May 2022, and as of March 31, 2023, we had not entered into any new interest rate derivative instruments. 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 5 for additional details on our derivative instruments. Non-Recurring Fair Value Measurements The most significant non-recurring fair value measurements utilized in the preparation of our condensed consolidated financial statements are those attributable to the initial determination of asset retirement obligations (“AROs”) associated with the ongoing development of new oil and gas properties. 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	3 Months Ended
	Mar. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 11 – Commitments and Contingencies Drilling and Completion Commitments As of March 31, 2023, we had contracts for two drilling rigs with remaining terms of less than two years. 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 intrastate pipeline transportation. The following table provides details on these contractual arrangements as of March 31, 2023: Description of contractual arrangement Expiration Gross Minimum Volume Expiration of MVC 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 and Fayette 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. During the 12-month period ended March 31, 2023 and excluding the potential impact of the effects of price escalation from commodity price changes, if any, the minimum fee requirements attributable to the MVC under the gathering, transportation and marketing agreements are as follows: $10.5 million for the remainder of 2023, approximately $13.9 million per year for 2024 through 2025, $7.8 million for 2026, $3.8 million per year for 2027 through 2030 and $0.6 million for 2031. During the three months ended March 31, 2023 and 2022, we delivered more than the required 20,000 gross barrels of oil per day and recorded total expense of $10.0 million and $10.2 million, respectively, for contractual fees in connection with these arrangements. Crude Oil Storage As of March 31, 2023, we had access to up to approximately 180,000 barrels of dedicated tank capacity for no additional charge at the service provider’s CDP facility, in Lavaca County, Texas through February 2041. In addition, we had access for 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. Costs associated with this monthly agreement are in the form of a monthly fixed rate short-term lease and are charged as incurred on a monthly basis to GPT in our condensed consolidated statements of operations. Other Agreements We have a long-term dedication of certain specific leases under a crude purchase and throughput terminal agreement through 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 with a 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 agreement that extends into 2029. Legal, Environmental Compliance and Other 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 March 31, 2023 and December 31, 2022, we had an estimated reserve of approximately $0.1 million for certain claims made against us regarding previously divested operations included in Accounts payable and accrued liabilities on our condensed consolidated balance sheets. As of March 31, 2023 and December 31, 2022, we had AROs of approximately $9.0 million and $8.8 million, respectively, attributable to the plugging of abandoned wells. Additionally, we have entered into certain contractual arrangements for other products and services and have commitments under information technology licensing and service agreements, among others.

Shareholders' Equity

Shareholders' Equity	3 Months Ended
	Mar. 31, 2023
Equity [Abstract]
Shareholders' Equity	Note 12 – Shareholders’ Equity Capital Stock As of March 31, 2023, the Company had two classes of common stock: Class A Common Stock and Class B Common Stock. The holders of record of Class A Common Stock and Class B Common Stock vote together as a single class on all matters on which holders of Class A Common Stock and Class B Common Stock are entitled to vote; except that certain directors are elected by holders of a majority of the shares of Class B Common Stock voting as a separate class. The holders of Class A Common Stock have no preemptive rights to purchase shares of Class A Common Stock. Shares of Class A Common Stock are not subject to any redemption or sinking fund provisions and are not convertible into any of the Company’s other securities. In the event of the Company’s voluntary or involuntary liquidation, dissolution or winding up, holders of Class A Common Stock will share equally in the assets remaining after it pays its creditors and preferred shareholders. Holders of Class A Common Stock are entitled to receive dividends when and if declared by the Board of Directors. Shares of Class B Common Stock are non-economic interests in the Company, and no dividends can be declared or paid on the Class B Common Stock. The holders of Class B Common Stock have no preemptive rights to purchase shares of Class B Common Stock. Shares of Class B common stock are not subject to any redemption or sinking fund provisions. In the event of the Company’s voluntary or involuntary liquidation, dissolution or winding up, after payment or provision for payment of its debts and other liabilities, the holders of Class B Common Stock will be entitled to receive, out of its assets or proceeds thereof available for distribution to our shareholders, before any distribution of such assets or proceeds is made to or set aside for the holders of Class A Common Stock and any other of the Company’s stock ranking junior to the Class B Common Stock as to such distribution, payment in full in an amount equal to $0.01 per share of Class B Common Stock. With the exception of the aforementioned distribution, the holders of shares of Class B Common Stock will not be entitled to receive any of the Company’s assets in the event of its voluntary or involuntary liquidation, dissolution or winding up. The Company’s Class B Common Stock is not convertible into any of the Company’s other securities. However, if a holder exchanges one common unit of the Partnership for one share of the Company’s Class A Common Stock, it must also surrender to the Company a share of its Class B Common Stock for each common unit exchanged. As of March 31, 2023, the Company had (i) 110,000,000 authorized shares of Class A Common Stock and 18,982,425 shares of Class A Common Stock issued and outstanding, (ii) 30,000,000 authorized shares of Class B Common Stock and 22,548,998 shares of Class B Common Stock issued and outstanding, and (iii) 5,000,000 authorized shares of preferred stock, par value $0.01 per share, and no shares of preferred stock issued or outstanding. Dividends On March 3, 2023, the Company’s Board of Directors declared a cash dividend of $0.075 per share of Class A Common Stock. The dividend was paid on March 30, 2023 to holders of record of Class A Common Stock as of the close of business on March 17, 2023. In connection with any dividend, Ranger’s operating subsidiary will also make a corresponding distribution to its common unitholders. During the first quarter of 2023, the dividend to the holders of our Class A Common Stock and distribution to common unitholders totaled $3.1 million in the aggregate. The Company’s Credit Facility and the Indenture have restrictive covenants that limit its ability to pay dividends. See Note 15 for details on dividends declared subsequent to March 31, 2023. Share Repurchase Program On April 13, 2022, our Board of Directors approved a share repurchase program that authorized the Company to repurchase up to $100 million of its outstanding Class A Common Stock. The share repurchase authorization was effective immediately and was valid through March 31, 2023. On July 7, 2022, the Board of Directors authorized an increase in the share repurchase program from $100 million to $140 million and extended the term of the program through June 30, 2023. We do not intend to repurchase additional shares pending closing of the Baytex Merger. During the three months ended March 31, 2023, we repurchased 121,857 shares of our Class A Common Stock at a total cost of $4.8 million and an average purchase price of $39.52. The share repurchases were recorded to Class A common stock and Paid-in capital on our condensed consolidated balance sheets. As of March 31, 2023, the remaining authorized repurchase amount under the share repurchase program was $60.0 million. On August 16, 2022, the Inflation Reduction Act was signed into law and imposes a 1% excise tax on the repurchase of stock by publicly traded U.S. corporations. The excise tax is effective for stock repurchases after December 31, 2022. Based on the total share repurchases during the three months ended March 31, 2023, we recognized less than $0.1 million of additional cost within Paid-in capital associated with the excise tax for these share repurchases. Change in Ownership of Consolidated Subsidiaries The following table summarizes changes in the ownership interest in consolidated subsidiaries during the periods presented: Three Months Ended March 31, 2023 2022 Net income (loss) attributable to Class A common shareholders $ 51,999 $ (9,985) Transfers from the noncontrolling interest, net 1 978 N/A Change from Net income (loss) attributable to Class A common shareholders and net transfers from Noncontrolling interest $ 52,977 $ (9,985) _____________________________________________ 1 The three months ended March 31, 2023 includes a net transfer of $1.0 million from Noncontrolling interest for share repurchases and common stock issuances related to employees’ share-based compensation with a corresponding adjustment to Paid-in capital. This equity adjustment had no impact on earnings other than a resulting increase to the noncontrolling interest proportionate share of net income and a corresponding decrease to the proportionate share of net income attributable to Class A common shareholders. As discussed above and in Note 13, in the three months ended March 31, 2023, we repurchased shares of our Class A Common Stock and issued shares of our Class A Common Stock related to the vesting of employees’ share-based compensation resulting in a change in the proportionate share of Common Units held by the Company relative to Juniper. As such, we recognized an adjustment to the carrying amount of noncontrolling interest and a corresponding adjustment to Class A common shareholders’ equity of $1.0 million for the three months ended March 31, 2023 to reflect the revised ownership percentage of total equity. See Note 2 for further discussion.

Share-Based Compensation and Ot

Share-Based Compensation and Other Benefit Plans	3 Months Ended
	Mar. 31, 2023
Share-Based Payment Arrangement [Abstract]
Share-Based Compensation and Other Benefit Plans	Note 13 – Share-Based Compensation and Other Benefit Plans Share-Based Compensation We reserved 4,424,600 shares of Class A Common Stock for issuance under the Ranger Oil Management Incentive Plan for share-based compensation awards. A total of 820,651 RSUs and 664,414 PRSUs have been granted to employees and directors through March 31, 2023. We recognized expense attributable to the RSUs and PRSUs of $2.1 million and $0.9 million for the three months ended March 31, 2023 and 2022, respectively. We recognize share-based compensation expense as a component of general and administrative (“G&A”) expenses in our condensed consolidated statements of operations. Time-Vested Restricted Stock Units The table below summarizes activity for the three months ended March 31, 2023 with respect to awarded RSUs: Time-Vested Weighted-Average Balance at January 1, 2023 149,871 $ 17.51 Granted 9,078 $ 38.68 Vested (43,015) $ 4.72 Forfeited (1,176) $ 42.81 Balance at March 31, 2023 114,758 $ 23.72 Compensation expense for RSUs is recognized on a straight-line basis over the applicable vesting period, which is generally over a three-year period. As of March 31, 2023, we had $1.6 million of unrecognized compensation cost attributable to RSUs. We expect that cost to be recognized over a weighted-average period of 1.49 years. Performance-Based Restricted Stock Units The table below summarizes activity for the three months ended March 31, 2023 with respect to awarded PRSUs: Performance Restricted Stock Weighted-Average Balance at January 1, 2023 440,100 $ 29.87 Granted — $ — Vested — $ — Forfeited (1,177) $ 58.87 Balance at March 31, 2023 438,923 $ 29.87 Compensation expense for PRSUs with a market condition is being amortized ratably over three years for the 2022 and 2021 grants. For the 2020 and 2019 grants, compensation expense for the PRSUs with a market condition were amortized on a graded-vesting basis. The applicable period for the amortization of compensation ranges from less than one year to three years. Compensation expense for PRSUs with a performance condition is recognized ratably over three years when it is considered probable that the performance condition will be achieved and such grants are expected to vest. PRSUs with a market condition do not allow for the reversal of previously recognized expense, even if the market condition is not achieved and no shares ultimately vest. The 2022 and 2021 PRSU grants contain performance measures of which 50% are based on the Company’s return on average capital employed (“ROCE”) relative to a defined peer group and 50% are 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 2022 and 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. PRSUs granted in 2020 and 2019 vested at 92% of the original grant based on TSR relative to a defined peer group over the three-year performance period. As TSR is deemed a market condition, the grant-date fair value for the 2019, 2020 and a portion of the 2021 and 2022 PRSU grants was derived by using a Monte Carlo model. The table below presents ranges for the assumptions used in the Monte Carlo model for the PRSUs granted in the following periods: 2022 2021 1 2020 1 2019 Expected volatility 134.98% to 138.75% 131.74% to 134.74% 101.32% to 117.71% 49.9 % Dividend yield 0.0 % 0.0 % 0.0 % 0.0 % Risk-free interest rate 2.59 % 0.22% to 0.29% 0.18% to 0.51% 1.66 % Performance period 2022-2024 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. As of March 31, 2023, we had $6.5 million of unrecognized compensation cost attributable to PRSUs. We expect that cost to be recognized over a weighted-average period of 1.49 years. Other Benefit Plans We maintain the Ranger Oil Corporation and Affiliated Companies Employees 401(k) Plan (the “401(k) Plan”), a defined contribution plan, which covers substantially all of our employees. We recognized expense attributable to the 401(k) Plan of $0.3 million for the three months ended March 31, 2023 and $0.2 million for the three months ended March 31, 2022. The charges for the 401(k) Plan are included as a component of G&A expenses in our condensed consolidated statements of operations. We maintain unqualified legacy defined benefit pension and defined benefit postretirement plans that cover a limited number 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 of the three months ended March 31, 2023 and 2022, and is included as a component of Other, net in our condensed consolidated statements of operations.

Earnings Per Share

Earnings Per Share	3 Months Ended
	Mar. 31, 2023
Earnings Per Share [Abstract]
Earnings Per Share	Note 14 – Earnings Per Share Basic net earnings (loss) per share is calculated by dividing the net income (loss) available to Class A common shareholders, excluding net income or loss attributable to Noncontrolling interest, 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 (and shares of Class B Common Stock) held by the Noncontrolling interest in the Partnership are exchanged for common shares. Accordingly, our reported net income (loss) attributable to Class A common shareholders is adjusted due to the elimination of the Noncontrolling interest assuming exchange of the Common Units (and shares of Class B Common Stock) held by the Noncontrolling interest. The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings (loss) per share for the periods presented: Three Months Ended March 31, 2023 2022 Numerator: Net income (loss) $ 113,791 $ (20,661) Net (income) loss attributable to Noncontrolling interest (61,792) 10,676 Net income (loss) attributable to Class A common shareholders for Basic EPS 51,999 (9,985) Adjustment for assumed conversions and elimination of Noncontrolling interest net income (loss) 429 (10,676) Net income (loss) attributable to Class A common shareholders for Diluted EPS $ 52,428 $ (20,661) Denominator: Weighted average shares outstanding used in Basic EPS 18,975 21,107 Effect of dilutive securities: Common Units and Class B Common Stock that are exchangeable for Class A Common Stock 1 — — RSUs and PRSUs 1 648 — Weighted average shares outstanding used in Diluted EPS 1 19,623 21,107 _______________________ 1 For the three months ended March 31, 2023 and 2022, approximately 22.5 million potentially dilutive Common Units (and the associated 22.5 million Class B Common Stock) had the effect of being anti-dilutive and were excluded from the calculation of earnings per share. For the three months ended March 31, 2022, 0.6 million of RSUs and PRSUs had the effect of being anti-dilutive and were excluded from the calculation of earnings per share.

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2023
Subsequent Events [Abstract]
Subsequent Events	Note 15 – Subsequent Events Dividends

Basis of Presentation and Sig_2

Basis of Presentation and Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2023
Accounting Policies [Abstract]
Basis of Presentation	Basis of PresentationOur unaudited condensed consolidated financial statements include the accounts of Ranger Oil and all of our subsidiaries as of the relevant dates. Intercompany balances and transactions have been eliminated. A substantial noncontrolling interest in our subsidiaries is provided for in our condensed consolidated statements of operations and comprehensive income (loss) and our condensed consolidated balance sheets for the periods presented. Our condensed 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 Exchange Commission (the “SEC”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments considered necessary for a fair presentation of our condensed consolidated financial statements have been included. Our condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2022 (“2022 Annual Report”). Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.
Principles of Consolidation	Principles of Consolidation Ranger Oil is organized as an Up-C structure whereby Juniper owns all of the shares of the Company’s Class B Common Stock which are non-economic voting only shares of the Company. Juniper’s economic interest in the Company is held through its ownership of limited partner interests, the Common Units, in the Partnership. Pursuant to the amended and restated limited partnership agreement of the Partnership (the “Partnership Agreement”), the Company’s ownership of Common Units in the Partnership at all times equals the number of shares of the Company’s Class A Common Stock then outstanding, and Juniper’s ownership of Common Units in the Partnership at all times equals the number of shares of Class B Common Stock then outstanding. The Partnership was formed for the purpose of executing the Company’s reorganization with Juniper into an Up-C structure. The Partnership, through its subsidiaries, owns, operates, and manages oil and gas properties in Texas and manages the Company’s outstanding debt and derivative instruments. The Company’s wholly-owned subsidiary, ROCC Energy Holdings GP LLC (the “GP”), is the general partner of the Partnership. Subsidiaries of the Partnership own and operate all our oil and gas assets. Ranger Oil and the Partnership are holding companies with no other operations, material cash flows, or material assets or liabilities other than the equity interests in their subsidiaries. The Common Units are redeemable (concurrently with the cancellation of an equivalent number of shares of Class B Common Stock) by Juniper at any time on a one-for-one basis in exchange for shares of Class A Common Stock or, if the Partnership elects, cash based on the 5-day average volume-weighted closing price for the Class A Common Stock immediately prior to the redemption. In determining whether to make a cash election, the Company would consider the interests of the holders of the Class A Common Stock, the Company’s financial condition, results of operations, earnings, projections, liquidity and capital requirements, management’s assessment of the intrinsic value of the Class A Common Stock, the trading price of the Class A Common Stock, legal requirements, covenant compliance, restrictions in the Company’s debt agreements and other factors it deems relevant.
Noncontrolling Interest	Noncontrolling Interest The noncontrolling interest percentage may be affected by the issuance of shares of Class A Common Stock, repurchases or cancellation of Class A Common Stock, the exchange of Class B Common Stock and the redemption of Common Units (and concurrent cancellation of Class B Common Stock), among other things. The percentage is based on the proportionate number of Common Units held by Juniper relative to the total Common Units outstanding. As of March 31, 2023, the Company owned 18,982,425 Common Units, representing a 45.7% limited partner interest in the Partnership, and Juniper owned 22,548,998 Common Units, representing the remaining 54.3% limited partner interest. As of December 31, 2022, the Company owned 19,074,864 Common Units, representing a 45.8% limited partner interest in the Partnership, and Juniper owned 22,548,998 Common Units, representing the remaining 54.2% limited partner interest. During the three months ended March 31, 2023, changes in the ownership interests were the result of share repurchases and issuances of Class A Common Stock in connection with the vesting of employees’ share-based compensation. See Note 12 for information regarding share repurchases and Note 13 for vesting of share-based compensation. When the Company’s relative ownership interest in the Partnership changes, adjustments to Noncontrolling interest and 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 Accounting Standards Codification 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. Additionally, based on the Partnership Agreement, there are no substantive profit sharing arrangements that would cause distributions to be other than pro rata. Therefore, profits and losses are attributed to the Class A common shareholders and noncontrolling interest pro rata based on ownership interests in the Partnership.
Recent Accounting Pronouncements and Recently Issued Accounting Pronouncements Not Yet Adopted	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. Adoption of Recently Issued Accounting Pronouncements Effective January 1, 2023, we adopted 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 if it had originated the contract, rather than at fair value. As required, ASU 2021-08 will be applied prospectively to business combinations occurring on or after December 15, 2022. We adopted this update on January 1, 2023 and it did not have a material impact on our financial statements.
Revenue	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 (“CDP”) 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”) in our condensed consolidated statements of operations. 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 in our condensed consolidated statements of operations. We record revenue in the month that our oil and gas production is delivered to our customers. However, 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 sold. 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. 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 contract assets or liabilities.
Oil and Gas Properties Policy	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 Ceiling Test utilizes an average of commodity prices based on the closing prices on the first day of each month for the previous 12 months.
Fair Value Measurements	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 and MEH crude oil, NYMEX HH natural gas, HSC natural gas and OPIS Mt. Belvieu 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 determined the fair values of our interest rate swaps using an income approach valuation technique which discounts future cash flows back to a single present value. We estimated the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these was a Level 2 input. All interest rate swaps matured in May 2022, and as of March 31, 2023, we had not entered into any new interest rate derivative instruments.
Share-Based Payment Arrangement	Compensation expense for RSUs is recognized on a straight-line basis over the applicable vesting period, which is generally over a three-year period.Compensation expense for PRSUs with a performance condition is recognized ratably over three years when it is considered probable that the performance condition will be achieved and such grants are expected to vest. PRSUs with a market condition do not allow for the reversal of previously recognized expense, even if the market condition is not achieved and no shares ultimately vest.
Earnings Per Share	Basic net earnings (loss) per share is calculated by dividing the net income (loss) available to Class A common shareholders, excluding net income or loss attributable to Noncontrolling interest, 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 (and shares of Class B Common Stock) held by the Noncontrolling interest in the Partnership are exchanged for common shares. Accordingly, our reported net income (loss) attributable to Class A common shareholders is adjusted due to the elimination of the Noncontrolling interest assuming exchange of the Common Units (and shares of Class B Common Stock) held by the Noncontrolling interest.

Revenue Recognition (Tables)

Revenue Recognition (Tables)	3 Months Ended
	Mar. 31, 2023
Receivables [Abstract]
Schedule of Accounts Receivable	The following table summarizes our accounts receivable by type as of the dates presented: March 31, 2023 December 31, 2022 Customers $ 111,726 $ 109,149 Joint interest partners 26,501 30,730 Derivative settlements from counterparties 1 732 437 Other 132 114 Total 139,091 140,430 Less: Allowance for credit losses (545) (715) Accounts receivable, net of allowance for credit losses $ 138,546 $ 139,715 _______________________

Derivative Instruments (Tables)

Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Commodity Derivative Positions	The following table sets forth our commodity derivative positions, presented on a net basis by period of maturity, as of March 31, 2023: 2Q2023 3Q2023 4Q2023 1Q2024 2Q2024 NYMEX WTI Crude Swaps Average Volume Per Day (bbl) 2,400 2,807 2,657 462 462 Weighted Average Swap Price ($/bbl) $ 54.26 $ 54.92 $ 54.93 $ 58.75 $ 58.75 NYMEX WTI Crude Collars Average Volume Per Day (bbl) 23,214 16,304 8,967 Weighted Average Purchased Put Price ($/bbl) $ 67.81 $ 72.50 $ 72.27 Weighted Average Sold Call Price ($/bbl) $ 78.89 $ 88.35 $ 87.57 MEH WTI CMA Crude Differential Swaps Average Volume Per Day (bbl) 13,187 Weighted Average Swap Price ($/bbl) $ 2.03 NYMEX HH Swaps Average Volume Per Day (MMBtu) 7,500 Weighted Average Swap Price ($/MMBtu) $ 3.690 NYMEX HH Collars Average Volume Per Day (MMBtu) 11,538 11,413 11,413 11,538 11,538 Weighted Average Purchased Put Price ($/MMBtu) $ 2.500 $ 2.500 $ 2.500 $ 2.500 $ 2.328 Weighted Average Sold Call Price ($/MMBtu) $ 2.682 $ 2.682 $ 2.682 $ 3.650 $ 3.000 HSC Basis Swaps Average Volume Per Day (MMBtu) 19,038 11,413 11,413 HSC Basis Average Fixed Price ($/MMBtu) $ (0.153) $ (0.153) $ (0.153) HSC Index Swap Average Volume Per Day (MMBtu) 6,319 HSC Index Average Fixed Price ($/MMBtu) $ (0.045) OPIS Mt. Belvieu Ethane Swaps Average Volume per Day (gal) 98,901 34,239 34,239 34,615 Weighted Average Fixed Price ($/gal) $ 0.2288 $ 0.2275 $ 0.2275 $ 0.2275 _______________________ 1 NYMEX WTI refers to New York Mercantile Exchange West Texas Intermediate and MEH refers to Magellan East Houston that serve as benchmarks for crude oil. NYMEX HH refers to NYMEX Henry Hub that serves as the benchmark for natural gas. HSC refers to Houston Ship Channel that serves as another benchmark for natural gas. OPIS Mt. Belvieu refers to Oil Price Information Service Mt. Belvieu that serves as the benchmark for ethane which represents a commodity proxy for NGLs.
Schedule of Impact of Derivative Activities on Condensed Consolidated Statements of Income and Cash Flows	The following table summarizes the effects of our derivative activities for the periods presented: Three Months Ended March 31, 2023 2022 Interest rate swap gains recognized in the condensed consolidated statements of operations $ — $ 83 Commodity gains (losses) recognized in the condensed consolidated statements of operations 25,658 (167,970) $ 25,658 $ (167,887) Interest rate cash settlements recognized in the condensed consolidated statements of cash flows $ — $ (938) Commodity cash settlements and premiums paid recognized in the condensed consolidated statements of cash flows (7,358) (28,470) $ (7,358) $ (29,408)
Schedule of Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets	The following table summarizes the fair values of our derivative instruments, which we elect to present on a gross basis, as well as the locations of these instruments on our condensed consolidated balance sheets as of the dates presented: Fair Values March 31, 2023 December 31, 2022 Type Balance Sheet Location Derivative Assets Derivative Liabilities Derivative Assets Derivative Liabilities Commodity contracts Derivative assets/liabilities – current $ 23,756 $ 32,286 $ 29,714 $ 67,933 Commodity contracts Derivative assets/liabilities – non-current 216 1,320 316 3,416 $ 23,972 $ 33,606 $ 30,030 $ 71,349

Property and Equipment, Net (Ta

Property and Equipment, Net (Tables)	3 Months Ended
	Mar. 31, 2023
Property, Plant and Equipment [Abstract]
Schedule of Property and Equipment	The following table summarizes our property and equipment as of the dates presented: March 31, 2023 December 31, 2022 Oil and gas properties (full cost accounting method): Proved $ 3,163,277 $ 3,013,854 Unproved 43,158 41,882 Total oil and gas properties 3,206,435 3,055,736 Other property and equipment 1 31,307 30,969 Total properties and equipment 3,237,742 3,086,705 Accumulated depreciation, depletion, amortization and impairments (1,362,906) (1,277,705) Total property and equipment, net $ 1,874,836 $ 1,809,000 _______________________

Long-Term Debt (Tables)

Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2023
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	The following table summarizes our debt obligations as of the dates presented: March 31, 2023 December 31, 2022 Credit Facility $ 240,000 $ 215,000 9.25% Senior Notes due 2026 400,000 400,000 Other — 238 Total 640,000 615,238 Less: Unamortized discount ¹ (2,878) (3,055) Less: Unamortized deferred issuance costs 1, 2 (7,642) (8,106) Long-term debt $ 629,480 $ 604,077 _______________________ ¹ 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. ² Excludes issuance costs associated with the Credit Facility, which represents costs attributable to the access to credit over its contractual term, that have been presented as a component of Other assets (see Note 9) and are being amortized over the term of the Credit Facility using the straight-line method.

Supplemental Balance Sheet De_2

Supplemental Balance Sheet Detail (Tables)	3 Months Ended
	Mar. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Components of Selected Balance Sheet Accounts	The following table summarizes components of selected balance sheet accounts as of the dates presented: March 31, 2023 December 31, 2022 Prepaid and other current assets: Inventories 1 $ 16,305 $ 19,341 Prepaid expenses 2 2,155 2,923 $ 18,460 $ 22,264 Other assets: Deferred issuance costs of the Credit Facility, net of amortization $ 2,926 $ 3,218 Right-of-use assets – operating leases 3 14,197 989 Other 155 213 $ 17,278 $ 4,420 Accounts payable and accrued liabilities: Trade accounts payable $ 50,366 $ 58,592 Drilling and other lease operating costs 50,318 62,842 Revenue and royalties payable 101,418 104,512 Production, ad valorem and other taxes 11,764 10,547 Derivative settlements to counterparties 3,074 4,109 Compensation and benefits 3,197 6,927 Interest 5,432 14,655 Current operating lease obligations 3 11,043 907 Other 3,180 2,518 $ 239,792 $ 265,609 Other non-current liabilities: Asset retirement obligations $ 8,960 $ 8,849 Non-current operating lease obligations 3 3,373 200 Postretirement benefit plan obligations 798 885 $ 13,131 $ 9,934 _______________________ 1 Includes tubular inventory and well materials of $15.7 million and $18.7 million as of March 31, 2023 and December 31, 2022, respectively, and crude oil volumes in storage of $0.6 million as of both March 31, 2023 and December 31, 2022. 2 The balances as of March 31, 2023 and December 31, 2022 include $0.5 million in each period for the prepayment of drilling and completion materials and services. 3 The balances as of March 31, 2023 primarily relate to an amended drilling rig lease contract.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2023
Fair Value Disclosures [Abstract]
Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis	The following tables summarize the valuation of those assets and liabilities as of the dates presented: As of March 31, 2023 Level 1 Level 2 Level 3 Total Financial assets: Commodity derivative assets – current $ — $ 23,756 $ — $ 23,756 Commodity derivative assets – non-current — 216 — 216 Total financial assets $ — $ 23,972 $ — $ 23,972 Financial liabilities: Commodity derivative liabilities – current $ — $ 32,286 $ — $ 32,286 Commodity derivative liabilities – non-current — 1,320 — 1,320 Total financial liabilities $ — $ 33,606 $ — $ 33,606 As of December 31, 2022 Level 1 Level 2 Level 3 Total Financial assets: Commodity derivative assets – current $ — $ 29,714 $ — $ 29,714 Commodity derivative assets – non-current — 316 — 316 Total financial assets $ — $ 30,030 $ — $ 30,030 Financial liabilities: Commodity derivative liabilities – current $ — $ 67,933 $ — $ 67,933 Commodity derivative liabilities – non-current — 3,416 — 3,416 Total financial liabilities $ — $ 71,349 $ — $ 71,349

Commitment and Contingencies (T

Commitment and Contingencies (Tables)	3 Months Ended
	Mar. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Supply Commitment	The following table provides details on these contractual arrangements as of March 31, 2023: Description of contractual arrangement Expiration Gross Minimum Volume Expiration of MVC 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

Shareholders' Equity (Tables)

Shareholders' Equity (Tables)	3 Months Ended
	Mar. 31, 2023
Equity [Abstract]
Schedule of Change in Ownership Interest	The following table summarizes changes in the ownership interest in consolidated subsidiaries during the periods presented: Three Months Ended March 31, 2023 2022 Net income (loss) attributable to Class A common shareholders $ 51,999 $ (9,985) Transfers from the noncontrolling interest, net 1 978 N/A Change from Net income (loss) attributable to Class A common shareholders and net transfers from Noncontrolling interest $ 52,977 $ (9,985) _____________________________________________ 1 The three months ended March 31, 2023 includes a net transfer of $1.0 million from Noncontrolling interest for share repurchases and common stock issuances related to employees’ share-based compensation with a corresponding adjustment to Paid-in capital. This equity adjustment had no impact on earnings other than a resulting increase to the noncontrolling interest proportionate share of net income and a corresponding decrease to the proportionate share of net income attributable to Class A common shareholders.

Share-Based Compensation and _2

Share-Based Compensation and Other Benefit Plans (Tables)	3 Months Ended
	Mar. 31, 2023
Share-Based Payment Arrangement [Abstract]
Schedule of Restricted Stock Unit Activity	The table below summarizes activity for the three months ended March 31, 2023 with respect to awarded RSUs: Time-Vested Weighted-Average Balance at January 1, 2023 149,871 $ 17.51 Granted 9,078 $ 38.68 Vested (43,015) $ 4.72 Forfeited (1,176) $ 42.81 Balance at March 31, 2023 114,758 $ 23.72 The table below summarizes activity for the three months ended March 31, 2023 with respect to awarded PRSUs: Performance Restricted Stock Weighted-Average Balance at January 1, 2023 440,100 $ 29.87 Granted — $ — Vested — $ — Forfeited (1,177) $ 58.87 Balance at March 31, 2023 438,923 $ 29.87
Schedule of Valuation Assumptions	The table below presents ranges for the assumptions used in the Monte Carlo model for the PRSUs granted in the following periods: 2022 2021 1 2020 1 2019 Expected volatility 134.98% to 138.75% 131.74% to 134.74% 101.32% to 117.71% 49.9 % Dividend yield 0.0 % 0.0 % 0.0 % 0.0 % Risk-free interest rate 2.59 % 0.22% to 0.29% 0.18% to 0.51% 1.66 % Performance period 2022-2024 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.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2023
Earnings Per Share [Abstract]
Schedule of 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 (loss) per share for the periods presented: Three Months Ended March 31, 2023 2022 Numerator: Net income (loss) $ 113,791 $ (20,661) Net (income) loss attributable to Noncontrolling interest (61,792) 10,676 Net income (loss) attributable to Class A common shareholders for Basic EPS 51,999 (9,985) Adjustment for assumed conversions and elimination of Noncontrolling interest net income (loss) 429 (10,676) Net income (loss) attributable to Class A common shareholders for Diluted EPS $ 52,428 $ (20,661) Denominator: Weighted average shares outstanding used in Basic EPS 18,975 21,107 Effect of dilutive securities: Common Units and Class B Common Stock that are exchangeable for Class A Common Stock 1 — — RSUs and PRSUs 1 648 — Weighted average shares outstanding used in Diluted EPS 1 19,623 21,107 _______________________ 1 For the three months ended March 31, 2023 and 2022, approximately 22.5 million potentially dilutive Common Units (and the associated 22.5 million Class B Common Stock) had the effect of being anti-dilutive and were excluded from the calculation of earnings per share. For the three months ended March 31, 2022, 0.6 million of RSUs and PRSUs had the effect of being anti-dilutive and were excluded from the calculation of earnings per share.

Organization and Description _2

Organization and Description of Business (Details)	3 Months Ended
	Mar. 31, 2023 segment $ / shares shares	Dec. 31, 2022 $ / shares shares
Juniper Transaction Table [Line Items]
Number of reportable segments | segment	1
Number of operating segments | segment	1
Juniper Transaction
Juniper Transaction Table [Line Items]
Ownership percentage by noncontrolling owners	54.30%	54.20%
Common Class B
Juniper Transaction Table [Line Items]
Common stock, par value (in dollars per share) | $ / shares	$ 0.01	$ 0.01
Common stock, issued (in shares)	22,548,998	22,548,998
Common stock, outstanding (in shares)	22,548,998	22,548,998
Common Class B | Juniper Transaction
Juniper Transaction Table [Line Items]
Common stock, par value (in dollars per share) | $ / shares	$ 0.01
Common Units
Juniper Transaction Table [Line Items]
Common stock, issued (in shares)	22,548,998
Common stock, outstanding (in shares)	22,548,998
Common Units | Juniper Transaction
Juniper Transaction Table [Line Items]
Investment owned (in shares)	22,548,998	22,548,998

Basis of Presentation and Sig_3

Basis of Presentation and Significant Accounting Policies (Details)	3 Months Ended
	Mar. 31, 2023 shares	Dec. 31, 2022 shares
Noncontrolling Interest [Line Items]
Common unit conversion ratio	1
Ranger Oil Corporation
Noncontrolling Interest [Line Items]
Ownership percentage	45.70%	45.80%
Ranger Oil Corporation | Common Units
Noncontrolling Interest [Line Items]
Investment owned (in shares)	18,982,425	19,074,864
Juniper Transaction
Noncontrolling Interest [Line Items]
Ownership percentage by noncontrolling owners	54.30%	54.20%
Juniper Transaction | Common Units
Noncontrolling Interest [Line Items]
Investment owned (in shares)	22,548,998	22,548,998
GP LLC | Ranger Oil Corporation
Noncontrolling Interest [Line Items]
Ownership percentage	100%

Transactions (Details)

Transactions (Details) - Baytex Merger	Feb. 27, 2023 $ / shares shares
Business Acquisition [Line Items]
Shares issued (in shares) | shares	7.49
Cash offered per share (in usd per share) | $ / shares	$ 13.31

Revenue Recognition (Details)

Revenue Recognition (Details) - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022
Receivables [Abstract]
Customers	$ 111,726	$ 109,149
Joint interest partners	26,501	30,730
Derivative settlements from counterparties	732	437
Other	132	114
Total	139,091	140,430
Less: Allowance for credit losses	(545)	(715)
Accounts receivable, net of allowance for credit losses	$ 138,546	$ 139,715

Derivative Instruments - Commod

Derivative Instruments - Commodity Derivative Positions (Details)	Mar. 31, 2023 bbl $ / bbl
Crude oil | Swap | Second Quarter 2023
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
Crude oil | Swap | Third Quarter 2023
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
Crude oil | Swap | Fourth Quarter 2023
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
Crude oil | Swap | First Quarter 2024
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	462
Derivative, Swap Type, Average Fixed Price	58.75
Crude oil | Swap | Second Quarter 2024
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	462
Derivative, Swap Type, Average Fixed Price	58.75
Crude oil | 2-Way Collars | Second Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	23,214
Derivative, Average Floor Price	67.81
Derivative, Average Cap Price	78.89
Crude oil | 2-Way Collars | Third Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	16,304
Derivative, Average Floor Price	72.50
Derivative, Average Cap Price	88.35
Crude oil | 2-Way Collars | Fourth Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	8,967
Derivative, Average Floor Price	72.27
Derivative, Average Cap Price	87.57
Crude oil | CMA Crude Differential Swaps | Second Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	13,187
Derivative, CMA Crude Differential Swaps, Price	2.03
Natural Gas | Swap | Second Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	19,038
Natural Gas | Swap | Second Quarter 2023 | Short
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Average Fixed Price	0.153
Natural Gas | Swap | Third Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	11,413
Natural Gas | Swap | Third Quarter 2023 | Short
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Average Fixed Price	0.153
Natural Gas | Swap | Fourth Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	11,413
Natural Gas | Swap | Fourth Quarter 2023 | Short
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Average Fixed Price	0.153
Natural Gas | 2-Way Collars | Second Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	11,538
Derivative, Average Floor Price	2.500
Derivative, Average Cap Price	2.682
Natural Gas | 2-Way Collars | Third Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	11,413
Derivative, Average Floor Price	2.500
Derivative, Average Cap Price	2.682
Natural Gas | 2-Way Collars | Fourth Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	11,413
Derivative, Average Floor Price	2.500
Derivative, Average Cap Price	2.682
Natural Gas | 2-Way Collars | First Quarter 2024
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	11,538
Derivative, Average Floor Price	2.500
Derivative, Average Cap Price	3.650
Natural Gas | 2-Way Collars | Second Quarter 2024
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	11,538
Derivative, Average Floor Price	2.328
Derivative, Average Cap Price	3
Natural Gas | NYMEX HH Swaps | Second Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	7,500
Derivative, Swap Type, Average Fixed Price	3.690
Natural Gas | HSC Index Swap | Second Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	6,319
Natural Gas | HSC Index Swap | Second Quarter 2023 | Short
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Swap Type, Average Fixed Price	0.045
Natural gas liquids | Swap | Second Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	98,901
Derivative, Swap Type, Average Fixed Price	0.2288
Natural gas liquids | Swap | Third Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	34,239
Derivative, Swap Type, Average Fixed Price	0.2275
Natural gas liquids | Swap | Fourth Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	34,239
Derivative, Swap Type, Average Fixed Price	0.2275
Natural gas liquids | Swap | First Quarter 2024
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	34,615
Derivative, Swap Type, Average Fixed Price	0.2275

Derivative Instruments - Narrat

Derivative Instruments - Narrative (Details) $ in Millions	Mar. 31, 2023 USD ($) customer	May 31, 2022 USD ($)
Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, notional amount		$ 300
Derivative, average fixed interest rate	1.36%
Commodity contracts
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative liabilities	$ 9.6
Number of derivative counterparties | customer	7

Derivative Instruments - Impact

Derivative Instruments - Impact of Derivative Activities on Condensed Consolidated Statements of Income and Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Interest rate swap gains recognized in the condensed consolidated statements of operations	$ 0	$ 83
Commodity gains (losses) recognized in the condensed consolidated statements of operations	25,658	(167,970)
Derivative gains (losses)	25,658	(167,887)
Cash settlements and premiums paid, net	(7,358)	(29,408)
Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Interest rate cash settlements recognized in the condensed consolidated statements of cash flows	0	(938)
Commodity contracts
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Commodity cash settlements and premiums paid recognized in the condensed consolidated statements of cash flows	$ (7,358)	$ (28,470)

Derivative Instruments - Fair V

Derivative Instruments - Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022
Derivatives, Fair Value [Line Items]
Derivative assets	$ 23,756	$ 29,714
Derivative assets	216	316
Derivative assets	23,972	30,030
Derivative liabilities	32,286	67,933
Derivative liabilities	1,320	3,416
Derivative liabilities	33,606	71,349
Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative assets	23,756	29,714
Derivative assets	216	316
Derivative liabilities	32,286	67,933
Derivative liabilities	$ 1,320	$ 3,416

Property and Equipment, Net - S

Property and Equipment, Net - Summary of Property and Equipment (Details) - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022
Oil and gas properties (full cost accounting method):
Proved	$ 3,163,277	$ 3,013,854
Unproved	43,158	41,882
Total oil and gas properties	3,206,435	3,055,736
Other property and equipment	31,307	30,969
Total properties and equipment	3,237,742	3,086,705
Accumulated depreciation, depletion, amortization and impairments	(1,362,906)	(1,277,705)
Total property and equipment, net	1,874,836	$ 1,809,000
Assets held for sale	$ 1,200

Property and Equipment, Net - N

Property and Equipment, Net - Narrative (Details) $ in Millions	3 Months Ended		15 Months Ended
	Mar. 31, 2023 USD ($) $ / bbl	Mar. 31, 2022 USD ($) $ / bbl	Mar. 31, 2023 USD ($) $ / bbl bbl	Mar. 31, 2023 USD ($) $ / bbl $ / bbl	Mar. 31, 2023 USD ($) $ / Mcf $ / bbl	Dec. 31, 2022 USD ($)
Property, Plant and Equipment [Line Items]
Unproved oil and gas property excluded	$ 43.2		$ 43.2	$ 43.2	$ 43.2	$ 41.9
Undeveloped leasehold costs transferred	0.9	$ 0.7
Capitalized costs, proved properties	1.6	1.4	$ 1.6	$ 1.6	$ 1.6
Interest costs capitalized	$ (0.9)	$ (1.1)
Amortization expense per physical unit of production | $ / bbl	19.45	14.98	19.45	19.45	19.45
West Texas Intermediate
Property, Plant and Equipment [Line Items]
Impairments of oil and gas properties	$ 0	$ 0
West Texas Intermediate | Maximum
Property, Plant and Equipment [Line Items]
Oil price per barrel (in dollars per barrel)				120	9
West Texas Intermediate | Minimum
Property, Plant and Equipment [Line Items]
Oil price per barrel (in dollars per barrel)				67	2
OPEC+
Property, Plant and Equipment [Line Items]
Number of barrels | bbl			1,160,000
Oil price per barrel (in dollars per barrel) | $ / bbl				3.66

Long-Term Debt - Summary of Lon

Long-Term Debt - Summary of Long-Term Debt (Details) - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022	Aug. 10, 2021
Debt Instrument [Line Items]
Long-term debt, gross	$ 640,000	$ 615,238
Less: Unamortized discount	(2,878)	(3,055)
Less: Unamortized deferred issuance costs	(7,642)	(8,106)
Long-term debt, net	629,480	604,077
Line of Credit
Debt Instrument [Line Items]
Long-term debt, gross	240,000	215,000
Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross	$ 400,000	400,000
Senior Notes | Senior Notes Due 2026
Debt Instrument [Line Items]
Interest rate	9.25%		9.25%
Other
Debt Instrument [Line Items]
Long-term debt, gross	$ 0	$ 238

Long-Term Debt - Narrative (Det

Long-Term Debt - Narrative (Details) - USD ($)	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Aug. 10, 2021
Debt Disclosure [Line Items]
Current ratio	1
Debt to EBITD ratio, maximum	3.50
Debt issuance costs, line of credit arrangements, gross	$ 0	$ 400,000
Senior notes, redemption percentage			99.018%
Other debt	200,000
Gain on extinguishment of debt	$ 0	$ 2,157,000
Revolving Credit Facility
Debt Disclosure [Line Items]
Line of credit facility, interest rate at period end	7.67%
Commitment fee	0.50%
Revolving Credit Facility | Interest Payable One
Debt Disclosure [Line Items]
Debt instrument, interest payable period	1 month
Revolving Credit Facility | Interest Payable Two
Debt Disclosure [Line Items]
Debt instrument, interest payable period	3 months
Revolving Credit Facility | Interest Payable Three
Debt Disclosure [Line Items]
Debt instrument, interest payable period	6 months
Revolving Credit Facility | Minimum
Debt Disclosure [Line Items]
Interest rate	1.50%
Revolving Credit Facility | Minimum | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate
Debt Disclosure [Line Items]
Applicable margin	2.50%
Revolving Credit Facility | Maximum
Debt Disclosure [Line Items]
Interest rate	2.50%
Revolving Credit Facility | Maximum | Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate
Debt Disclosure [Line Items]
Applicable margin	3.50%
Line of Credit | Revolving Credit Facility
Debt Disclosure [Line Items]
Line of credit facility, maximum borrowing capacity	$ 1,000,000,000
Line of credit facility, current borrowing capacity	500,000,000
Outstanding borrowings	240,000,000
Letters of credit outstanding	1,000,000
Remaining borrowing capacity	259,000,000
Letter of Credit
Debt Disclosure [Line Items]
Line of credit facility, maximum borrowing capacity	25,000,000
Revolving Credit Facility | Line of Credit
Debt Disclosure [Line Items]
Line of credit facility, borrowing base	$ 950,000,000
Senior Notes Due 2026 | Senior Notes
Debt Disclosure [Line Items]
Interest rate	9.25%		9.25%
Principal amount			$ 400,000,000

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Income tax expense (benefit)	$ (991)	$ 189
Change in deferred tax assets valuation allowance, percent	0.90%	0.90%
Net deferred tax liability	$ 7,000
Unrecognized tax benefits	0		$ 0
Income tax examination, penalties and interest expense	$ 0	$ 0

Supplemental Balance Sheet De_3

Supplemental Balance Sheet Detail (Details) - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022
Prepaid and other current assets:
Inventories	$ 16,305	$ 19,341
Prepaid expenses	2,155	2,923
Prepaid and other current assets	18,460	22,264
Other assets:
Deferred issuance costs of the Credit Facility, net of amortization	2,926	3,218
Right-of-use assets – operating leases 3	14,197	989
Other	155	213
Other assets	17,278	4,420
Accounts payable and accrued liabilities:
Trade accounts payable	50,366	58,592
Drilling and other lease operating costs	50,318	62,842
Revenue and royalties payable	101,418	104,512
Production, ad valorem and other taxes	11,764	10,547
Derivative settlements to counterparties	3,074	4,109
Compensation and benefits	3,197	6,927
Interest	5,432	14,655
Current operating lease obligations 3	11,043	907
Other	3,180	2,518
Accounts payable and accrued liabilities	239,792	265,609
Other non-current liabilities:
Asset retirement obligations	8,960	8,849
Non-current operating lease obligations 3	3,373	200
Postretirement benefit plan obligations	798	885
Other non-current liabilities	13,131	9,934
Tubular inventory and well materials	15,700	18,700
Capitalized costs - crude oil in storage	$ 600	600
Drilling and completion prepayment		$ 500

Fair Value Measurements - Narra

Fair Value Measurements - Narrative (Details) - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022	Aug. 10, 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, gross	$ 640,000	$ 615,238
Long-term debt, fair value	661,500	616,400
Senior Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, gross	$ 400,000	$ 400,000
Senior Notes Due 2026 | Senior Notes
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Interest rate	9.25%		9.25%

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022
Financial assets:
Commodity derivative assets – current	$ 23,756	$ 29,714
Commodity derivative assets – non-current	216	316
Total financial assets	23,972	30,030
Financial liabilities:
Derivative liabilities – current	32,286	67,933
Derivative liabilities, noncurrent	1,320	3,416
Total financial liabilities	33,606	71,349
Fair Value, Measurements, Recurring
Financial assets:
Total financial assets	23,972	30,030
Financial liabilities:
Total financial liabilities	33,606	71,349
Commodity contracts
Financial assets:
Commodity derivative assets – current	23,756	29,714
Commodity derivative assets – non-current	216	316
Financial liabilities:
Derivative liabilities – current	32,286	67,933
Derivative liabilities, noncurrent	1,320	3,416
Commodity contracts | Fair Value, Measurements, Recurring
Financial assets:
Commodity derivative assets – current	23,756	29,714
Commodity derivative assets – non-current	216	316
Financial liabilities:
Derivative liabilities – current	32,286	67,933
Derivative liabilities, noncurrent	1,320	3,416
Level 1 | Fair Value, Measurements, Recurring
Financial assets:
Total financial assets	0	0
Financial liabilities:
Total financial liabilities	0	0
Level 1 | Commodity contracts | Fair Value, Measurements, Recurring
Financial assets:
Commodity derivative assets – current	0	0
Commodity derivative assets – non-current	0	0
Financial liabilities:
Derivative liabilities – current	0	0
Derivative liabilities, noncurrent	0	0
Level 2 | Fair Value, Measurements, Recurring
Financial assets:
Total financial assets	23,972	30,030
Financial liabilities:
Total financial liabilities	33,606	71,349
Level 2 | Commodity contracts | Fair Value, Measurements, Recurring
Financial assets:
Commodity derivative assets – current	23,756	29,714
Commodity derivative assets – non-current	216	316
Financial liabilities:
Derivative liabilities – current	32,286	67,933
Derivative liabilities, noncurrent	1,320	3,416
Level 3 | Fair Value, Measurements, Recurring
Financial assets:
Total financial assets	0	0
Financial liabilities:
Total financial liabilities	0	0
Level 3 | Commodity contracts | Fair Value, Measurements, Recurring
Financial assets:
Commodity derivative assets – current	0	0
Commodity derivative assets – non-current	0	0
Financial liabilities:
Derivative liabilities – current	0	0
Derivative liabilities, noncurrent	$ 0	$ 0

Commitments and Contingencies -

Commitments and Contingencies - Narrative (Details)	3 Months Ended
	Mar. 31, 2023 USD ($) rig productionAgreement bbl	Mar. 31, 2022 USD ($)	Dec. 31, 2022 USD ($)
Commitments and Contingencies Disclosure [Line Items]
Remaining term of drilling equipment contract	2 years
Unrecorded unconditional purchase obligation, change of amount as result of variable components (in dollars per barrel)	$ 90
Unrecorded unconditional purchase obligation, purchases	$ 10,000,000	$ 10,200,000
Natural gas production extend period	3 years
Number of gas production agreement | productionAgreement	1
Estimated litigation liability, current	$ 100,000		$ 100,000
Asset retirement obligation	9,000,000		$ 8,800,000
Crude Oil Gathering And Transportation Services
Commitments and Contingencies Disclosure [Line Items]
Purchase obligation, remainder of 2023	10,500,000
Purchase obligation, year 2024	13,900,000
Purchase obligation, year 2025	13,900,000
Purchase obligation, year 2026	7,800,000
Purchase obligation, year 2027	3,800,000
Purchase obligation, year 2028	3,800,000
Purchase obligation, year 2029	3,800,000
Purchase obligation, year 2030	3,800,000
Purchase obligation, year 2031	$ 600,000
Intermediate pipeline transportation services
Commitments and Contingencies Disclosure [Line Items]
Number of barrels | bbl	8,000
Field gathering agreement
Commitments and Contingencies Disclosure [Line Items]
Number of barrels | bbl	8,000
Gonzales, Lavaca and Fayette Counties, Texas | Intermediate pipeline transportation services
Commitments and Contingencies Disclosure [Line Items]
Number of barrels | bbl	20,000
Gonzales, Lavaca and Fayette Counties, Texas | Field gathering agreement
Commitments and Contingencies Disclosure [Line Items]
Number of barrels | bbl	20,000
Nuevo G&T | Crude Oil Storage Capacity
Commitments and Contingencies Disclosure [Line Items]
Number of barrels | bbl	180,000
Nuevo G&T | Tank Capacity
Commitments and Contingencies Disclosure [Line Items]
Number of barrels | bbl	70,000
Drilling Rig With Two Year Contract
Commitments and Contingencies Disclosure [Line Items]
Drilling rigs | rig	2

Commitments and Contingencies_2

Commitments and Contingencies - Purchase Commitment, Excluding Long-term Commitment (Details)	3 Months Ended
	Mar. 31, 2023 bbl
Field gathering agreement
Commitments and Contingencies Disclosure [Line Items]
Number of barrels	8,000
Intermediate pipeline transportation services
Commitments and Contingencies Disclosure [Line Items]
Number of barrels	8,000
Volume capacity support
Commitments and Contingencies Disclosure [Line Items]
Number of barrels	8,000

Shareholders' Equity - Narrativ

Shareholders' Equity - Narrative (Details)		3 Months Ended
	Mar. 03, 2023 $ / shares	Mar. 31, 2023 USD ($) class $ / shares shares	Feb. 27, 2023 USD ($)	Dec. 31, 2022 $ / shares shares	Jul. 07, 2022 USD ($)	Apr. 13, 2022 USD ($)
Subsidiary, Sale of Stock [Line Items]
Number of common stock classes | class		2
Preferred stock, shares authorized (in shares)		5,000,000		5,000,000
Preferred stock, par value (in dollars per share) | $ / shares		$ 0.01		$ 0.01
Preferred stock, shares outstanding (in shares)		0
Preferred stock, issued (in shares)		0		0
Cash dividend declared (in dollars per share) | $ / shares		$ 0.075
Dividends declared ($0.075 per share of Class A common stock) | $		$ 1,454,000
Treasury stock, acquired (in shares)		121,857
Treasury stock, acquired | $		$ 4,800,000
Treasury stock, acquired, average cost per share (in dollars per share) | $ / shares		$ 39.52
Remaining authorized repurchase amount | $		$ 60,000,000
Stock repurchased value | $		100,000
Limited Partner
Subsidiary, Sale of Stock [Line Items]
Transfers to the noncontrolling interest, net | $		$ 978,000
Common Class B
Subsidiary, Sale of Stock [Line Items]
Common stock, par value, liquidation (in dollars per share) | $ / shares		$ 0.01
Common stock, authorized (in shares)		30,000,000		30,000,000
Common stock, issued (in shares)		22,548,998		22,548,998
Common stock, outstanding (in shares)		22,548,998		22,548,998
Common Class A
Subsidiary, Sale of Stock [Line Items]
Common stock, authorized (in shares)		110,000,000		110,000,000
Common stock, issued (in shares)		18,982,425		19,074,864
Common stock, outstanding (in shares)		18,982,425		19,074,864
Cash dividend declared (in dollars per share) | $ / shares	$ 0.075
Dividends declared ($0.075 per share of Class A common stock) | $		$ 3,100,000
Stock repurchase program, authorized amount | $			$ 0		$ 140,000,000	$ 100,000,000

Shareholders' Equity - Schedule

Shareholders' Equity - Schedule of Change in Ownership Interest (Details) - Limited Partner - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Subsidiary, Sale of Stock [Line Items]
Net income (loss) attributable to Class A common shareholders	$ 51,999	$ (9,985)
Transfers to the noncontrolling interest, net	978
Change from Net income (loss) attributable to Class A common shareholders and net transfers from Noncontrolling interest	$ 52,977	$ (9,985)

Share-Based Compensation and _3

Share-Based Compensation and Other Benefit Plans - Narrative (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2020	Dec. 31, 2019
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based compensation	$ 2,051	$ 924
Defined contribution plan, cost	300	200
Other Pension, Postretirement and Supplemental Plans
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Pension and other postretirement benefits cost (reversal of cost), less than	$ 100	$ 100
Restricted Stock Units (RSUs)
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Number of shares available for grant (in shares)	820,651
Award vesting period	3 years
Cost not yet recognized, amount	$ 1,600
Cost not yet recognized, period for recognition	1 year 5 months 26 days
Performance Shares
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Number of shares authorized (in shares)	664,414
Award vesting period	3 years
Cost not yet recognized, amount	$ 6,500
Cost not yet recognized, period for recognition	1 year 5 months 26 days
Performance Shares | Minimum
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Award vesting period	1 year
Shares expected to vest, percentage	0%
Performance Shares | Maximum
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Award vesting period	3 years
Shares expected to vest, percentage	200%
Performance Restricted Stock Units
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Performance measure one, percent of award	50%
Performance measure two, percent of award	50%
Shares expected to vest, percentage			92%	92%
Employees and Directors
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Number of shares available for grant (in shares)	4,424,600

Share-Based Compensation and _4

Share-Based Compensation and Other Benefit Plans - Summary of Restricted Stock Unit Activity (Details)	3 Months Ended
	Mar. 31, 2023 $ / shares shares
Restricted Stock Units (RSUs)
Time-Vested Restricted Stock Units
Balance at beginning of period (in shares) | shares	149,871
Granted (in shares) | shares	9,078
Vested (in shares) | shares	(43,015)
Forfeited (in shares) | shares	(1,176)
Balance at end of period (in shares) | shares	114,758
Weighted-Average Grant Date Fair Value
Balance at beginning of period (in dollars per share) | $ / shares	$ 17.51
Granted (in dollars per share) | $ / shares	38.68
Vested (in dollars per share) | $ / shares	4.72
Forfeited (in shares) | $ / shares	42.81
Balance at end of period (in shares) | $ / shares	$ 23.72
Performance Shares
Time-Vested Restricted Stock Units
Balance at beginning of period (in shares) | shares	440,100
Granted (in shares) | shares	0
Vested (in shares) | shares	0
Forfeited (in shares) | shares	(1,177)
Balance at end of period (in shares) | shares	438,923
Weighted-Average Grant Date Fair Value
Balance at beginning of period (in dollars per share) | $ / shares	$ 29.87
Granted (in dollars per share) | $ / shares	0
Vested (in dollars per share) | $ / shares	0
Forfeited (in shares) | $ / shares	58.87
Balance at end of period (in shares) | $ / shares	$ 29.87

Share-Based Compensation and _5

Share-Based Compensation and Other Benefit Plans - Schedule of Valuation Assumptions (Details) - Performance Shares	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Mar. 31, 2021	Mar. 31, 2020
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expected volatility				49.90%
Dividend yield	0%	0%	0%	0%
Risk-free interest rate	2.59%			1.66%
Risk-free interest rate, minimum		0.22%	0.18%
Risk-free interest rate, maximum		0.29%	0.51%
Minimum
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expected volatility	134.98%	131.74%	101.32%
Maximum
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expected volatility	138.75%	134.74%	117.71%

Earnings Per Share - Components

Earnings Per Share - Components of Calculation of Basic and Diluted Earnings Per Share (Details) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Numerator:
Net income (loss)	$ 113,791	$ (20,661)
Net (income) loss attributable to Noncontrolling interest	(61,792)	10,676
Net income (loss) attributable to Class A common shareholders	51,999	(9,985)
Adjustment for assumed conversions and elimination of Noncontrolling interest net income (loss)	429	(10,676)
Net income (loss) attributable to Class A common shareholders for Diluted EPS	$ 52,428	$ (20,661)
Denominator:
Weighted-average shares – basic (in shares)	18,975	21,107
Effect of dilutive securities:
Common Units and Class B Common Stock that are exchangeable for Class A Common Stock (in shares)	0	0
RSUs and PRSUs (in shares)	648	0
Weighted average shares outstanding used in Diluted EPS (in shares)	19,623	21,107
Restricted Stock Units and Performance Stock Units
Effect of dilutive securities:
Antidilutive securities excluded from computation of earnings per share (in shares)		600
Common Units
Effect of dilutive securities:
Antidilutive securities excluded from computation of earnings per share (in shares)	22,500	22,500
Common Class B
Effect of dilutive securities:
Antidilutive securities excluded from computation of earnings per share (in shares)	22,500	22,500

Subsequent Events (Details)

Subsequent Events (Details) - $ / shares			3 Months Ended
	May 05, 2023	Mar. 03, 2023	Mar. 31, 2023
Subsequent Event [Line Items]
Cash dividend declared (in dollars per share)			$ 0.075
Common Class A
Subsequent Event [Line Items]
Cash dividend declared (in dollars per share)		$ 0.075
Common Class A | Subsequent Event
Subsequent Event [Line Items]
Cash dividend declared (in dollars per share)	$ 0.075