10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________________________________________________________________

 FORM 10-Q

______________________________________________________________________________________

(Mark One)

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2022

or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to              

 Commission file number: 1-13283

RANGER OIL CORPORATION

(Exact name of registrant as specified in its charter)

Virginia	23-1184320
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

16285 Park Ten Place, Suite 500

Houston, TX 77084

(Address of principal executive offices) (Zip Code)

(713) 722-6500

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class A Common Stock, $0.01 Par Value	ROCC	The Nasdaq Stock Market LLC

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒  No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐	Accelerated filer	☒
Non-accelerated filer	☐	Smaller reporting company	☒
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

As of April 28, 2022, there were 43,712,392 shares of common stock outstanding, including 21,163,394 shares of Class A Common Stock and 22,548,998 shares of Class B Common Stock.

RANGER OIL CORPORATION

QUARTERLY REPORT ON FORM 10-Q

 For the Quarterly Period Ended March 31, 2022

 Table of Contents

		Page
	Part I - Financial Information
Item 1.	Financial Statements - Unaudited	3
	Condensed Consolidated Statements of Operations - Unaudited	3
	Condensed Consolidated Statements of Comprehensive Loss - Unaudited	4
	Condensed Consolidated Balance Sheets - Unaudited	5
	Condensed Consolidated Statements of Cash Flows - Unaudited	6
	Condensed Consolidated Statements of Equity - Unaudited	7
	Notes to Condensed Consolidated Financial Statements - Unaudited	8
	Note 1 – Organization and Description of Business	8
	Note 2 – Summary of Significant Accounting Policies	8
	Note 3 – Acquisition	9
	Note 4 – Revenue Recognition	9
	Note 5 – Derivative Instruments	10
	Note 6 – Property and Equipment	12
	Note 7 – Long-Term Debt	13
	Note 8 – Income Taxes	14
	Note 9 – Supplemental Balance Sheet Detail	15
	Note 10 – Fair Value Measurements	16
	Note 11 – Commitments and Contingencies	17
	Note 12 – Share-Based Compensation and Other Benefit Plans	18
	Note 13 – Earnings per Share	20
	Note 14 – Subsequent Events	20
Forward-Looking Statements		22
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
	Overview and Executive Summary	23
	Results of Operations	26
	Liquidity and Capital Resources	35
	Critical Accounting Estimates	38
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39
Item 4.	Controls and Procedures	40
	Part II - Other Information
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 3.	Defaults Upon Senior Securities	40
Item 4.	Mine Safety Disclosures	40
Item 5.	Other Information	40
Item 6.	Exhibits	41
Signatures		42

Part I. FINANCIAL INFORMATION

Item 1. Financial Statements

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – UNAUDITED

(in thousands, except per share data) 

	Three Months Ended March 31,
	2022		2021
Revenues and other
Crude oil	$	226,732	$	81,913
Natural gas liquids	16,740		3,562
Natural gas	12,127		2,833
Other operating income, net	856		247
Total revenues and other	256,455		88,555
Operating expenses
Lease operating	18,102		8,825
Gathering, processing and transportation	9,040		4,674
Production and ad valorem taxes	13,140		5,513
General and administrative	9,779		13,177
Depreciation, depletion and amortization	50,893		23,884
Impairments of oil and gas properties	—		1,811
Total operating expenses	100,954		57,884
Operating income	155,501		30,671
Other income (expense)
Interest expense, net of amounts capitalized	(10,697)		(5,397)
Gain (loss) on extinguishment of debt	2,157		(1,231)
Derivative losses	(167,887)		(44,368)
Other, net	76		(6)
Loss before income taxes	(20,850)		(20,331)
Income tax benefit	189		310
Net loss	(20,661)		(20,021)
Net loss attributable to Noncontrolling interest	10,676		6,449
Net loss attributable to common shareholders	$	(9,985)	$	(13,572)
Net loss per share attributable to common shareholders:
Basic	$	(0.47)	$	(0.89)
Diluted	$	(0.47)	$	(0.89)
Weighted average shares outstanding – basic	21,107		15,263
Weighted average shares outstanding – diluted	21,107		15,263

See accompanying notes to condensed consolidated financial statements.

3

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS – UNAUDITED

(in thousands) 

	Three Months Ended March 31,
	2022		2021
Net loss	$	(20,661)	$	(20,021)
Other comprehensive loss:
Change in pension and postretirement obligations, net of tax	—		2
Comprehensive loss	(20,661)		(20,019)
Net loss attributable to Noncontrolling interest	10,676		6,449
Other comprehensive income attributable to Noncontrolling interest	—		(1)
Comprehensive loss attributable to common shareholders	$	(9,985)	$	(13,571)

See accompanying notes to condensed consolidated financial statements.

4

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS – UNAUDITED

(in thousands, except share data)

	March 31, 2022		December 31, 2021
Assets
Current assets
Cash and cash equivalents	$	6,358	$	23,681
Accounts receivable, net of allowance for credit losses	154,179		118,594
Derivative assets	9,631		11,478
Prepaid and other current assets	15,989		20,998
Assets held for sale	11,400		11,400
Total current assets	197,557		186,151
Property and equipment, net (full cost method)	1,417,715		1,383,348
Derivative assets	2,912		2,092
Other assets	4,636		5,017
Total assets	$	1,622,820	$	1,576,608
Liabilities and Equity
Current liabilities
Accounts payable and accrued liabilities	246,189		214,381
Derivative liabilities	149,008		50,372
Current portion of long-term debt	1,925		4,129
Total current liabilities	397,122		268,882
Deferred income taxes	2,073		2,793
Derivative liabilities	42,620		23,815
Other non-current liabilities	9,900		10,358
Long-term debt, net	521,780		601,252
Commitments and contingencies (Note 11)
Equity
Preferred stock of $0.01 par value – 5,000,000 shares authorized; none issued as of March 31, 2022 and December 31, 2021	—		—
Class A common stock of $0.01 par value – 110,000,000 shares authorized; 21,146,230 and 21,090,259 shares issued as of March 31, 2022 and December 31, 2021, respectively	729		729
Class B common stock of $0.01 par value – 30,000,000 shares authorized; 22,548,998 shares issued as of March 31, 2022 and December 31, 2021	2		2
Paid-in capital	273,807		273,329
Retained earnings	39,598		49,583
Accumulated other comprehensive loss	(111)		(111)
Ranger Oil shareholders’ equity	314,025		323,532
Noncontrolling interest	335,300		345,976
Total equity	649,325		669,508
Total liabilities and equity	$	1,622,820	$	1,576,608

See accompanying notes to condensed consolidated financial statements.

5

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – UNAUDITED

(in thousands)

	Three Months Ended March 31,
	2022		2021
Cash flows from operating activities
Net loss	$	(20,661)	$	(20,021)
Adjustments to reconcile net loss to net cash provided by operating activities:
(Gain) loss on extinguishment of debt	(2,157)		1,231
Depreciation, depletion and amortization	50,893		23,884
Impairments of oil and gas properties	—		1,811
Derivative contracts:
Net losses	167,887		44,368
Cash settlements and premiums paid, net	(29,408)		(7,169)
Deferred income tax benefit	(721)		(310)
Non-cash interest expense	800		611
Share-based compensation	924		2,246
Other, net	(182)		2
Changes in operating assets and liabilities, net	(33,540)		(13,966)
Net cash provided by operating activities	133,835		32,687
Cash flows from investing activities
Capital expenditures	(71,173)		(34,758)
Proceeds from sales of assets, net	656		4
Net cash used in investing activities	(70,517)		(34,754)
Cash flows from financing activities
Proceeds from credit facility borrowings	50,000		—
Repayments of credit facility borrowings	(130,000)		(85,500)
Repayments of second lien term loan	—		(53,140)
Repayments of acquired debt	(83)		—
Proceeds from redeemable common units	—		151,160
Proceeds from redeemable preferred stock	—		2
Transaction costs paid on behalf of Noncontrolling interest	—		(5,543)
Issuance costs paid for Noncontrolling interest securities	—		(3,758)
Withholding taxes for share-based compensation	(445)		(476)
Debt issuance costs paid	(113)		(1,830)
Net cash provided by (used in) financing activities	(80,641)		915
Net decrease in cash and cash equivalents	(17,323)		(1,152)
Cash and cash equivalents – beginning of period	23,681		13,020
Cash and cash equivalents – end of period	$	6,358	$	11,868
Supplemental disclosures:
Cash paid for:
Interest, net of amounts capitalized	$	20,214	$	4,888
Non-cash investing and financing activities:
Changes in property and equipment related to capital contributions	$	—	$	(38,415)
Changes in accrued liabilities related to capital expenditures	$	9,361	$	20,246

See accompanying notes to condensed consolidated financial statements.

6

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - UNAUDITED

(in thousands)

	Preferred Stock		Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Loss		Noncontrolling interest		Total Equity
Balance as of December 31, 2021	$	—	$	731	$	273,329	$	49,583	$	(111)	$	345,976	$	669,508
Net loss	—		—		—		(9,985)		—		(10,676)		(20,661)
All other changes 1	—		—		478		—		—		—		478
Balance as of March 31, 2022	$	—	$	731	$	273,807	$	39,598	$	(111)	$	335,300	$	649,325

_______________________

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, 69,206 of common stock were issued in connection with the vesting of certain time-vested restricted stock units (“RSUs”), net of shares withheld for income taxes. No shares of common stock were issued in connection with the vesting of performance-based restricted stock units (“PRSUs”) during the three months ended March 31, 2022.

	Preferred Stock		Common Stock		Paid-in Capital		Retained Earnings/(Accumulated Deficit)		Accumulated Other Comprehensive Loss		Noncontrolling interest		Total Equity
Balance as of December 31, 2020	$	—	$	152	$	203,463	$	9,354	$	(131)	$	—	212,838
Net loss	—		—		—		(13,572)		—		(6,449)		(20,021)
Issuance of preferred stock	2		—		—		—		—		—		2
Issuance of Noncontrolling interest	—		—		(50,068)		—		—		229,620		179,552
All other changes 1	—		1		1,769		—		1		1		1,772
Balance as of March 31, 2021	$	2	$	153	$	155,164	$	(4,218)	$	(130)	$	223,172	$	374,143

_______________________

1 Includes equity-classified share-based compensation of $2.2 million during the three months ended March 31, 2021. During the three months ended March 31, 2021, 102,586 and 6,800 shares of common stock were issued in connection with the vesting of certain RSUs and PRSUs, net of shares withheld for income taxes, respectively.

See accompanying notes to condensed consolidated financial statements.

7

RANGER OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – UNAUDITED

For the Quarterly Period Ended March 31, 2022

(in thousands, except per share amounts or where otherwise indicated)

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.

On January 15, 2021, the Company consummated the transactions (collectively, the “Juniper Transactions”) contemplated by: (i) the Contribution Agreement, dated November 2, 2020, by and among the Company, PV Energy Holdings, L.P. (the “Partnership”) and JSTX Holdings, LLC (“JSTX”), an affiliate of Juniper Capital Advisors, L.P. (“Juniper Capital” and, together with JSTX and Rocky Creek Resources, LLC, “Juniper”); and (ii) the Contribution Agreement, dated November 2, 2020, by and among Rocky Creek Resources, LLC, an affiliate of Juniper Capital, the Company and the Partnership pursuant to which Juniper contributed $150 million in cash and certain oil and gas assets in South Texas in exchange for equity that entitles Juniper to both vote and share in any dividend on the same basis as 22,548,998 shares of our Class A Common Stock, par value $0.01 per share (“Class A Common Stock”) (after post-closing adjustments). In connection with the consummation of the Juniper Transactions, the Company completed a reorganization into an up-C structure which was intended to, among other things, result in the affiliates of Juniper Capital having a voting interest in the Company that is commensurate with such holders’ economic interest in the Partnership.

Note 2 – Summary of 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 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. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications did not have a material impact on prior period financial statements. 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, 2021. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

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 Annual Report on Form 10-K for the year ended December 31, 2021 (“2021 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 2021 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.

Recently Issued Accounting Pronouncements Not Yet Adopted

In October 2021, the Financial Accounting Standards Board issued ASU 2021-08, Business Combinations (Topic 805): (“ASU 2021-08”): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers. ASU 2021-08 amends Topic 805 to require the acquirer in a business combination to record contract assets and contract liabilities in accordance with Revenue from Contracts with Customers (Topic 606) at acquisition as if it had originated the contract, rather than at fair value. This update is effective for public companies beginning after December 15, 2022, with early adoption permitted. Adoption should be applied prospectively to business combinations occurring on or after the effective date of the amendments unless early adoption occurs during an interim period in which other application rules apply. We do not expect the adoption of this update to have a material impact to our financial statements.

8

Note 3 – Acquisition

Acquisition of Lonestar Resources

On October 5, 2021 (the “Closing Date”), the Company acquired Lonestar Resources US Inc., a Delaware corporation (“Lonestar”), as a result of which Lonestar and its subsidiaries became wholly-owned subsidiaries of the Company (the “Lonestar Acquisition”). The Lonestar Acquisition was effected pursuant to the Agreement and Plan of Merger (the “Merger Agreement”), dated July 10, 2021, by and between the Company and Lonestar. In accordance with the terms of the Merger Agreement, Lonestar shareholders received 0.51 shares of the Company’s common stock for each share of Lonestar common stock held immediately prior to the effective time of the Lonestar Acquisition. Based on the closing price of the Company’s common stock on October 5, 2021 of $30.19, and in connection with the Lonestar Acquisition, the total value of the Company’s common stock issued to holders of Lonestar common stock, warrants and restricted stock units as applicable, was approximately $173.6 million.

The Lonestar Acquisition constituted a business combination and was accounted for using the acquisition method of accounting, with Ranger Oil being treated as the accounting acquirer. Under the acquisition method of accounting, the assets and liabilities of Lonestar and its subsidiaries were recorded at their respective preliminary fair values as of the date of completion of the Lonestar Acquisition. Although the purchase price allocation is substantially complete as of March 31, 2022, there may be further adjustments to oil and gas properties as we continue to gather information related to the evaluation of certain properties. We will finalize these amounts within one year subsequent to the closing date of the Lonestar Acquisition. During the three months ended March 31, 2022, there were no changes to the allocation presented in the 2021 Form 10-K.

We expensed $1.7 million in acquisition-related costs for the three months ended March 31, 2022 related to employee severance and change-in-control compensation costs and other integration related costs.

Pro Forma Operating Results (Unaudited)

The following unaudited pro forma condensed financial data for the three months ended March 31, 2021 was derived from the historical financial statements of the Company giving effect to the Lonestar Acquisition, as if it had occurred on January 1, 2020.

	Three Months Ended March 31, 2021
Total revenues	$	128,371
Net income (loss) attributable to common shareholders	$	(23,850)

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 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.

9

Performance obligations

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 90 days. The following table summarizes our accounts receivable by type as of the dates presented:

	March 31, 2022		December 31, 2021
Customers	$	132,760	$	96,195
Joint interest partners	21,518		21,755
Derivative settlements from counterparties	55		1,037
Other	275		18
Total	154,608		119,005
Less: Allowance for credit losses	(429)		(411)
Accounts receivable, net of allowance for credit losses	$	154,179	$	118,594

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 formally designated as hedges for accounting purposes. While the use of derivative instruments limits the risk of adverse commodity price and interest rate movements, such use may also limit the beneficial impact of future product revenues and interest expense from favorable commodity price and interest rate movements. From time to time, we may enter into incremental derivative contracts in order to increase the notional volume of production we are hedging, restructure existing derivative contracts or enter into other derivative contracts resulting in modification to the terms of existing contracts. In accordance with our internal policies, we do not utilize derivative instruments for speculative purposes.

For our commodity derivatives, we typically combine swaps, purchased put options, purchased call options, sold put options and sold call options in order to achieve various hedging objectives. Certain of these objectives result in combinations that operate as collars which include purchased put options and sold call options, three-way collars, which include purchased put options, sold put options and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap, among others.

10

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, 2022:

	2Q2022		3Q2022		4Q2022		1Q2023		2Q2023		3Q2023		4Q2023		1Q2024		2Q2024
NYMEX WTI Crude Swaps
Average Volume Per Day (bbl)	3,000		3,000		3,000		2,500		2,400		2,807		2,657		462		462
Weighted Average Swap Price ($/bbl)	$	74.12	$	73.01	$	69.20	$	54.40	$	54.26	$	54.92	$	54.93	$	58.75	$58.75
NYMEX WTI Crude Collars
Average Volume Per Day (bbl)	17,720		14,266		9,375		6,250		6,181		1,630		1,630
Weighted Average Purchased Put Price ($/bbl)	$	59.12	$	57.14	$	52.17	$	50.67	$	50.67	$	60.00	$	60.00
Weighted Average Sold Call Price ($/bbl)	$	77.01	$	81.13	$	67.57	$	65.65	$	65.65	$	76.12	$	76.12
NYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (bbl)	20,879		14,674		14,674
Weighted Average Swap Price ($/bbl)	$	1.120	$	1.172	$	1.172
NYMEX HH Swaps
Average Volume Per Day (MMBtu)	12,500		12,500		12,500		10,000		7,500
Weighted Average Swap Price ($/MMBtu)	$	3.727	$	3.745	$	3.793	$	3.620	$	3.690
NYMEX HH Collars
Average Volume Per Day (MMBtu)	13,187		13,043		13,043				11,538		11,413		11,413		11,538		11,538
Weighted Average Purchased Put Price ($/MMBtu)	$	2.500	$	2.500	$	2.500			$	2.500	$	2.500	$	2.500	$	2.500	$	2.328
Weighted Average Sold Call Price($/MMBtu)	$	3.220	$	3.220	$	3.220			$	2.682	$	2.682	$	2.682	$	3.650	$	3.000
OPIS Mt Belv Ethane Swaps
Average Volume per Day (gal)	28,022		27,717		27,717				98,901		34,239		34,239		34,615
Weighted Average Fixed Price ($/gal)	$	0.2500	$	0.2500	$	0.2500			$	0.2288	$	0.2275	$	0.2275	$	0.2275

_______________________

1    NYMEX WTI refers to New York Mercantile Exchange West Texas Intermediate that serves as the benchmark for crude oil. NYMEX HH refers to NYMEX Henry Hub that serves as the benchmark for natural gas. OPIS Mt Belv 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

As of March 31, 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 totals $300 million, with us paying a weighted average fixed rate of 1.36% on the notional amount, and the counterparties paying a variable rate equal to LIBOR through May 2022.

Financial Statement Impact of Derivatives

The impact of our derivative activities on income is included within Derivatives 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 (see Note 4) and Accounts payable and accrued liabilities (see Note 9) on the condensed consolidated balance sheets. The effects of derivative gains and (losses) and cash settlements are reported as adjustments to reconcile net loss to net cash provided by operating activities. These items are recorded within the Derivative contracts section of our condensed consolidated statements of cash flows under Net losses and Cash settlements and premiums paid, net.

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The following table summarizes the effects of our derivative activities for the periods presented:

	Three Months Ended March 31,
	2022		2021
Interest Rate Swap gains recognized in the condensed consolidated statements of operations	$	83	$	32
Commodity losses recognized in the condensed consolidated statements of operations	(167,970)		(44,400)
	$	(167,887)	$	(44,368)
Interest rate cash settlements recognized in the condensed consolidated statements of cash flows	$	(938)	$	(922)
Commodity cash settlements and premiums paid recognized in the condensed consolidated statements of cash flows	(28,470)		(6,247)
	$	(29,408)	$	(7,169)

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, 2022				December 31, 2021
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Interest rate contracts	Derivative assets/liabilities – current	$	—	$	458	$	—	$	1,480
Commodity contracts	Derivative assets/liabilities – current	9,631		148,550		11,478		48,892
Interest rate contracts	Derivative assets/liabilities – non-current	—		—		—		—
Commodity contracts	Derivative assets/liabilities – non-current	2,912		42,620		2,092		23,815
		$	12,543	$	191,628	$	13,570	$	74,187

As of March 31, 2022, we reported net commodity derivative liabilities of $178.6 million and net Interest Rate Swap liabilities of $0.5 million. The contracts associated with these positions are with eight counterparties for commodity derivatives and four counterparties for Interest Rate Swaps, all of which are investment grade financial institutions and are participants in 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.

Note 6 – Property and Equipment

The following table summarizes our property and equipment as of the dates presented: 

	March 31, 2022		December 31, 2021
Oil and gas properties:
Proved	$	2,412,399	$	2,327,686
Unproved	58,686		57,900
Total oil and gas properties	2,471,085		2,385,586
Other property and equipment 1	31,060		31,055
Total properties and equipment	2,502,145		2,416,641
Accumulated depreciation, depletion, amortization and impairments	(1,084,430)		(1,033,293)
Total property and equipment, net	$	1,417,715	$	1,383,348

_______________________

1     Excludes the corporate office building and related assets acquired in connection with the Lonestar Acquisition that were classified as Assets held for sale on the condensed consolidated balance sheets as of March 31, 2022 and December 31, 2021.

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Unproved property costs of $58.7 million and $57.9 million have been excluded from amortization as of March 31, 2022 and December 31, 2021, respectively. We transferred $0.7 million and $7.6 million of undeveloped leasehold costs, including capitalized interest, associated with proved undeveloped reserves, acreage unlikely to be drilled or expiring acreage, from unproved properties to the full cost pool during the three months ended March 31, 2022 and 2021, respectively. We capitalized internal costs of $1.4 million and $0.7 million and interest of $1.1 million and $0.8 million during the three months ended March 31, 2022 and 2021, respectively, in accordance with our accounting policies. Average depreciation, depletion and amortization per barrel of oil equivalent of proved oil and gas properties was $14.98 and $12.92 for the three months ended March 31, 2022 and 2021, respectively.

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”). Beginning in early 2020, certain events such as the COVID-19 pandemic and the decisions by the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, collectively “OPEC+”) negatively impacted the oil and gas industry with significant declines in crude oil prices and oversupply of crude oil. Over the past year, however, increased mobility, deployment of vaccines and other factors have resulted in increased oil demand and commodity prices. A high level of uncertainty remains regarding the volatility of energy supply and demand as a result of OPEC’s continued strategy to increase production as well as the Russia-Ukraine conflict and related sanctions which began in the first quarter of 2022. WTI crude oil prices have surged, closing at over $120 per bbl during first quarter 2022 due to concerns that it might result in significant oil supply shortages. Because the Ceiling Test utilizes commodity prices based on a trailing 12 month average, the decline in commodity prices in the first quarter of 2021 as a result of COVID-19 and macroeconomic factors resulted in impairments of our oil and gas properties of $1.8 million during the three months ended March 31, 2021. We did not record any impairments of our oil and gas properties during the three months ended March 31, 2022.

Note 7 – Long-Term Debt

The following table summarizes our debt obligations as of the dates presented:

	March 31, 2022		December 31, 2021
Credit Facility	$	128,000	$	208,000
9.25% Senior Notes due 2026	400,000		400,000
Mortgage debt 1	8,391		8,438
Other 2	322		2,516
Total	536,713		618,954
Less: Unamortized discount 3	(3,560)		(3,720)
Less: Unamortized deferred issuance costs 3, 4	(9,448)		(9,853)
Total, net	$	523,705	$	605,381
Less: Current portion	(1,925)		(4,129)
Long-term debt	$	521,780	$	601,252

_______________________

1     The mortgage debt relates to the corporate office building and related assets acquired in connection with the Lonestar Acquisition for which assets are held as collateral for such debt. As of March 31, 2022 and December 31, 2021, these assets met the held for sale criteria and were classified as Assets held for sale on the condensed consolidated balance sheets.

2     Other debt of $2.2 million was extinguished during the three months ended March 31, 2022 and recorded as a gain on extinguishment of debt.

3     The discount and issuance costs of the 9.25% Senior Notes due 2026 are being amortized over its respective term using the effective-interest method.

4     Excludes issuance costs associated with the Credit Facility, which 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, 2022, the Credit Facility had a $1.0 billion revolving commitment and a $725 million borrowing base with aggregate elected commitments of $400 million, and a $25 million sublimit for the issuance of letters of credit. Availability under the Credit Facility may not exceed the lesser of the aggregate elected commitments or the borrowing base less outstanding advances and letters of credit. The borrowing base under the Credit Facility is redetermined semi-annually, generally in the Spring and Fall of each year. Our next borrowing base redetermination is scheduled in May 2022. 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.

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The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 1.50% to 2.50%, determined based on the utilization level under the Credit Facility or (b) a Eurodollar rate, including LIBOR through 2023, plus an applicable margin ranging from 2.50% to 3.50%, determined based on the utilization level under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on Eurodollar borrowings is payable every one, three or six months, at the election of the borrower, and is computed on the basis of a year of 360 days. As of March 31, 2022, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 3.02%. Unused commitment fees are charged at a rate of 0.50%.

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, 2022, we had $128.0 million in outstanding borrowings and $0.7 million in outstanding letters of credit under the Credit Facility. Factoring in the outstanding letters of credit, we had $271.3 million of availability under the Credit Facility as of March 31, 2022. During the three months ended March 31, 2021, we incurred and capitalized approximately $0.4 million of issue costs associated with amendments to the Credit Facility.

9.25% Senior Notes due 2026

On August 10, 2021, our indirect, wholly-owned subsidiary Penn Virginia Escrow LLC (the “Escrow Issuer”) completed an offering of $400 million aggregate principal amount of senior unsecured notes due 2026 (the “9.25% Senior Notes due 2026”) that bear interest at 9.25% and were sold at 99.018% of par. Obligations under the 9.25% Senior Notes due 2026 were assumed by Penn Virginia Holdings, LLC (“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 in part at specified redemption prices.

The indenture governing the 9.25% Senior Notes due 2026 also contains other customary affirmative and negative covenants as well as events of default and remedies.

As of March 31, 2022, we were in compliance with all debt covenants.

Note 8 – Income Taxes

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 is fully attributable to the State of Texas. Our net deferred income tax liability balance of $2.1 million as of March 31, 2022 is also fully attributable to the State of Texas and primarily related to property.

The income tax provision resulted in a benefit of $0.3 million for the three months ended March 31, 2021. 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 1.5%, which is fully attributable to the State of Texas.

We had no liability for unrecognized tax benefits as of March 31, 2022 and December 31, 2021. There were no interest and penalty charges recognized during the three months ended March 31, 2022 and 2021. Tax years from 2017 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.

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Note 9 – Supplemental Balance Sheet Detail

The following table summarizes components of selected balance sheet accounts as of the dates presented:

	March 31, 2022		December 31, 2021
Prepaid and other current assets:
Inventories 1	$	13,025	$	10,305
Prepaid expenses 2	2,964		10,693
	$	15,989	$	20,998
Other assets:
Deferred issuance costs of the Credit Facility, net of amortization	$	3,138	$	3,308
Right-of-use assets – operating leases	1,498		1,671
Other	—		38
	$	4,636	$	5,017
Accounts payable and accrued liabilities:
Trade accounts payable	$	32,463	$	32,452
Drilling and other lease operating costs	47,103		35,045
Revenue and royalties payable	110,493		95,521
Production, ad valorem and other taxes	12,224		7,905
Derivative settlements to counterparties	25,146		6,117
Compensation and benefits	7,957		13,942
Interest	5,003		15,321
Environmental remediation liability 3	2,277		2,287
Current operating lease obligations	891		914
Other	2,632		4,877
	$	246,189	$	214,381
Other non-current liabilities:
Asset retirement obligations	$	8,186	$	8,413
Non-current operating lease obligations	755		975
Postretirement benefit plan obligations	959		970
	$	9,900	$	10,358

_______________________

1    Includes tubular inventory and well materials of $12.2 million and $9.5 million and crude oil volumes in storage of $0.8 million and $0.8 million as of March 31, 2022 and December 31, 2021, respectively.

2 The balances as of March 31, 2022 and December 31, 2021 include $0.6 million and $9.6 million, respectively, for the prepayment of drilling and completion materials and services.

3 The balance as of March 31, 2022 and December 31, 2021 represents estimated costs associated with remediation activities for certain wells and tanks acquired as part of the Lonestar Acquisition.

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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, 2022 and December 31, 2021, the carrying values of the borrowings outstanding under our credit facilities approximate fair value as the borrowings bear interest at variables rates tied to current market rates and the applicable margins represent market rates. The fair value of our fixed rate 9.25% Senior Notes due 2026 is estimated based on the published market prices for issuances of similar risk and tenor and is categorized as Level 2 within the fair value hierarchy. As of March 31, 2022, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $536.7 million and $559.4 million, respectively. As of December 31, 2021, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $619.0 million and $634.6 million.

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, 2022
	Level 1		Level 2		Level 3		Total
Financial assets:
Commodity derivative assets – current	$	—	$	9,631	$	—	$	9,631
Commodity derivative assets – non-current	—		2,912		—		2,912
Total financial assets	$	—	$	12,543	$	—	$	12,543
Financial liabilities:
Interest rate swap liabilities – current	$	—	$	(458)	$	—	$	(458)
Commodity derivative liabilities – current	—		(148,550)		—		(148,550)
Commodity derivative liabilities – non-current	—		(42,620)		—		(42,620)
Total financial liabilities	$	—	$	(191,628)	$	—	$	(191,628)

	As of December 31, 2021
	Level 1		Level 2		Level 3		Total
Financial assets:
Commodity derivative assets – current	$	—	$	11,478	$	—	$	11,478
Commodity derivative assets – non-current	—		2,092		—		2,092
Total financial assets	$	—	$	13,570	$	—	$	13,570
Financial liabilities:
Interest rate swap liabilities – current	$	—	$	(1,480)	$	—	$	(1,480)
Commodity derivative liabilities – current	—		(48,892)		—		(48,892)
Commodity derivative liabilities – non-current	—		(23,815)		—		(23,815)
Total financial liabilities	$	—	$	(74,187)	$	—	$	(74,187)

We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below:

•Commodity derivatives: We determine the fair values of our commodity derivative instruments using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatilities, time value and non-performance risk. For the current market prices, we use third-party quoted forward prices, as applicable, for NYMEX WTI, MEH crude oil, NYMEX HH natural gas and OPIS Mt Belv Ethane natural gas liquids closing prices as of the end of the reporting periods. Each of these is a Level 2 input.

•Interest rate swaps: We determine the fair values of our interest rate swaps using an income approach valuation technique which discounts future cash flows back to a single present value. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these is a Level 2 input.

Non-performance risk is incorporated by utilizing discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is in a liability position. See Note 5 for additional details on our derivative instruments.

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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 AROs associated with the ongoing development of new oil and gas properties and certain share-based compensation awards. The determination of the fair value of AROs is based upon regional market and facility specific information. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these significant fair value inputs are typically not observable, we have categorized the initial estimates as Level 3 inputs.

Note 11 – Commitments and Contingencies

Drilling and Completion Commitments

As of March 31, 2022, we have a one year contract for one drilling rig and a contractual commitment on a pad-to-pad basis for one other drilling rig.

Gathering and Intermediate Transportation Commitments

We have long-term agreements that provide us with field gathering and intermediate pipeline transportation services for a majority of our crude oil and condensate production in Lavaca and Gonzales Counties, Texas. We also have volume capacity support for certain downstream interstate pipeline transportation. The following table provides details on these contractual arrangements as of March 31, 2022:

Description of contractual arrangement	Expiration of Contractual Arrangement	Minimum Volume Commitment (MVC) (bbl/d)	Expiration of Minimum Volume Commitment (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.

Under each of the arrangements, credits for deliveries of volumes in excess of the volume commitment may be applied to any deficiency arising in the succeeding 12-month period.

During the three months ended March 31, 2022 and 2021, we recorded expense of $10.2 million and $8.4 million, respectively, for these contractual obligations in connection with these arrangements.

Excluding the application of existing credits that we have earned during the preceding 12-month period ended March 31, 2022 for deliveries of volumes in excess of the volume commitment, and 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 2022, approximately $13.9 million per year for 2023 through 2025, $7.8 million for 2026, $3.8 million per year for 2027 through 2030 and $0.6 million for 2031.

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Crude Oil Storage

As of March 31, 2022, we had access to up to approximately 180,000 barrels of dedicated tank capacity for no additional charge at the service provider’s central delivery point facility (“CDP”), in Lavaca County, Texas through February 2041. In addition, we had access for up to a maximum of 340,000 barrels of tank capacity and evergreen month-to-month at several locations in the South Texas region comprised of (i) access to an additional 70,000 barrels of tank capacity at the CDP on a month-to-month basis, which can be terminated by either party with 45 days’ notice to the counterparty, (ii) crude oil storage capacity for up to 90,000 barrels with a downstream interstate pipeline at a facility in DeWitt County, Texas, on a month-to-month basis, which expired in April 2022, and (iii) an agreement with a marketing affiliate of the aforementioned downstream interstate pipeline to utilize up to 62,000 barrels of capacity within their system on a firm basis and an additional 120,000 barrels, if available, on a flexible basis that both expired in April 2022. Costs associated with these agreements are in the form of monthly fixed rate short-term leases and are charged as incurred on a monthly basis to GPT in our condensed consolidated statements of operations.

Other Agreements

We have a long-term dedication of certain specific leases to a crude purchase and throughput terminal agreement into 2032. Under the agreement, we have rights to transfer dedicated oil for delivery to a gulf coast terminal in Point Comfort, Texas or oil may be transferred at alternate locations to third parties and pay the terminal fee.

We have agreements that provide us with field gathering, compression and short-haul transportation services for our natural gas production and gas lift for our hydrocarbon production under various terms through 2039.

We also have agreements that provide us with services to process our wet gas production into NGL products and dry, or residue, gas. Several agreements covering the majority of our wet gas production extend beyond three years, including one 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, 2022 and December 31, 2021, 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, 2022 and December 31, 2021, we had AROs of approximately $8.2 million and $8.4 million attributable to the plugging of abandoned wells, respectively. Additionally, we had $2.3 million of environmental remediation liabilities assumed in the Lonestar Acquisition as of March 31, 2022 and December 31, 2021. 

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.

Note 12 – 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 (the “Plan”) for share-based compensation awards. A total of 762,259 RSUs and 484,197 PRSUs have been granted to employees and directors through March 31, 2022.

We recognized expense attributable to the RSUs and PRSUs of $0.9 million for the three months ended March 31, 2022 and $2.2 million, including approximately $1.9 million as a result of a change-in-control event associated with the Juniper Transactions for the three months ended March 31, 2021. We recognize share-based compensation expense as a component of G&A expenses in our condensed consolidated statements of operations.

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Time-Vested Restricted Stock Units

The table below summarizes activity for the three months ended March 31, 2022 with respect to awarded RSUs:

	Restricted Stock Units	Weighted-Average Grant Date Fair Value
Balance at beginning of year	230,517	$	9.20
Granted	—	—
Vested	(69,206)	(7.94)
Forfeited	—	—
Balance at end of year	161,311	$	10.52

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, 2022, we had $1.2 million of unrecognized compensation cost attributable to RSUs. We expect that cost to be recognized over a weighted-average period of 1.71 years.

Performance-Based Restricted Stock Units

During the three months ended March 31, 2022, we did not have any activity with respect to the PRSUs. As of March 31, 2022, a total of 345,069 PRSUs were unvested and outstanding.

Compensation expense for PRSUs with a market condition is being charged to expense on a straight-line basis for the 2021 grants and graded-vesting for the 2020 and 2019 grants, over a range of less than one to three years. Compensation expense for PRSUs with a performance condition is recognized on a straight-line basis 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 2021 PRSU grants are based 50% on the Company’s return on average capital employed (“ROCE”) relative to a defined peer group and 50% based on the Company’s absolute total shareholder return and total shareholder return (“TSR”) relative to a defined peer group over the three-year performance period. The 2021 PRSUs cliff vest from 0% to 200% of the original grant at the end of a three-year performance period based on satisfaction of the respective underlying conditions.

Vesting of PRSUs granted in 2020 and 2019 range from 0% to 200% of the original grant based on TSR relative to a defined peer group over the three 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 grants is derived by using a Monte Carlo model. The ranges for the assumptions used in the Monte Carlo model for the PRSUs granted during 2021, 2020 and 2019 are presented as follows:

	2021 1		2020 1		2019
Expected volatility	131.74% to 134.74%		101.32% to 117.71%		49.9	%
Dividend yield	0.0	%	0.0	%	0.0	%
Risk-free interest rate	0.22% to 0.29%		0.18% to 0.51%		1.66	%
Performance period	2021-2023		2020-2022		2020-2022

_______________________

1    One executive officer’s inducement award originally granted in August 2020 was amended in April 2021 to conform vesting conditions to other PRSU awards granted in 2021. The Monte Carlo assumptions for both years are included above.

As of March 31, 2022, we had $3.9 million of unrecognized compensation cost attributable to PRSUs. We expect that cost to be recognized over a weighted-average period of 1.94 years.

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Other Benefit Plans

We maintain the Penn Virginia Corporation and Affiliated Companies Employees 401(k) Plan (the “401(k) Plan”), a defined contribution plan, which covers substantially all of our employees. We recognized $0.2 million of expense attributable to the 401(k) Plan for both the three months ended March 31, 2022 and 2021. The charges for the 401(k) Plan are recorded 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, all of whom 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 and three months ended March 31, 2022 and 2021. The charges for these plans are recorded as a component of Other income (expense) in our condensed consolidated statements of operations.

Note 13 – Earnings Per Share

Basic net earnings (loss) per share is calculated by dividing the net income (loss) available to common shareholders, excluding net income or loss attributable to Noncontrolling interest, 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, par value $0.01 per share (“Class B Common Stock”) as applicable to the three months ended March 31, 2022 and Series A Preferred Stock, par value $0.01 per share (“Series A Preferred Stock”) as applicable to the three months ended March 31, 2021) held by the Noncontrolling interest in the Partnership are exchanged for common shares. Accordingly, our reported net income (loss) attributable to common shareholders is adjusted to reflect the reallocation of the net income (loss) attributable to the Noncontrolling interest assuming exchange of the Common Units (and shares of Class B Common Stock as applicable to the three months ended March 31, 2022 and Series A Preferred Stock as applicable to the three months ended March 31, 2021) 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,
	2022		2021
Net loss	$	(20,661)	$	(20,021)
Net loss attributable to Noncontrolling interest	10,676		6,449
Net loss attributable to common shareholders (basic)	(9,985)		(13,572)
Reallocation of Noncontrolling interest net loss	(10,676)		(6,449)
Net loss attributable to common shareholders (diluted)	$	(20,661)	$	(20,021)
Weighted-average shares – basic	21,107		15,263
Effect of dilutive securities:
Common Units and Series A Preferred Stock or Class B Common Stock, as applicable, that are exchangeable for common shares 1	—		—
RSUs and PRSUs	—		—
Weighted-average shares – diluted 2	21,107		15,263

_______________________

1    In connection with the Juniper Transactions in January 2021, we issued shares of Series A Preferred Stock. In October 2021, the Company effected a recapitalization and the Series A Preferred Stock were exchanged with Class B Common Stock and the designation of the Series A Preferred Stock was cancelled.

2    For the three months ended March 31, 2022, approximately 22.5 million potentially dilutive Common Units (and the associated 22.5 million Class B Common Stock) and 0.6 million of RSUs and PRSUs had the effect of being anti-dilutive and were excluded from the calculation of earnings per share. For the three months ended March 31, 2021, approximately 22.7 million potentially dilutive securities represented by approximately 22.5 million Common Units (and the associated approximately 0.2 million shares of Series A Preferred Stock) as well as approximately 0.2 million of RSUs and PRSUs had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per share.

20

Note 14 – Subsequent Events

Share Repurchase Program

On April 13, 2022, our Board of Directors approved a share repurchase program, under which the Company is authorized to repurchase up to $100 million of its outstanding Class A common stock. The share repurchase authorization was effective immediately and is valid through March 31, 2023.

The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions, or by other means in accordance with federal securities laws. The Company intends to fund repurchases from available working capital and cash provided by operating activities. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including among other things, our earnings, liquidity, capital requirements, financial condition, management’s assessment of the intrinsic value of the Class A Common Stock, the market price of the Company's Class A common stock, general market and economic conditions, available liquidity, compliance with the Company’s debt and other agreements (including maintaining a leverage ratio of no more than 1.0 to 1.0), applicable legal requirements and other factors deemed relevant. The exact number of shares to be repurchased by the Company is not guaranteed, and the program may be suspended, modified, or discontinued at any time without prior notice.

Acquisitions

On May 3, 2022, we entered into separate agreements to acquire “bolt-on” oil producing properties in the Eagle Ford shale contiguous to our existing assets for a total purchase price of approximately $64 million in cash, subject to customary adjustments. The transactions are expected to close early in the third quarter, subject to customary closing conditions.

21

Forward-Looking Statements

Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We use words such as “anticipate,” “guidance,” “assumptions,” “projects,” “estimates,” “expects,” “continues,” “intends,” “plans,” “believes,” “forecasts,” “future,” “potential,” “may,” “possible,” “could” and variations of such words or similar expressions to identify forward-looking statements. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following:

•risks related to the fourth quarter 2021 acquisition of Lonestar Resources US Inc, including the risk that the benefits of the acquisition may not be fully realized or may take longer to realize than expected, and that management attention will be diverted to integration-related issues;

•risks related to other completed acquisitions and dispositions, including our ability to realize their expected benefits;

•risks related to pending acquisitions, including the risk that the transactions may be delayed or not be consummated or the risk the transactions could distract management from ongoing business operations or cause us to incur substantial costs;

•the decline in, sustained market uncertainty of, and volatility of commodity prices for crude oil, natural gas liquids, or NGLs, and natural gas;

•the continued impact of the COVID-19 pandemic, including reduced demand for oil and natural gas, economic slowdown, governmental actions, stay-at-home order and interruptions to our operations or our customer’s operations, including as a result of any resurgence or new variant;

•risks related to and the impact of actual or anticipated other world health events;

•our ability to satisfy our short-term and long-term liquidity needs, including our ability to generate sufficient cash flows from operations or to obtain adequate financing, including access to the capital markets, to fund our capital expenditures and meet working capital needs;

•our ability to access capital, including through lending arrangements and the capital markets, as and when desired;

•negative events or publicity adversely affecting our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties;

•plans, objectives, expectations and intentions contained in this report that are not historical;

•our ability to execute our business plan in volatile commodity price environments;

•our ability to develop, explore for, acquire and replace oil and gas reserves and sustain production;

•changes to our drilling and development program;

•our ability to generate profits or achieve targeted reserves in our development operations;

•our ability to meet guidance, market expectations and internal projections, including type curves;

•any impairments, write-downs or write-offs of our reserves or assets;

•the projected demand for and supply of oil, NGLs and natural gas;

•our ability to contract for drilling rigs, frac crews, materials, supplies and services at reasonable costs;

•our ability to repurchase shares pursuant to our announced share repurchase program;

•our ability to renew or replace expiring contracts on acceptable terms;

•our ability to obtain adequate pipeline transportation capacity or other transportation for our oil and gas production at reasonable cost and to sell our production at, or at reasonable discounts to, market prices;

•the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from that estimated in our proved oil and gas reserves;

•use of new techniques in our development, including choke management and longer laterals;

•drilling, completion and operating risks, including adverse impacts associated with well spacing and a high concentration of activity;

•our ability to compete effectively against other oil and gas companies;

22

•leasehold terms expiring before production can be established and our ability to replace expired leases;

•environmental obligations, costs and liabilities that are not covered by an effective indemnity or insurance;

•the timing of receipt of necessary regulatory permits;

•the effect of commodity and financial derivative arrangements with other parties and counterparty risk related to the ability of these parties to meet their future obligations;

•the occurrence of unusual weather or operating conditions, including force majeure events;

•our ability to retain or attract senior management and key employees;

•our reliance on a limited number of customers and a particular region for substantially all of our revenues and production;

•compliance with and changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters;

•physical, electronic and cybersecurity breaches;

•risks relating to our organizational structure, including the Partnership’s obligations with respect to tax distributions;

•uncertainties and economic events relating to general domestic and international economic and political conditions, such as political tensions or war;

•the impact and costs associated with litigation or other legal matters;

•sustainability initiatives; and

•other factors set forth in our periodic filings with the Securities and Exchange Commission, or SEC, including the risks set forth in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2021.

Additional information concerning these and other factors can be found in our press releases and public filings with the SEC. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable law.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the financial condition and results of operations of Ranger Oil Corporation and its consolidated subsidiaries (“Ranger,” “Ranger Oil,” the “Company,” “we,” “us” or “our”) should be read in conjunction with our condensed consolidated financial statements and notes thereto included in Part I, Item 1, “Financial Statements.” All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated. Also, due to the combination of different units of volumetric measure, the number of decimal places presented and rounding, certain results may not calculate explicitly from the values presented in the tables. Certain amounts for the prior period have been reclassified to conform to the current period presentation. References to “quarters” represent the three months ended March 31, 2022 or 2021, as applicable.

This section of the Form 10-Q discusses the results of operations for the quarter ended March 31, 2022 compared to the quarter ended March 31, 2021 unless otherwise indicated. On October 5, 2021, the Company acquired Lonestar Resources US Inc., a Delaware corporation (“Lonestar”), as a result of which Lonestar and its subsidiaries became wholly-owned subsidiaries of Ranger Oil (the “Lonestar Acquisition”). The results of operations of Lonestar are reflected in our accompanying condensed consolidated financial statements for the quarter ended March 31, 2022. Results for the quarter ended March 31, 2021 reflect the financial and operating results of Ranger Oil and do not include the financial and operating results of Lonestar. As such, our historical results of operations are not comparable from period to period.

23

Overview and Executive Summary

We are an independent oil and gas company focused on the onshore development and production of crude 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 in South Texas.

Recent Developments

On April 13, 2022, our Board of Directors approved a share repurchase program, under which the Company is authorized to repurchase up to $100 million of its outstanding Class A common stock through March 31, 2023. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions, or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including among other things, our earnings, liquidity, capital requirements, financial condition, management’s assessment of the intrinsic value of the Class A Common Stock, the market price of the Company's Class A Common Stock, general market and economic conditions, available liquidity, compliance with the Company’s debt and other agreements (including maintaining a leverage ratio of no more than 1.0 to 1.0), applicable legal requirements and other factors deemed relevant and may be discontinued at any time.

On May 3, 2022, we entered into separate agreements to acquire “bolt-on” oil producing properties in the Eagle Ford shale contiguous to our existing assets for a total purchase price of approximately $64 million in cash, subject to customary adjustments. The transactions are expected to close early in the third quarter, subject to customary closing conditions.

Industry Environment and Recent Operating and Financial Highlights

Commodity Price and Other Economic Conditions

As an oil and gas development and production company, we are exposed to a number of risks and uncertainties that are inherent to our industry. In addition to such industry-specific risks, the global public health crisis associated with COVID-19 created uncertainty for global economic activity. Beginning in March 2020, the slowdown in global economic activity attributable to COVID-19 resulted in a dramatic decline in the demand for energy, which directly impacted our industry and the Company. Over the past year, however, increased mobility, deployment of vaccines and other factors have resulted in increased oil demand and commodity prices.

A high level of uncertainty remains regarding the volatility of energy supply and demand as the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, collectively “OPEC+”) continued to execute its strategy throughout 2021 to gradually increase production. In its most recent March 2022 meeting, OPEC+ reconfirmed the agreement to increase output targets each month by 432,000 bbl/day beginning May 1, 2022. Most recently, WTI crude oil prices have surged, closing at over $120 per bbl during first quarter 2022 as a result of the Russia-Ukraine conflict and related sanctions and concerns that it might result in significant oil supply shortages. In response, governmental authorities have implemented, and are expected to continue to implement, measures to address rising crude oil prices, including releasing emergency oil reserves. Higher energy prices, along with the global supply chain issues and other factors, have increased inflationary pressures, which has led or may lead to increased costs of services and certain materials necessary for our operations.

Our crude oil production is sold at a premium or deduct differential to the prevailing NYMEX West Texas Intermediate (“NYMEX WTI”) price. The differential reflects adjustments for location, quality and transportation and gathering costs, as applicable. All of our crude oil volumes are sold under Magellan East Houston (“MEH”) pricing, which historically has been at a premium to NYMEX WTI.

Similar to crude prices, Natural gas prices have jumped substantially as a result of the Russia-Ukraine conflict, with NYMEX Henry Hub (“NYMEX HH”) closing well over $5.00 per Mcf during first quarter 2022, which is the highest level in more than a decade. Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity, and supply and demand relationships in that region or locality. Similar to crude oil, our natural gas production price has a premium or deduct differential to the prevailing NYMEX HH price primarily due to differential adjustments for the location and the energy content of the natural gas. Location differentials result from variances in natural gas transportation costs based on the proximity of the natural gas to its major consuming markets that correspond with the ultimate delivery point as well as individual interaction of supply and demand.

A summary of these pricing differentials is provided in the discussion of “Results of Operations – Realized Differentials” that follows.

In addition to the volatility of commodity prices, we are subject to inflationary and other factors that have resulted in higher costs for products, materials and services that we utilize in both our capital projects and with respect to our operating expenses. In 2021, we took certain actions with vendors and other service providers to secure products and services at fixed prices and to pay for certain materials and services in advance in order to lock in favorable costs but we have continued to experience higher costs and this may be exacerbated in the future.

24

Capital Expenditures, Development Progress and Production

During the three months ended March 31, 2022, we operated two drilling rigs and incurred capital expenditures of approximately $83.5 million, of which $82.8 million was directed to drilling and completion projects. During the first quarter 2022, a total of 14 gross (8.9 net) wells were completed and turned in line. During the second quarter of 2022, we entered into a contract to operate a spot drilling rig.

As of April 28, 2022, we had approximately 170,800 gross (139,900 net) acres in the Eagle Ford, net of expirations, of which approximately 95% is held by production.

Total sales volume for the first quarter 2022 was 3,398 thousand barrels of oil equivalent (“Mboe”), or 37,752 barrels of oil equivalent (“boe”) per day, with approximately 71%, or 2,428 thousand barrels of oil (“Mbbl”), of sales volume from crude oil, 15% from NGLs and 14% from natural gas.

Commodity Hedging Program

As of April 28, 2022, we have hedged a portion of our estimated future crude oil and natural gas production from April 1, 2022 through the first half of 2024. The following table summarizes our net hedge position for the periods presented:

	2Q2022		3Q2022		4Q2022		1Q2023		2Q2023		3Q2023		4Q2023		1Q2024		2Q2024
NYMEX WTI Crude Swaps
Average Volume Per Day (bbl)	3,000		3,000		3,000		2,500		2,400		2,807		2,657		462		462
Weighted Average Swap Price ($/bbl)	$	74.12	$	73.01	$	69.20	$	54.40	$	54.26	$	54.92	$	54.93	$	58.75	$58.75
NYMEX WTI Crude Collars
Average Volume Per Day (bbl)	17,720		14,266		9,375		6,250		6,181		1,630		1,630
Weighted Average Purchased Put Price ($/bbl)	$	59.12	$	57.14	$	52.17	$	50.67	$	50.67	$	60.00	$	60.00
Weighted Average Sold Call Price ($/bbl)	$	77.01	$	81.13	$	67.57	$	65.65	$	65.65	$	76.12	$	76.12
NYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (bbl)	20,879		7,337		1,630
Weighted Average Swap Price ($/bbl)	$	1.120	$	1.172	$	1.020
NYMEX HH Swaps
Average Volume Per Day (MMBtu)	12,500		12,500		12,500		10,000		7,500
Weighted Average Swap Price ($/MMBtu)	$	3.727	$	3.745	$	3.793	$	3.620	$	3.690
NYMEX HH Collars
Average Volume Per Day (MMBtu)	13,187		15,679		14,511		6,417		11,538		11,413		11,413		11,538		11,538
Weighted Average Purchased Put Price ($/MMBtu)	$	2.500	$	3.088	$	2.854	$	6.000	$	2.500	$	2.500	$	2.500	$	2.500	$	2.328
Weighted Average Sold Call Price($/MMBtu)	$	3.220	$	4.141	$	3.791	$	10.000	$	2.682	$	2.682	$	2.682	$	3.650	$	3.000
OPIS Mt Belv Ethane Swaps
Average Volume per Day (gal)	28,022		27,717		27,717				98,901		34,239		34,239		34,615
Weighted Average Fixed Price ($/gal)	$	0.2500	$	0.2500	$	0.2500			$	0.2288	$	0.2275	$	0.2275	$	0.2275

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Results of Operations

The following table sets forth certain historical summary operating and financial statistics for the periods presented: 

	Three Months Ended
	March 31, 2022			December 31, 2021			March 31, 2021
Total sales volume (Mboe) 1	3,398			3,702			1,848
Average daily sales volume (boe/d) 1	37,752			40,236			20,534
Crude oil sales volume (Mbbl) 1	2,428			2,532			1,469
Crude oil sold as a percent of total 1	71		%	68		%	80		%
Product revenues	$	255,599		$	224,594		$	88,308
Crude oil revenues	$	226,732		$	191,079		$	81,913
Crude oil revenues as a percent of total	89		%	85		%	93		%
Realized prices:
Crude oil ($/bbl)	$	93.38		$	75.48		$	55.76
NGLs ($/bbl)	$	33.40		$	29.91		$	16.95
Natural gas ($/Mcf)	$	4.32		$	4.54		$	2.80
Aggregate ($/boe)	$	75.23		$	60.67		$	47.79
Realized prices, including effects of derivatives, net 2
Crude oil ($/bbl)	$	74.00		$	64.50		$	44.80
Natural gas ($/Mcf)	$	3.96		$	2.99		$	2.84
Aggregate ($/boe)	$	61.08		$	51.77		$	39.10
Production and lifting costs:
Lease operating ($/boe)	$	5.33		$	4.38		$	4.78
Gathering, processing and transportation ($/boe)	$	2.66		$	2.19		$	2.53
Production and ad valorem taxes ($/boe)	$	3.87		$	3.05		$	2.98
General and administrative ($/boe) 3	$	2.88		$	9.57		$	7.13
Depreciation, depletion and amortization ($/boe)	$	14.98		$	12.97		$	12.92

_______________________

1    All volumetric statistics presented above represent volumes of commodity production that were sold during the periods presented. Volumes of crude oil physically produced in excess of volumes sold are placed in temporary storage to be sold in subsequent periods.

2    Realized prices, including effects of derivatives, net is a non-GAAP measure (see discussion and reconciliation to GAAP measure below in “Results of Operations – Effects of Derivatives” that follows).

3    Includes combined amounts of $0.79, $7.57 and $3.86 per boe for the three months ended March 31, 2022, December 31, 2021 and March 31, 2021, respectively, attributable to share-based compensation and significant special charges, comprised of organizational restructuring, acquisition and integration costs and strategic transaction costs, including costs attributable to the Lonestar Acquisition during the first quarter 2022 and fourth quarter 2021 periods and a change-in-control event during the first quarter of 2021 as described in the discussion of “Results of Operations - General and Administrative” that follows.

26

Sequential Quarterly Analysis

The following summarizes our key operating and financial highlights for the three months ended March 31, 2022, with comparison to the three months ended December 31, 2021. The year-over-year highlights for the quarterly periods ended March 31, 2022 and 2021 are addressed in further detail in the discussions that follow below in Year over Year Analysis of Operating and Financial Results.

•Daily sales volume decreased to 37,752 boe per day from 40,236 boe per day with 8.9 net wells turned in line for the first quarter 2022 compared to 10.4 net wells turned in line for the fourth quarter 2021. Total sales volume decreased 8% to 3,398 Mboe from 3,702 Mboe.

•Product revenues increased 14% to $255.6 million from $224.6 million as a result of 24% higher crude oil realized prices, or $43.5 million, coupled with lower crude oil sales volume, or $7.8 million. NGL revenues were lower due to 18% lower sales volume, or $3.4 million, although realized prices were 12% higher, or $1.7 million. Natural gas revenues were 20% lower as a result of 5% lower realized prices and 16% lower volume for an overall decrease of $3.0 million.

•Production and lifting costs, consisting of Lease operating expenses (“LOE”) and Gathering, processing and transportation expenses (“GPT”), increased on an absolute basis and per unit basis to $27.1 million and $7.99 per boe from $24.3 million and $6.57 per boe due primarily to the impact of the Lonestar Acquisition, partially offset by the effects of 8% lower sales volume.

•Production and ad valorem taxes increased on an absolute and per unit basis to $13.1 million and $3.87 per boe from $11.3 million and $3.05 per boe, respectively, due to the overall effects of 24% higher aggregate realized product pricing, coupled with higher estimated ad valorem tax assessments in 2022.

•General and administrative (“G&A”) expenses decreased on an absolute and per unit basis to $9.8 million and $2.88 per boe from $35.4 million and $9.57 per boe, respectively, primarily due to less acquisition and integration costs associated with the Lonestar Acquisition of $1.7 million incurred during the first quarter 2022 compared to $27.0 million during the fourth quarter 2021.

•Depreciation, depletion and amortization (“DD&A”) increased on an absolute and per unit basis to $50.9 million and $14.98 per boe during the first quarter 2022 as compared to $48.0 million and $12.97 per boe during the fourth quarter 2021 due primarily to higher development costs.

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Year over Year Analysis of Operating and Financial Results

Sales Volume

The following tables set forth a summary of our total and average daily sales volumes by product for the periods presented: 

	Three Months Ended March 31,
Total Sales Volume 1	2022	2021	Change	% Change
Crude oil (Mbbl and bbl/d)	2,428	1,469	959	65	%
NGLs (Mbbl and bbl/d)	501	210	291	139	%
Natural gas (MMcf and MMcf/d)	2,810	1,013	1,797	177	%
Total (Mboe and boe/d)	3,398	1,848	1,550	84	%
	Three Months Ended March 31,
Average Daily Sales Volume 1	2022	2021	Change	% Change
Crude oil (Mbbl and bbl/d)	26,980	16,324	10,656	65	%
NGLs (Mbbl and bbl/d)	5,568	2,335	3,233	138	%
Natural gas (MMcf and MMcf/d)	31	11	20	182	%
Total (Mboe and boe/d)	37,752	20,534	17,218	84	%

_______________________

1    All volumetric statistics represent volumes of commodity production that were actually sold during the periods presented. Volumes of crude oil physically produced in excess of volumes sold are placed in temporary storage to be sold in subsequent periods.

Total sales volume increased 84% during the three months ended March 31, 2022 when compared to the corresponding period in 2021 as a result of the Lonestar Acquisition that closed in fourth quarter of 2021 and increased drilling activity throughout 2021.

Approximately 71% of total sales volume during the three month periods in 2022 was attributable to crude oil when compared to approximately 80% during the corresponding periods in 2021. The decrease in the crude oil composition of total sales volume is due primarily to higher gas content of the wells acquired in the Lonestar Acquisition.

Product Revenues and Prices

The following tables set forth a summary of our revenues and prices per unit of volume by product for the periods presented:

	Three Months Ended March 31,
Total Product Revenues	2022		2021		Change		% Change
Crude oil	$	226,732	$	81,913	$	144,819	177	%
NGLs	16,740		3,562		13,178		370	%
Natural gas	12,127		2,833		9,294		328	%
Total	$	255,599	$	88,308	$	167,291	189	%
Product Revenues per Unit of	Three Months Ended March 31,
Volume ($ per unit of volume)	2022		2021		Change		% Change
Crude oil	$	93.38	$	55.76	$	37.62	67	%
NGLs	$	33.40	$	16.95	$	16.45	97	%
Natural gas	$	4.32	$	2.80	$	1.52	54	%
Total	$	75.23	$	47.79	$	27.44	57	%

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The following table provides an analysis of the changes in our revenues for the periods presented:

	Three Months Ended March 31, 2022 vs. 2021
	Revenue Variance Due to
	Volume		Price		Total
Crude oil	$	53,472	$	91,347	$	144,819
NGLs	4,934		8,244		13,178
Natural gas	5,029		4,265		9,294
	$	63,435	$	103,856	$	167,291

Our product revenues during the three month period in 2022 increased compared to the corresponding period in 2021 due to significantly higher prices from continued economic recovery, as well as supply concerns resulting from the Russia-Ukraine conflict as compared to the prior year. These factors resulted in an increase to the NYMEX WTI benchmark price of 63% for the three months ended March 31, 2022, as compared to the corresponding period in 2022. Also contributing to the higher product revenues was an increase in volumes across all commodities due to the Lonestar Acquisition, with an overall increase in Mboe of 84%.

Realized Differentials

The following table reconciles our realized price differentials from average NYMEX-quoted prices for WTI crude oil and HH natural gas for the periods presented:

	Three Months Ended March 31,
	2022		2021		Change		% Change
Realized crude oil prices ($/bbl)	$	93.38	$	55.76	$	37.62	67	%
Average WTI prices	95.01		58.14		36.87		63	%
Realized differential to WTI	$	(1.63)	$	(2.38)	$	0.75	(32)	%
Realized natural gas prices ($/Mcf)	$	4.32	$	2.80	$	1.52	54	%
Average HH prices ($/MMBtu)	4.60		3.38		1.22		36	%
Realized differential to HH	$	(0.28)	$	(0.58)	$	0.30	(52)	%

Our differential to NYMEX WTI for the three months ended March 31, 2022 improved by 32% compared to the corresponding period in 2021 due to more favorable NYMEX Calendar Month Average contractual pricing component and more favorable pricing negotiated with certain new crude purchasers effective early in first quarter 2022. Our differential to NYMEX HH also improved for the three months ended March 31, 2022 due to more favorable location basis differentials. See also the discussion of Commodity Price and Other Economic Conditions in the Overview above.

Effects of Derivatives

We present realized prices for crude oil and natural gas, as adjusted for the effects of derivatives, net as we believe these measures are useful to management and stakeholders in determining the effectiveness of our price-risk management program that is designed to reduce the volatility associated with our operations. Realized prices for crude oil and natural gas, as adjusted for the effects of derivatives, net, are supplemental financial measures that are not prepared in accordance with generally accepted accounting principles (“GAAP”).

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The following table presents the calculation of our non-GAAP realized prices for crude oil and natural gas, as adjusted for the effects of derivatives, net and reconciles to realized prices for crude oil and natural gas determined in accordance with GAAP: 

	Three Months Ended March 31,
	2022		2021		Change		% Change
Realized crude oil prices ($/bbl)	$	93.38	$	55.76	$	37.62	67	%
Effects of derivatives, net ($/bbl)	(19.38)		(10.96)		(8.42)		77	%
Crude oil realized prices, including effects of derivatives, net ($/bbl)	$	74.00	$	44.80	$	29.20	65	%
Realized natural gas prices ($/Mcf)	$	4.32	$	2.80	$	1.52	54	%
Effects of derivatives, net ($/Mcf)	(0.36)		0.04		(0.40)		(1000)	%
Natural gas realized prices, including effects of derivatives, net ($/Mcf)	$	3.96	$	2.84	$	1.12	39	%

Effects of derivatives, net include, as applicable to the period presented: (i) current period commodity derivative settlements; (ii) the impact of option premiums paid or received in prior periods related to current period production; (iii) the impact of prior period cash settlements of early-terminated derivatives originally designated to settle against current period production; (iv) the exclusion of option premiums paid or received in current period related to future period production; and (v) the exclusion of the impact of current period cash settlements for early-terminated derivatives originally designated to settle against future period production.

Other operating income, net

Other operating income, net includes fees for marketing and water disposal services that we charge to third parties, net of related expenses, as well as other miscellaneous revenues and credits attributable to our current operations and gains and losses on the sale or disposition of assets other than our oil and gas properties. In addition, charges attributable to credit losses associated with our trade and joint venture partner receivables are netted within this caption.

The following table sets forth the total Other operating income, net recognized for the periods presented:

	Three Months Ended March 31,
	2022		2021		Change		% Change
Other operating income, net	$	856	$	247	$	609	247	%

Our marketing fee income increased in the three month period in 2022 as compared to the corresponding period in 2021 due primarily to the higher commodity-based pricing and gain on sales of field materials.

Lease Operating Expenses

LOE includes costs that we incur to operate our producing wells and field operations. The most significant costs include compression and gas lift, chemicals, water disposal, repairs and maintenance, including down-hole repairs, field labor, pumping and well-tending, equipment rentals, utilities and supplies, among others.

The following table sets forth our LOE for the periods presented:

	Three Months Ended March 31,
	2022		2021		Change		% Change
Lease operating	$	18,102	$	8,825	$	9,277	105	%
Per unit ($/boe)	$	5.33	$	4.78	$	0.55	12	%

LOE increased on an absolute basis and per unit basis during the three month period in 2022 when compared to the corresponding period in 2021 due primarily to the impact of the Lonestar Acquisition, increased field labor and variable costs driven by higher sales volume.

Gathering, Processing and Transportation

GPT expense includes costs that we incur to gather and aggregate our crude oil and natural gas production from our wells and deliver them via pipeline or truck to a central delivery point, downstream pipelines or processing plants, and blend or process, as necessary, depending upon the type of production and the specific contractual arrangements that we have with the applicable midstream operators. In addition, GPT expense includes short-term rental charges for crude oil storage tanks.

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The following table sets forth our GPT expense for the periods presented:

	Three Months Ended March 31,
	2022		2021		Change		% Change
GPT	$	9,040	$	4,674	$	4,366	93	%
Per unit ($/boe)	$	2.66	$	2.53	$	0.13	5	%

GPT expense increased on an absolute basis and per unit basis during the three month period in 2022 as compared to the corresponding period in 2021 due primarily to the impact of the Lonestar Acquisition, which contributed to the 177% higher natural gas sales volumes and 65% higher crude oil sales volumes. Additionally, for certain of our crude oil volumes gathered, 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. As such, with the higher prices during first quarter 2022 compared to first quarter 2021, we incurred higher gathering costs associated with these volumes. These unfavorable variances were partially offset by the effects of an increase in the mix of crude oil volume sold at the wellhead, including the majority of crude oil volumes from the acquired Lonestar wells, resulting in reduced transportation costs and cost per unit.

Production and Ad Valorem Taxes

Production or severance taxes represent taxes imposed by the states in which we operate for the removal of resources including crude oil, NGLs and natural gas. Ad valorem taxes represent taxes imposed by certain jurisdictions, primarily counties in which we operate, based on the assessed value of our operating properties. The assessments for ad valorem taxes are generally based on published index prices.

The following table sets forth our production and ad valorem taxes for the periods presented:

	Three Months Ended March 31,
	2022			2021			Change			% Change
Production/severance taxes	$	11,570		$	4,242		$	7,328		173	%
Ad valorem taxes	1,570			1,271			299			24	%
	$	13,140		$	5,513		$	7,627		138	%
Per unit ($/boe)	$	3.87		$	2.98		$	0.89		30	%
Production/severance tax rate as a percent of product revenues	4.5		%	4.8		%	(0.3)		%	—	%

Production and Ad Valorem taxes increased on an absolute basis and per unit basis during the three month period in 2022 when compared to the corresponding period in 2021 due primarily to the impact of the Lonestar Acquisition. Additionally, Production taxes increased on an absolute and per unit basis due to higher aggregate commodity sales prices during the three month period in 2022.

General and Administrative

Our G&A expenses include employee compensation, benefits and other related costs for our corporate management and governance functions, rent and occupancy costs for our corporate facilities, insurance, and professional fees and consulting costs supporting various corporate-level functions, among others. In order to facilitate a meaningful discussion and analysis of our results of operations with respect to G&A expenses, we have disaggregated certain costs into three components as presented in the table below. Primary G&A encompasses all G&A costs except share-based compensation and certain significant special charges that are generally attributable to material stand-alone transactions or corporate actions that are not otherwise in the normal course.

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The following table sets forth the components of our G&A expenses for the periods presented:

	Three Months Ended March 31,
	2022		2021		Change		% Change
Primary G&A expenses	$	7,112	$	6,037	$	1,075	18	%
Share-based compensation	924		2,246		(1,322)
Significant special charges:							100	%
Organizational restructuring, including severance	—		239		(239)		(100)	%
Acquisition/integration and strategic transaction costs	1,743		4,655		(2,912)		(63)	%
Total G&A expenses	$	9,779	$	13,177	$	(3,398)	(26)	%
Per unit ($/boe)	$	2.88	$	7.13	$	(4.25)	(60)	%
Per unit ($/boe) excluding share-based compensation and other significant special charges identified above	$	2.09	$	3.27	$	(1.18)	(36)	%

Our total G&A expenses were lower on an absolute and per unit basis during the three month period in 2022 when compared to the corresponding period in 2021 due to lower costs incurred in first quarter 2022 for the Lonestar Acquisition integration related costs than the costs incurred in first quarter 2021 associated with the Juniper Transactions, as well as lower share-based compensation cost due to the incremental $1.9 million charge during first quarter 2021 discussed below. These decreases were partially offset by higher salaries and wages in 2022, primarily driven by increased headcount.

Our primary G&A expenses increased on an absolute basis during the three month period in 2022 when compared to the corresponding period in 2021 due primarily to increased headcount following the Lonestar Acquisition and the impact of salary increases effective January 1, 2022. Primary G&A expenses decreased on a per unit basis due to higher overall sales volumes.

Share-based compensation charges during the periods presented are attributable to the amortization of compensation cost, net of forfeitures, associated with the grants of time-vested restricted stock units (“RSUs”), and performance-based restricted stock units (“PRSUs”). The grants of RSUs and PRSUs are described in greater detail in Note 12 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements.” As a result of the Juniper Transactions, all of the RSUs granted before 2019 vested and an incremental charge of approximately $1.9 million was recorded during the first quarter 2021. All of our share-based compensation represents non-cash expenses.

Depreciation, Depletion and Amortization

DD&A expense includes charges for the allocation of property costs based on the volume of production, depreciation of fixed assets other than oil and gas assets as well as the accretion of our asset retirement obligations.

The following table sets forth total and per unit costs for DD&A expense for the periods presented:

	Three Months Ended March 31,
	2022		2021		Change		% Change
DD&A expense	$	50,893	$	23,884	$	27,009	113	%
DD&A rate ($/boe)	$	14.98	$	12.92	$	2.06	16	%

DD&A expense increased on an absolute and a per unit basis during the three month period in 2022 when compared to the corresponding period in 2021. Higher production volume provided for an increase of $20.0 million and a higher DD&A rate resulted in an increase of $7.0 million for first quarter 2022. The higher DD&A rate in 2022 is primarily due to the Lonestar Acquisition, which contributed to an increase in our total proved reserves at a higher relative cost per boe as compared to the first quarter 2021.

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Impairment of Oil and Gas Properties

We assess our oil and gas properties on a quarterly basis based on the results of a comparison of the unamortized cost of our oil and gas properties, net of deferred income taxes, to the sum of our estimated after-tax discounted future net revenues from proved properties adjusted for costs excluded from amortization (the “Ceiling Test”) in accordance with the full cost method of accounting for oil and gas properties.

	Three Months Ended March 31,
	2022		2021		Change		% Change
Impairment of oil and gas properties	$	—	$	1,811	$	(1,811)	(100)	%

We did not record an impairment of our oil and gas properties during the three month period in 2022, compared to an impairment of $1.8 million recorded in the corresponding period in 2021. The impairment in 2021 was the result of the decline in the twelve-month average prices of crude oil, NGLs and natural gas as indicated by the respective quarterly Ceiling Test under the full cost method of accounting for oil and gas properties.

Interest Expense

Interest expense for the three month period in 2022 includes charges for outstanding borrowings under the Credit Facility derived from internationally recognized interest rates with a premium based on our credit profile and the level of credit outstanding and the contractual rate associated with the 9.25% Senior Notes due 2026. Also included are the amortization of issuance costs capitalized attributable to the Credit Facility and the 9.25% Senior Notes due 2026 and accretion of original issue discount (“OID”) on the 9.25% Senior Notes due 2026.

Interest expense for the three month period in 2021 includes charges for outstanding borrowings under the Credit Facility and the Second Lien Credit Agreement, dated September 29, 2017 (the “Second Lien Term Loan”) which was repaid in full in October 2021, as well as amortization of their respective issuance costs capitalized. Also included is the accretion of OID on the Second Lien Term Loan.

In addition, we are assessed certain fees for the overall credit commitments provided to us as well as fees for credit utilization and letters of credit. These costs are partially offset by interest amounts that we capitalize on unproved property costs while we are engaged in the evaluation of projects for the underlying acreage.

The following table summarizes the components of our interest expense for the periods presented:

	Three Months Ended March 31,
	2022		2021		Change		% Change
Interest on borrowings and related fees	$	10,957	$	5,632	$	5,325	95	%
Accretion of original issue discount	640		105		535		510	%
Amortization of debt issuance costs	160		506		(346)		(68)	%
Capitalized interest	(1,060)		(846)		(214)		25	%
Total interest expense, net of capitalized interest	$	10,697	$	5,397	$	5,300	98	%

The increase in interest expense during the three month period in 2022 is primarily attributable to interest incurred in the amount of $8.8 million for the 9.25% Senior Notes due 2026 and $1.7 million for the Credit Facility compared to interest incurred in the corresponding period in 2021 of $3.5 million for the Second Lien Term Loan and $1.9 million for the Credit Facility as well as increased amortization of OID compared to the corresponding period in 2021. These increases are partially offset by decreased amortization of debt issuance costs during the three month period in 2022 when compared to the corresponding period in 2021 and increased capitalized interest during the three month period in 2022, driven by higher overall weighted-average interest rate in 2022 as compared to the corresponding period in 2021.

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Derivatives

The gains and losses for our derivatives portfolio reflect changes in the fair value attributable to changes in market values relative to our hedged commodity prices and interest rates.

The following table summarizes the gains and (losses) attributable to our commodity derivatives portfolio and interest rate swaps for the periods presented:

	Three Months Ended March 31,
	2022		2021		Change		% Change
Commodity derivative losses	$	(167,970)	$	(44,400)	$	(123,570)	278	%
Interest rate swap gains	83		32		51		159	%
Total	$	(167,887)	$	(44,368)	$	(123,519)	278	%

In the three month period in 2022, commodity prices were significantly higher on an average aggregate basis than those during the corresponding periods in 2021. The derivative losses in the three month periods in 2022 and 2021 reflect the decline in the mark-to-market values consistent with the increase in prices attributable to open positions for both periods. Realized settlement payments, net for crude oil and natural gas derivatives were $28.5 million and $6.2 million during the three month periods in 2022 and 2021, respectively. We hedge a portion of our exposure to variable interest rates associated with our Credit Facility and, in first quarter 2021, our Second Lien Term Loan. For both the three month periods in 2022 and 2021, we paid $0.9 million of net settlements from our interest rate swaps.

Income Taxes

Income taxes represent our income tax provision as determined in accordance with generally accepted accounting principles. It considers taxes attributable to our obligations for federal taxes under the Internal Revenue Code as well as to the various states in which we operate, primarily Texas, or otherwise have continuing involvement.

The following table summarizes our income taxes for the periods presented:

	Three Months Ended March 31,
	2022			2021			Change			% Change
Income tax benefit	$	189		$	310		$	(121)		(39)	%
Effective tax rate	0.9		%	1.5		%	(0.6)		%	—	%

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 is fully attributable to the State of Texas. Our net deferred income tax liability balance of $2.1 million as of March 31, 2022 is also fully attributable to the State of Texas and primarily related to property.

The income tax provision resulted in a benefit of $0.3 million for the three months ended March 31, 2021. The federal and state tax expense was fully offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of 1.5% which was fully attributable to the State of Texas.

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Liquidity and Capital Resources

Liquidity

Our primary sources of liquidity include our cash on hand, cash provided by operating activities and borrowings under the Credit Facility. As of March 31, 2022, we had liquidity of $277.7 million, comprised of cash and cash equivalents of $6.4 million and availability under our Credit Facility of $271.3 million (factoring in letters of credit). The Credit Facility provides us up to $1.0 billion in borrowing commitments. The current borrowing base under the Credit Facility is $725.0 million with aggregate elected commitments of $400.0 million. The availability under the Credit Facility of $271.3 million remained unchanged as of April 28, 2022.

Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for crude oil, NGL and natural gas products, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity and other supply chain dynamics, among other factors. All of these factors have been impacted by the COVID-19 pandemic and the Russia-Ukraine conflict and related instability in the global energy markets. In order to mitigate this volatility, we utilize derivative contracts with a number of financial institutions, all of which are participants in our Credit Facility, hedging a portion of our estimated future crude oil, NGLs and natural gas production through the first half of 2024. The level of our hedging activity and duration of the financial instruments employed depends on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy.

From time-to-time and under market conditions that we believe are favorable to us, we may consider capital market transactions, including the offering of debt and equity securities. We maintain an effective shelf registration statement to allow for optionality.

Capital Resources

Our 2022 capital budget contemplates capital expenditures of up to approximately $435 million, of which approximately $425 million has been allocated to drilling and completion activities. We plan to fund our 2022 capital program and our operations for the next twelve months primarily with cash on hand, cash from operating activities and, to the extent necessary, supplemental borrowings under the Credit Facility. Based upon current price and production expectations, we believe that our cash on hand, cash from operating activities and borrowings under our Credit Facility, as necessary, will be sufficient to fund our capital spending and operations for at least the next twelve months; however, future cash flows are subject to a number of variables including the length and magnitude of the current global economic uncertainties associated with the COVID-19 pandemic and Russia-Ukraine conflict and related instability in the global energy markets.

Additionally, we have other obligations primarily consisting of our outstanding debt principal and interest obligations, derivative instruments, service agreements, operating leases, and asset retirement and environmental obligations, all of which are customary in our business. See Note 11 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for more details related to these obligations. The Partnership is also required in certain circumstances to make certain tax distributions to its partners, which may impact cash flow from operations for the Company, as discussed below under “Tax Distributions.”

Share Repurchase Program

In April 2022, we announced that the Board of Directors approved a share repurchase program under which we are authorized to repurchase up to $100 million of outstanding Class A Common Stock through March 31, 2023. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including management’s assessment of the intrinsic value of the Company’s shares, the market price of the Company's Class A common stock, general market and economic conditions, available liquidity, compliance with the Company’s debt and other agreements (including maintaining a leverage ratio of no more than 1.0 to 1.0), and applicable legal requirements. We expect to fund repurchases from available working capital and cash provided by operating activities.

Tax Distributions

Under its partnership agreement, the Partnership is required to make distributions to all of its limited partners pro rata on a quarterly basis and in such amounts as necessary to enable the Company to timely satisfy all of its U.S. federal, state and local and non-U.S. tax liabilities. Additionally, the Partnership is required to make advances to its non-corporate partners in an amount sufficient to enable such partner to timely satisfy its U.S. federal, state and local and non-U.S. tax liabilities (a “Tax Advance”). Any such Tax Advance will be treated as an advance against and, therefore, reduce any future distributions that such partner is otherwise entitled to receive. The Company’s cash flow from operations and ability to effect share repurchases or cash dividends to our stockholders could be adversely impacted as a result of such cash distributions. Whether and how much Tax Advances are required to be paid is dependent upon the amount and timing of taxable income generated in the future that is allocable to partners and the federal tax rates then applicable. We are unable to assess whether the Partnership will be required to make Tax Advances for the year ending December 31, 2022 or in future years.

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Cash Flows

The following table summarizes our cash flows for the periods presented:

	Three Months Ended March 31,
	2022		2021
Net cash provided by operating activities	133,835		32,687
Net cash used in investing activities	(70,517)		(34,754)
Net cash provided by (used in) financing activities	(80,641)		915
Net decrease in cash, cash equivalents and restricted cash	$	(17,323)	$	(1,152)

Cash Flows from Operating Activities. The increase of $101.1 million in net cash provided by operating activities for the three months ended March 31, 2022 compared to the corresponding period in 2021 was primarily attributable to the effect of cash receipts that were derived from higher average prices in 2022 and the effects of higher total sales volume, partially offset by (i) higher net payments for commodity derivatives settlements and premiums, (iii) higher acquisition, integration and strategic transaction costs paid in 2021 and (iv) executive restructuring costs including severance payments in 2021.

Cash Flows from Investing Activities. Our cash payments for capital expenditures were higher during the three months ended March 31, 2022 as compared to the corresponding period in 2021, due primarily to the continued impact into early 2021 from the temporary suspension of the drilling program in 2020 due to the global economic downturn associated with COVID-19. This is coupled with the current economic impacts from inflation and higher costs.

The following table sets forth costs related to our capital expenditures program for the periods presented:

	Three Months Ended March 31,
	2022		2021
Drilling and completion	$	82,794	$	53,585
Lease acquisitions, land-related costs, and geological and geophysical (seismic) costs	665		788
Pipeline, gathering facilities and other equipment, net 1	2		(251)
Total capital expenditures incurred	$	83,461	$	54,122

_______________________

1    Includes certain capital charges to our working interest partners for completion services.

The following table reconciles the total costs of our capital expenditures program with the net cash paid for capital expenditures as reported in our condensed consolidated statements of cash flows for the periods presented:

	Three Months Ended March 31,
	2022		2021
Total capital expenditures program costs (from above)	$	83,461	$	54,122
Increase in accounts payable for capital items and accrued capitalized costs	(9,361)		(20,246)
Net purchases of tubular inventory and well materials 1	3,587		(545)
Prepayments for drilling and completion services, net of (transfers)	(8,964)		339
Capitalized internal labor, capitalized interest and other	2,450		1,088
Total cash paid for capital expenditures	$	71,173	$	34,758

_______________________

1    Includes purchases made in advance of drilling.

Cash Flows from Financing Activities. During the three months ended March 31, 2022, we had borrowings of $50.0 million and repayments of $130.0 million under the Credit Facility. During the three months ended March 31, 2021, we received over $150 million of proceeds from the issuance of equity in connection with the Juniper Transactions. These proceeds were primarily used to (i) fund the repayments of $80.5 million and $50.0 million under the Credit Facility and Second Lien Term Loan, respectively and (ii) pay $9.3 million of transaction and issue costs related to Juniper. The three months ended March 31, 2021 includes an additional repayment of $5 million under the Credit Facility and a $1.9 million quarterly amortization payment under the Second Lien Term Loan.

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Capitalization

The following table summarizes our total capitalization as of the dates presented:

	March 31, 2022			December 31, 2021
Credit facility	$	128,000		$	208,000
9.25 Senior Notes due 2026, net	386,992			386,427
Mortgage debt 1	8,391			8,438
Other 2	322			2,516
Total debt, net	523,705			605,381
Total equity	649,325			669,508
Total capitalization	$	1,173,030		$	1,274,889
Debt as a % of total capitalization	45		%	47		%

_______________________

1     The mortgage debt relates to the corporate office building and related assets acquired in connection with the Lonestar Acquisition for which assets are held as collateral for such debt. As of March 31, 2022 and December 31, 2021, these assets were classified as Assets held for sale on the condensed consolidated balance sheets.

2     Other debt of $2.2 million was extinguished during the three months ended March 31, 2022 and recorded as a gain on extinguishment of debt.

Credit Facility. As of March 31, 2022, the Credit Facility had a $1.0 billion revolving commitment and a $725 million borrowing base, with aggregate elected commitments of $400 million and a $25 million sublimit for the issuance of letters of credit. 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. Our next borrowing base redetermination is scheduled in May 2022. The Credit Facility is available to us for general corporate purposes including working capital. We had $0.7 million and $0.9 million in letters of credit outstanding as of March 31, 2022 and December 31, 2021, respectively. The maturity date under the Credit Facility is October 6, 2025.

The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 1.50% to 2.50%, determined based on the utilization level under the Credit Facility or (b) a Eurodollar rate 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, including LIBOR, borrowings is payable every one, three or six months, at our election, and is computed on the basis of a year of 360 days. As of March 31, 2022, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 3.02%. Unused commitment fees are charged at a rate of 0.50%.

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The following table summarizes our borrowing activity under the Credit Facility for the periods presented:

			Borrowings Outstanding
	End of Period		Weighted- Average		Maximum		Weighted- Average Rate
Three months ended March 31, 2022	$	128,000	$	199,000	$	228,000	3.18	%

The Credit Facility is guaranteed by all of the subsidiaries of the borrower (the “Guarantor Subsidiaries”), except for Boland Building, LLC which holds real estate assets that are associated with mortgage obligations assumed in the Lonestar Acquisition. The guarantees under the Credit Facility are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. There are no significant restrictions on the ability of the borrower or any of the Guarantor Subsidiaries to obtain funds through dividends, advances or loans. The obligations under the Credit Facility are secured by a first priority lien on substantially all of our subsidiaries’ assets.

9.25% Senior Notes due 2026. On August 10, 2021, our indirect, wholly-owned subsidiary Penn Virginia Escrow LLC (the “Escrow Issuer”) completed an offering of $400 million aggregate principal amount of senior unsecured notes due 2026 (the “9.25% Senior Notes due 2026”) that bear interest at 9.25% and were sold at 99.018% of par. Obligations under the 9.25% Senior Notes due 2026 were assumed by Penn Virginia Holdings, LLC (“Holdings”), as borrower, and are guaranteed by the subsidiaries of Holdings that guarantee the Credit Facility.

Covenant Compliance. 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) of 1.00 to 1.00 and (2) a maximum leverage ratio (consolidated indebtedness to EBITDAX, each as defined in the Credit Facility), in each case measured as of the last day of each fiscal quarter of 3.50 to 1.00.

The Credit Facility and the indenture governing the 9.25% Senior Notes due 2026 contain 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, 2022, we were in compliance with all of the debt covenants.

See Note 7 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information on our debt.

Critical Accounting Estimates

The process of preparing financial statements in accordance with GAAP requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Disclosure of our most critical accounting estimates that involve the judgment of our management can be found in our Annual Report on Form 10-K for the year ended December 31, 2021.

As described in this Quarterly Report on Form 10-Q as well as the Critical Accounting Estimates disclosures in the Annual Report on Form 10-K, we apply the full cost method to account for our oil and gas properties. At the end of each quarterly reporting period, we perform a Ceiling Test in order to determine if our oil and gas properties have been impaired. For purposes of the Ceiling Test, estimated discounted future net revenues are determined using the prior 12-month’s average price based on closing prices on the first day of each month, adjusted for differentials, discounted at 10%. The calculation of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are significant uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production, timing and plan of development. We had no impairments of our proved oil and gas properties during the first quarter of 2022. The carrying value of our proved oil and gas properties exceeded the limit determined by the Ceiling Test as of March 31, 2021, resulting in a $1.8 million impairment.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are interest rate risk and commodity price risk.

Interest Rate Risk

As of March 31, 2022, we had variable-rate borrowings of $128.0 million under the Credit Facility and fixed-rate borrowings of $400.0 million for the 9.25% Senior Notes due 2026 at interest rates of 3.02% and 9.25%, respectively. Assuming a constant borrowing level under the Credit Facility, an increase (decrease) in the interest rate of one percent would result in an increase (decrease) in aggregate interest payments of approximately $1.3 million on an annual basis, excluding the offsetting impact of our interest rate swap derivatives.

Commodity Price Risk

We produce and sell crude oil, NGLs and natural gas. As a result, our financial results are affected when prices for these commodities fluctuate. Our price risk management programs permit the utilization of derivative financial instruments (such as collars and swaps) to seek to mitigate the price risks associated with fluctuations in commodity prices as they relate to a portion of our anticipated production. The derivative instruments are placed with major financial institutions that we believe are of acceptable credit risk. The fair values of our derivative instruments are significantly affected by fluctuations in the prices of crude oil, NGLs and natural gas.

As of March 31, 2022, our commodity derivative portfolio was in a net liability position in the amount of $178.6 million. The contracts associated with this position are with eight counterparties, all of which are investment grade financial institutions. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. 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.

During the three months ended March 31, 2022, we reported a net commodity derivative loss of $168.0 million. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our derivative instruments. Our results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which fluctuate with changes in crude oil, NGL and natural gas prices. These fluctuations could be significant in a volatile pricing environment. See Note 5 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for a further description of our commodity price risk management activities.

The following table illustrates the estimated impact on the fair values of our derivative financial instruments and operating income attributable to hypothetical changes in the underlying commodity prices. This illustration assumes that crude oil and natural gas prices and production volumes remain constant at anticipated levels. The estimated changes in operating income exclude potential cash receipts or payments in settling these derivative positions.

	Change of 10% per bbl of Crude Oil ($ in millions)
	Increase		Decrease
Effect on the fair value of crude oil derivatives 1	$	(66.4)	$	46.5
Effect of crude oil price changes for the remainder of 2022 on operating income, excluding derivatives 2	$	37.4	$	(38.3)

_______________________

1 Based on derivatives outstanding as of March 31, 2022.

2    These sensitivities are subject to significant change.

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Item 4. Controls and Procedures

(a) Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of March 31, 2022. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported on a timely basis and that such information is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of March 31, 2022, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

Except as described below, during the quarter ended March 31, 2022, there were no changes to our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

During the quarter ended March 31, 2022, we continued the process of integrating Lonestar into our operations and internal control processes.

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

We are not aware of any material pending legal or governmental proceedings against us, any material proceedings by governmental officials against us that are pending or contemplated to be brought against us and no such proceedings have been terminated during the period covered by this Quarterly Report on Form 10-Q. See Note 11 to our condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information regarding our legal and regulatory matters.

Item 1A. Risk Factors

There have been no material changes to the risk factors disclosed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2021 except as follows:

Our ability to repurchase shares of our Class A Common Stock is subject to certain risks.

In April 2022, our Board approved a share repurchase program to repurchase up to $100 million of shares of our Class A Common Stock. Any repurchasing of shares of our Class A Common Stock will be at the discretion of our Board of Directors and will depend upon, among other things, our earnings, liquidity, capital requirements, financial condition, management’s assessment of the intrinsic value of the Class A Common Stock, the market price of the Company's Class A Common Stock, general market and economic conditions, available liquidity, compliance with the Company’s debt and other agreements, applicable legal requirements and other factors deemed relevant. Our Credit Facility and Indenture both limit our ability to repurchase shares of our Class A Common Stock. In addition, share repurchases may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. We can provide no assurances that we will repurchase shares of our Class A Common Stock within the authorized amount or at all.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

(a) None.

(b) None.

(c) None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5.    Other Information

None.

40

Item 6.    Exhibits

(31.1) *	Certification Pursuant to Rule 13a-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(31.2) *	Certification Pursuant to Rule 13a-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(32.1) †	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(32.2) †	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(101.INS) *	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
(101.SCH) *	Inline XBRL Taxonomy Extension Schema Document
(101.CAL) *	Inline XBRL Taxonomy Extension Calculation Linkbase Document
(101.DEF) *	Inline XBRL Taxonomy Extension Definition Linkbase Document
(101.LAB) *	Inline XBRL Taxonomy Extension Label Linkbase Document
(101.PRE) *	Inline XBRL Taxonomy Extension Presentation Linkbase Document
(104) *	The cover page of Ranger Oil Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2022, formatted in Inline XBRL (included within the Exhibit 101 attachments).

_____________________________

*    Filed herewith.

†    Furnished herewith.

41

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	RANGER OIL CORPORATION
May 5, 2022	By:	/s/ RUSSELL T KELLEY, JR.
		Russell T Kelley, Jr.
		Senior Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)
May 5, 2022	By:	/s/ KAYLA D. BAIRD
		Kayla D. Baird
		Vice President, Chief Accounting Officer and Controller
		(Principal Accounting Officer)

42

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Darrin J. Henke, President and Chief Executive Officer of Ranger Oil Corporation (the “Registrant”), certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of the Registrant (this “Report”);

2. Based on my knowledge, this Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Report;

3. Based on my knowledge, the financial statements, and other financial information included in this Report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this Report;

4. The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this Report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this Report based on such evaluation; and

(d)Disclosed in this Report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter (the Registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

5. The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date: May 5, 2022

/s/ DARRIN J. HENKE

Darrin J. Henke

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Russell T Kelley, Jr., Senior Vice President, Chief Financial Officer and Treasurer of Ranger Oil Corporation (the “Registrant”), certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of the Registrant (this “Report”);

2. Based on my knowledge, this Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Report;

3. Based on my knowledge, the financial statements, and other financial information included in this Report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this Report;

4. The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this Report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this Report based on such evaluation; and

(d)Disclosed in this Report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter (the Registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

5. The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date: May 5, 2022

/s/ RUSSELL T KELLEY, JR.

Russell T Kelley, Jr.

Senior Vice President, Chief Financial Officer and Treasurer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Ranger Oil Corporation (the “Company”) on Form 10-Q for the quarter ended March 31, 2022, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Darrin J. Henke, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: May 5, 2022

/s/ DARRIN J. HENKE

Darrin J. Henke

President and Chief Executive Officer

This written statement is being furnished to the Securities and Exchange Commission as an exhibit to the Report. A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Ranger Oil Corporation (the “Company”) on Form 10-Q for the quarter ended March 31, 2022, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Russell T Kelley, Jr., Senior Vice President, Chief Financial Officer and Treasurer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: May 5, 2022

/s/ RUSSELL T KELLEY, JR.

Russell T Kelley, Jr.

Senior Vice President, Chief Financial Officer and Treasurer

This written statement is being furnished to the Securities and Exchange Commission as an exhibit to the Report. A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Cover - shares	3 Months Ended
	Mar. 31, 2022	Apr. 28, 2022
Document Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2022
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	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Amendment Flag	false
Document Fiscal Year Focus	2022
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		21,163,394
Common Class B
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		22,548,998

XML

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – UNAUDITED - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Revenues
Total revenues and other	$ 256,455	$ 88,555
Operating expenses
Lease operating	18,102	8,825
Gathering, processing and transportation	9,040	4,674
Production and ad valorem taxes	13,140	5,513
General and administrative	9,779	13,177
Depreciation, depletion and amortization	50,893	23,884
Impairments of oil and gas properties	0	1,811
Total operating expenses	100,954	57,884
Operating income	155,501	30,671
Other income (expense)
Interest expense, net of amounts capitalized	(10,697)	(5,397)
Gain (loss) on extinguishment of debt	2,157	(1,231)
Derivative losses	(167,887)	(44,368)
Other, net	76	(6)
Loss before income taxes	(20,850)	(20,331)
Income tax benefit	189	310
Net loss	(20,661)	(20,021)
Net loss attributable to Noncontrolling interest	10,676	6,449
Net loss attributable to common shareholders	$ (9,985)	$ (13,572)
Net loss per share attributable to common shareholders:
Basic (in dollars per share)	$ (0.47)	$ (0.89)
Diluted (in dollars per share)	$ (0.47)	$ (0.89)
Weighted average shares outstanding – basic (in shares)	21,107	15,263
Weighted average shares outstanding – diluted (in shares)	21,107	15,263
Crude oil
Revenues
Revenues	$ 226,732	$ 81,913
Natural gas liquids
Revenues
Revenues	16,740	3,562
Natural gas
Revenues
Revenues	12,127	2,833
Other operating income, net
Revenues
Revenues	$ 856	$ 247

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS – UNAUDITED - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Statement of Comprehensive Income [Abstract]
Net loss	$ (20,661)	$ (20,021)
Other comprehensive loss:
Change in pension and postretirement obligations, net of tax	0	2
Comprehensive loss	(20,661)	(20,019)
Net loss attributable to Noncontrolling interest	10,676	6,449
Other comprehensive income attributable to Noncontrolling interest	0	(1)
Comprehensive loss attributable to common shareholders	$ (9,985)	$ (13,571)

XML

CONDENSED CONSOLIDATED BALANCE SHEETS – UNAUDITED - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Current assets
Cash and cash equivalents	$ 6,358	$ 23,681
Accounts receivable, net of allowance for credit losses	154,179	118,594
Derivative assets	9,631	11,478
Prepaid and other current assets	15,989	20,998
Assets held for sale	11,400	11,400
Total current assets	197,557	186,151
Property and equipment, net (full cost method)	1,417,715	1,383,348
Derivative assets	2,912	2,092
Other assets	4,636	5,017
Total assets	1,622,820	1,576,608
Current liabilities
Accounts payable and accrued liabilities	246,189	214,381
Derivative liabilities	149,008	50,372
Current portion of long-term debt	1,925	4,129
Total current liabilities	397,122	268,882
Deferred income taxes	2,073	2,793
Derivative liabilities	42,620	23,815
Other non-current liabilities	9,900	10,358
Long-term debt, net	521,780	601,252
Commitments and contingencies (Note 11)
Equity
Preferred stock of $0.01 par value – 5,000,000 shares authorized; none issued as of March 31, 2022 and December 31, 2021	0	0
Paid-in capital	273,807	273,329
Retained earnings	39,598	49,583
Accumulated other comprehensive loss	(111)	(111)
Ranger Oil shareholders’ equity	314,025	323,532
Noncontrolling interest	335,300	345,976
Total equity	649,325	669,508
Total liabilities and equity	1,622,820	1,576,608
Common Class A
Equity
Common stock	729	729
Common Class B
Equity
Common stock	$ 2	$ 2

XML

CONDENSED CONSOLIDATED BALANCE SHEETS – UNAUDITED (Parenthetical) - $ / shares	Mar. 31, 2022	Dec. 31, 2021
Series A Preferred Stock
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, shares issued (in shares)	0	0
Common Class A
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	110,000,000	110,000,000
Common stock, shares, issued (in shares)	21,146,230	21,090,259
Common Class B
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	30,000,000	30,000,000
Common stock, shares, issued (in shares)	22,548,998	22,548,998

XML

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – UNAUDITED - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Cash flows from operating activities
Net loss	$ (20,661)	$ (20,021)
Adjustments to reconcile net loss to net cash provided by operating activities:
(Gain) loss on extinguishment of debt	(2,157)	1,231
Depreciation, depletion and amortization	50,893	23,884
Impairments of oil and gas properties	0	1,811
Derivative contracts:
Net losses	167,887	44,368
Cash settlements and premiums paid, net	29,408	7,169
Deferred income tax benefit	(721)	(310)
Non-cash interest expense	800	611
Share-based compensation	924	2,246
Other, net	(182)	2
Changes in operating assets and liabilities, net	(33,540)	(13,966)
Net cash provided by operating activities	133,835	32,687
Cash flows from investing activities
Capital expenditures	(71,173)	(34,758)
Proceeds from sales of assets, net	656	4
Net cash used in investing activities	(70,517)	(34,754)
Cash flows from financing activities
Proceeds from credit facility borrowings	50,000	0
Repayments of credit facility borrowings	(130,000)	(85,500)
Repayments of second lien term loan	0	(53,140)
Repayments of acquired debt	(83)	0
Proceeds from redeemable common units	0	151,160
Proceeds from redeemable preferred stock	0	2
Transaction costs paid on behalf of Noncontrolling interest	0	(5,543)
Issuance costs paid for Noncontrolling interest securities	0	(3,758)
Withholding taxes for share-based compensation	(445)	(476)
Debt issuance costs paid	(113)	(1,830)
Net cash provided by (used in) financing activities	(80,641)	915
Net decrease in cash and cash equivalents	(17,323)	(1,152)
Cash and cash equivalents – beginning of period	23,681	13,020
Cash and cash equivalents – end of period	6,358	11,868
Cash paid for:
Interest, net of amounts capitalized	20,214	4,888
Non-cash investing and financing activities:
Changes in property and equipment related to capital contributions	0	(38,415)
Changes in accrued liabilities related to capital expenditures	$ 9,361	$ 20,246

XML

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - UNAUDITED - USD ($) $ in Thousands		Total	Preferred Stock	Common Stock	Paid-in Capital	Retained Earnings/(Accumulated Deficit)	Accumulated Other Comprehensive Loss	Noncontrolling interest
Balance at beginning of period at Dec. 31, 2020		$ 212,838	$ 0	$ 152	$ 203,463	$ 9,354	$ (131)	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss		(20,021)				(13,572)		(6,449)
Issuance of preferred stock		2	2
Issuance of Noncontrolling interest		179,552			(50,068)			229,620
All other changes	[1]	1,772		1	1,769		1	1
Balance at end of period at Mar. 31, 2021		374,143	2	153	155,164	(4,218)	(130)	223,172
Balance at beginning of period at Dec. 31, 2021		669,508	0	731	273,329	49,583	(111)	345,976
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss		(20,661)				(9,985)		(10,676)
All other changes	[2]	478			478
Balance at end of period at Mar. 31, 2022		$ 649,325	$ 0	$ 731	$ 273,807	$ 39,598	$ (111)	$ 335,300

[1] Includes equity-classified share-based compensation of $2.2 million during the three months ended March 31, 2021. During the three months ended March 31, 2021, 102,586 and 6,800 shares of common stock were issued in connection with the vesting of certain RSUs and PRSUs, net of shares withheld for income taxes, respectively.

[2] 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, 69,206 of common stock were issued in connection with the vesting of certain time-vested restricted stock units (“RSUs”), net of shares withheld for income taxes. No shares of common stock were issued in connection with the vesting of performance-based restricted stock units (“PRSUs”) during the three months ended March 31, 2022.

XML

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - UNAUDITED (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Statement of Stockholders' Equity [Abstract]
Share-based compensation	$ 924	$ 2,246
Restricted stock units, issued (in shares)	69,206	102,586
Performance shares, issued (in shares)	0	6,800

XML

Organization and Description of Business

3 Months Ended

Mar. 31, 2022

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.

On January 15, 2021, the Company consummated the transactions (collectively, the “Juniper Transactions”) contemplated by: (i) the Contribution Agreement, dated November 2, 2020, by and among the Company, PV Energy Holdings, L.P. (the “Partnership”) and JSTX Holdings, LLC (“JSTX”), an affiliate of Juniper Capital Advisors, L.P. (“Juniper Capital” and, together with JSTX and Rocky Creek Resources, LLC, “Juniper”); and (ii) the Contribution Agreement, dated November 2, 2020, by and among Rocky Creek Resources, LLC, an affiliate of Juniper Capital, the Company and the Partnership pursuant to which Juniper contributed $150 million in cash and certain oil and gas assets in South Texas in exchange for equity that entitles Juniper to both vote and share in any dividend on the same basis as 22,548,998 shares of our Class A Common Stock, par value $0.01 per share (“Class A Common Stock”) (after post-closing adjustments). In connection with the consummation of the Juniper Transactions, the Company completed a reorganization into an up-C structure which was intended to, among other things, result in the affiliates of Juniper Capital having a voting interest in the Company that is commensurate with such holders’ economic interest in the Partnership

XML

Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2022

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Note 2 – Summary of 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 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. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications did not have a material impact on prior period financial statements. 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, 2021. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

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 Annual Report on Form 10-K for the year ended December 31, 2021 (“2021 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 2021 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.

Recently Issued Accounting Pronouncements Not Yet Adopted

In October 2021, the Financial Accounting Standards Board issued ASU 2021-08, Business Combinations (Topic 805): (“ASU 2021-08”): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers. ASU 2021-08 amends Topic 805 to require the acquirer in a business combination to record contract assets and contract liabilities in accordance with Revenue from Contracts with Customers (Topic 606) at acquisition as if it had originated the contract, rather than at fair value. This update is effective for public companies beginning after December 15, 2022, with early adoption permitted. Adoption should be applied prospectively to business combinations occurring on or after the effective date of the amendments unless early adoption occurs during an interim period in which other application rules apply. We do not expect the adoption of this update to have a material impact to our financial statements.

XML

Acquisition

3 Months Ended

Mar. 31, 2022

Business Combination and Asset Acquisition [Abstract]

Acquisition

Note 3 – Acquisition

Acquisition of Lonestar Resources

On October 5, 2021 (the “Closing Date”), the Company acquired Lonestar Resources US Inc., a Delaware corporation (“Lonestar”), as a result of which Lonestar and its subsidiaries became wholly-owned subsidiaries of the Company (the “Lonestar Acquisition”). The Lonestar Acquisition was effected pursuant to the Agreement and Plan of Merger (the “Merger Agreement”), dated July 10, 2021, by and between the Company and Lonestar. In accordance with the terms of the Merger Agreement, Lonestar shareholders received 0.51 shares of the Company’s common stock for each share of Lonestar common stock held immediately prior to the effective time of the Lonestar Acquisition. Based on the closing price of the Company’s common stock on October 5, 2021 of $30.19, and in connection with the Lonestar Acquisition, the total value of the Company’s common stock issued to holders of Lonestar common stock, warrants and restricted stock units as applicable, was approximately $173.6 million.

The Lonestar Acquisition constituted a business combination and was accounted for using the acquisition method of accounting, with Ranger Oil being treated as the accounting acquirer. Under the acquisition method of accounting, the assets and liabilities of Lonestar and its subsidiaries were recorded at their respective preliminary fair values as of the date of completion of the Lonestar Acquisition. Although the purchase price allocation is substantially complete as of March 31, 2022, there may be further adjustments to oil and gas properties as we continue to gather information related to the evaluation of certain properties. We will finalize these amounts within one year subsequent to the closing date of the Lonestar Acquisition. During the three months ended March 31, 2022, there were no changes to the allocation presented in the 2021 Form 10-K.

We expensed $1.7 million in acquisition-related costs for the three months ended March 31, 2022 related to employee severance and change-in-control compensation costs and other integration related costs.

Pro Forma Operating Results (Unaudited)

The following unaudited pro forma condensed financial data for the three months ended March 31, 2021 was derived from the historical financial statements of the Company giving effect to the Lonestar Acquisition, as if it had occurred on January 1, 2020.

	Three Months Ended March 31, 2021
Total revenues	$	128,371
Net income (loss) attributable to common shareholders	$	(23,850)

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Revenue Recognition

3 Months Ended

Mar. 31, 2022

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 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.

Performance obligations

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 90 days. The following table summarizes our accounts receivable by type as of the dates presented:

	March 31, 2022		December 31, 2021
Customers	$	132,760	$	96,195
Joint interest partners	21,518		21,755
Derivative settlements from counterparties	55		1,037
Other	275		18
Total	154,608		119,005
Less: Allowance for credit losses	(429)		(411)
Accounts receivable, net of allowance for credit losses	$	154,179	$	118,594

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Derivative Instruments

3 Months Ended

Mar. 31, 2022

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 formally designated as hedges for accounting purposes. While the use of derivative instruments limits the risk of adverse commodity price and interest rate movements, such use may also limit the beneficial impact of future product revenues and interest expense from favorable commodity price and interest rate movements. From time to time, we may enter into incremental derivative contracts in order to increase the notional volume of production we are hedging, restructure existing derivative contracts or enter into other derivative contracts resulting in modification to the terms of existing contracts. In accordance with our internal policies, we do not utilize derivative instruments for speculative purposes.

For our commodity derivatives, we typically combine swaps, purchased put options, purchased call options, sold put options and sold call options in order to achieve various hedging objectives. Certain of these objectives result in combinations that operate as collars which include purchased put options and sold call options, three-way collars, which include purchased put options, sold put options and sold call options, and enhanced swaps, which include either sold put options or sold call options with the associated premiums rolled into an enhanced fixed price swap, among others.

Commodity Derivatives 1

The following table sets forth our commodity derivative positions, presented on a net basis by period of maturity, as of March 31, 2022:

	2Q2022		3Q2022		4Q2022		1Q2023		2Q2023		3Q2023		4Q2023		1Q2024		2Q2024
NYMEX WTI Crude Swaps
Average Volume Per Day (bbl)	3,000		3,000		3,000		2,500		2,400		2,807		2,657		462		462
Weighted Average Swap Price ($/bbl)	$	74.12	$	73.01	$	69.20	$	54.40	$	54.26	$	54.92	$	54.93	$	58.75	$58.75
NYMEX WTI Crude Collars
Average Volume Per Day (bbl)	17,720		14,266		9,375		6,250		6,181		1,630		1,630
Weighted Average Purchased Put Price ($/bbl)	$	59.12	$	57.14	$	52.17	$	50.67	$	50.67	$	60.00	$	60.00
Weighted Average Sold Call Price ($/bbl)	$	77.01	$	81.13	$	67.57	$	65.65	$	65.65	$	76.12	$	76.12
NYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (bbl)	20,879		14,674		14,674
Weighted Average Swap Price ($/bbl)	$	1.120	$	1.172	$	1.172
NYMEX HH Swaps
Average Volume Per Day (MMBtu)	12,500		12,500		12,500		10,000		7,500
Weighted Average Swap Price ($/MMBtu)	$	3.727	$	3.745	$	3.793	$	3.620	$	3.690
NYMEX HH Collars
Average Volume Per Day (MMBtu)	13,187		13,043		13,043				11,538		11,413		11,413		11,538		11,538
Weighted Average Purchased Put Price ($/MMBtu)	$	2.500	$	2.500	$	2.500			$	2.500	$	2.500	$	2.500	$	2.500	$	2.328
Weighted Average Sold Call Price($/MMBtu)	$	3.220	$	3.220	$	3.220			$	2.682	$	2.682	$	2.682	$	3.650	$	3.000
OPIS Mt Belv Ethane Swaps
Average Volume per Day (gal)	28,022		27,717		27,717				98,901		34,239		34,239		34,615
Weighted Average Fixed Price ($/gal)	$	0.2500	$	0.2500	$	0.2500			$	0.2288	$	0.2275	$	0.2275	$	0.2275

_______________________

1    NYMEX WTI refers to New York Mercantile Exchange West Texas Intermediate that serves as the benchmark for crude oil. NYMEX HH refers to NYMEX Henry Hub that serves as the benchmark for natural gas. OPIS Mt Belv 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

As of March 31, 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 totals $300 million, with us paying a weighted average fixed rate of 1.36% on the notional amount, and the counterparties paying a variable rate equal to LIBOR through May 2022.

Financial Statement Impact of Derivatives

The impact of our derivative activities on income is included within Derivatives 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 (see Note 4) and Accounts payable and accrued liabilities (see Note 9) on the condensed consolidated balance sheets. The effects of derivative gains and (losses) and cash settlements are reported as adjustments to reconcile net loss to net cash provided by operating activities. These items are recorded within the Derivative contracts section of our condensed consolidated statements of cash flows under Net losses and Cash settlements and premiums paid, net.

The following table summarizes the effects of our derivative activities for the periods presented:

	Three Months Ended March 31,
	2022		2021
Interest Rate Swap gains recognized in the condensed consolidated statements of operations	$	83	$	32
Commodity losses recognized in the condensed consolidated statements of operations	(167,970)		(44,400)
	$	(167,887)	$	(44,368)
Interest rate cash settlements recognized in the condensed consolidated statements of cash flows	$	(938)	$	(922)
Commodity cash settlements and premiums paid recognized in the condensed consolidated statements of cash flows	(28,470)		(6,247)
	$	(29,408)	$	(7,169)

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, 2022				December 31, 2021
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Interest rate contracts	Derivative assets/liabilities – current	$	—	$	458	$	—	$	1,480
Commodity contracts	Derivative assets/liabilities – current	9,631		148,550		11,478		48,892
Interest rate contracts	Derivative assets/liabilities – non-current	—		—		—		—
Commodity contracts	Derivative assets/liabilities – non-current	2,912		42,620		2,092		23,815
		$	12,543	$	191,628	$	13,570	$	74,187

As of March 31, 2022, we reported net commodity derivative liabilities of $178.6 million and net Interest Rate Swap liabilities of $0.5 million. The contracts associated with these positions are with eight counterparties for commodity derivatives and four counterparties for Interest Rate Swaps, all of which are investment grade financial institutions and are participants in 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.

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Property and Equipment

3 Months Ended

Mar. 31, 2022

Property, Plant and Equipment [Abstract]

Property and Equipment

Note 6 – Property and Equipment

The following table summarizes our property and equipment as of the dates presented: 

	March 31, 2022		December 31, 2021
Oil and gas properties:
Proved	$	2,412,399	$	2,327,686
Unproved	58,686		57,900
Total oil and gas properties	2,471,085		2,385,586
Other property and equipment 1	31,060		31,055
Total properties and equipment	2,502,145		2,416,641
Accumulated depreciation, depletion, amortization and impairments	(1,084,430)		(1,033,293)
Total property and equipment, net	$	1,417,715	$	1,383,348

_______________________

1     Excludes the corporate office building and related assets acquired in connection with the Lonestar Acquisition that were classified as Assets held for sale on the condensed consolidated balance sheets as of March 31, 2022 and December 31, 2021.

Unproved property costs of $58.7 million and $57.9 million have been excluded from amortization as of March 31, 2022 and December 31, 2021, respectively. We transferred $0.7 million and $7.6 million of undeveloped leasehold costs, including capitalized interest, associated with proved undeveloped reserves, acreage unlikely to be drilled or expiring acreage, from unproved properties to the full cost pool during the three months ended March 31, 2022 and 2021, respectively. We capitalized internal costs of $1.4 million and $0.7 million and interest of $1.1 million and $0.8 million during the three months ended March 31, 2022 and 2021, respectively, in accordance with our accounting policies. Average depreciation, depletion and amortization per barrel of oil equivalent of proved oil and gas properties was $14.98 and $12.92 for the three months ended March 31, 2022 and 2021, respectively.

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”). Beginning in early 2020, certain events such as the COVID-19 pandemic and the decisions by the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, collectively “OPEC+”) negatively impacted the oil and gas industry with significant declines in crude oil prices and oversupply of crude oil. Over the past year, however, increased mobility, deployment of vaccines and other factors have resulted in increased oil demand and commodity prices. A high level of uncertainty remains regarding the volatility of energy supply and demand as a result of OPEC’s continued strategy to increase production as well as the Russia-Ukraine conflict and related sanctions which began in the first quarter of 2022. WTI crude oil prices have surged, closing at over $120 per bbl during first quarter 2022 due to concerns that it might result in significant oil supply shortages. Because the Ceiling Test utilizes commodity prices based on a trailing 12 month average, the decline in commodity prices in the first quarter of 2021 as a result of COVID-19 and macroeconomic factors resulted in impairments of our oil and gas properties of $1.8 million during the three months ended March 31, 2021. We did not record any impairments of our oil and gas properties during the three months ended March 31, 2022.

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Long-Term Debt

3 Months Ended

Mar. 31, 2022

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, 2022		December 31, 2021
Credit Facility	$	128,000	$	208,000
9.25% Senior Notes due 2026	400,000		400,000
Mortgage debt 1	8,391		8,438
Other 2	322		2,516
Total	536,713		618,954
Less: Unamortized discount 3	(3,560)		(3,720)
Less: Unamortized deferred issuance costs 3, 4	(9,448)		(9,853)
Total, net	$	523,705	$	605,381
Less: Current portion	(1,925)		(4,129)
Long-term debt	$	521,780	$	601,252

_______________________

1     The mortgage debt relates to the corporate office building and related assets acquired in connection with the Lonestar Acquisition for which assets are held as collateral for such debt. As of March 31, 2022 and December 31, 2021, these assets met the held for sale criteria and were classified as Assets held for sale on the condensed consolidated balance sheets.

2     Other debt of $2.2 million was extinguished during the three months ended March 31, 2022 and recorded as a gain on extinguishment of debt.

3     The discount and issuance costs of the 9.25% Senior Notes due 2026 are being amortized over its respective term using the effective-interest method.

4     Excludes issuance costs associated with the Credit Facility, which 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, 2022, the Credit Facility had a $1.0 billion revolving commitment and a $725 million borrowing base with aggregate elected commitments of $400 million, and a $25 million sublimit for the issuance of letters of credit. Availability under the Credit Facility may not exceed the lesser of the aggregate elected commitments or the borrowing base less outstanding advances and letters of credit. The borrowing base under the Credit Facility is redetermined semi-annually, generally in the Spring and Fall of each year. Our next borrowing base redetermination is scheduled in May 2022. 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 Eurodollar rate, including LIBOR through 2023, plus an applicable margin ranging from 2.50% to 3.50%, determined based on the utilization level under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on Eurodollar borrowings is payable every one, three or six months, at the election of the borrower, and is computed on the basis of a year of 360 days. As of March 31, 2022, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 3.02%. Unused commitment fees are charged at a rate of 0.50%.

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, 2022, we had $128.0 million in outstanding borrowings and $0.7 million in outstanding letters of credit under the Credit Facility. Factoring in the outstanding letters of credit, we had $271.3 million of availability under the Credit Facility as of March 31, 2022. During the three months ended March 31, 2021, we incurred and capitalized approximately $0.4 million of issue costs associated with amendments to the Credit Facility.

9.25% Senior Notes due 2026

On August 10, 2021, our indirect, wholly-owned subsidiary Penn Virginia Escrow LLC (the “Escrow Issuer”) completed an offering of $400 million aggregate principal amount of senior unsecured notes due 2026 (the “9.25% Senior Notes due 2026”) that bear interest at 9.25% and were sold at 99.018% of par. Obligations under the 9.25% Senior Notes due 2026 were assumed by Penn Virginia Holdings, LLC (“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 in part at specified redemption prices.

The indenture governing the 9.25% Senior Notes due 2026 also contains other customary affirmative and negative covenants as well as events of default and remedies.

As of March 31, 2022, we were in compliance with all debt covenants.

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Income Taxes

3 Months Ended

Mar. 31, 2022

Income Tax Disclosure [Abstract]

Income Taxes

Note 8 – Income Taxes

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 is fully attributable to the State of Texas. Our net deferred income tax liability balance of $2.1 million as of March 31, 2022 is also fully attributable to the State of Texas and primarily related to property.

The income tax provision resulted in a benefit of $0.3 million for the three months ended March 31, 2021. 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 1.5%, which is fully attributable to the State of Texas.

We had no liability for unrecognized tax benefits as of March 31, 2022 and December 31, 2021. There were no interest and penalty charges recognized during the three months ended March 31, 2022 and 2021. Tax years from 2017 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.

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Supplemental Balance Sheet Detail

3 Months Ended

Mar. 31, 2022

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, 2022		December 31, 2021
Prepaid and other current assets:
Inventories 1	$	13,025	$	10,305
Prepaid expenses 2	2,964		10,693
	$	15,989	$	20,998
Other assets:
Deferred issuance costs of the Credit Facility, net of amortization	$	3,138	$	3,308
Right-of-use assets – operating leases	1,498		1,671
Other	—		38
	$	4,636	$	5,017
Accounts payable and accrued liabilities:
Trade accounts payable	$	32,463	$	32,452
Drilling and other lease operating costs	47,103		35,045
Revenue and royalties payable	110,493		95,521
Production, ad valorem and other taxes	12,224		7,905
Derivative settlements to counterparties	25,146		6,117
Compensation and benefits	7,957		13,942
Interest	5,003		15,321
Environmental remediation liability 3	2,277		2,287
Current operating lease obligations	891		914
Other	2,632		4,877
	$	246,189	$	214,381
Other non-current liabilities:
Asset retirement obligations	$	8,186	$	8,413
Non-current operating lease obligations	755		975
Postretirement benefit plan obligations	959		970
	$	9,900	$	10,358

_______________________

1    Includes tubular inventory and well materials of $12.2 million and $9.5 million and crude oil volumes in storage of $0.8 million and $0.8 million as of March 31, 2022 and December 31, 2021, respectively.

2 The balances as of March 31, 2022 and December 31, 2021 include $0.6 million and $9.6 million, respectively, for the prepayment of drilling and completion materials and services.

3 The balance as of March 31, 2022 and December 31, 2021 represents estimated costs associated with remediation activities for certain wells and tanks acquired as part of the Lonestar Acquisition.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2022

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, 2022 and December 31, 2021, the carrying values of the borrowings outstanding under our credit facilities approximate fair value as the borrowings bear interest at variables rates tied to current market rates and the applicable margins represent market rates. The fair value of our fixed rate 9.25% Senior Notes due 2026 is estimated based on the published market prices for issuances of similar risk and tenor and is categorized as Level 2 within the fair value hierarchy. As of March 31, 2022, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $536.7 million and $559.4 million, respectively. As of December 31, 2021, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $619.0 million and $634.6 million.

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, 2022
	Level 1		Level 2		Level 3		Total
Financial assets:
Commodity derivative assets – current	$	—	$	9,631	$	—	$	9,631
Commodity derivative assets – non-current	—		2,912		—		2,912
Total financial assets	$	—	$	12,543	$	—	$	12,543
Financial liabilities:
Interest rate swap liabilities – current	$	—	$	(458)	$	—	$	(458)
Commodity derivative liabilities – current	—		(148,550)		—		(148,550)
Commodity derivative liabilities – non-current	—		(42,620)		—		(42,620)
Total financial liabilities	$	—	$	(191,628)	$	—	$	(191,628)

	As of December 31, 2021
	Level 1		Level 2		Level 3		Total
Financial assets:
Commodity derivative assets – current	$	—	$	11,478	$	—	$	11,478
Commodity derivative assets – non-current	—		2,092		—		2,092
Total financial assets	$	—	$	13,570	$	—	$	13,570
Financial liabilities:
Interest rate swap liabilities – current	$	—	$	(1,480)	$	—	$	(1,480)
Commodity derivative liabilities – current	—		(48,892)		—		(48,892)
Commodity derivative liabilities – non-current	—		(23,815)		—		(23,815)
Total financial liabilities	$	—	$	(74,187)	$	—	$	(74,187)

We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below:

•Commodity derivatives: We determine the fair values of our commodity derivative instruments using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatilities, time value and non-performance risk. For the current market prices, we use third-party quoted forward prices, as applicable, for NYMEX WTI, MEH crude oil, NYMEX HH natural gas and OPIS Mt Belv Ethane natural gas liquids closing prices as of the end of the reporting periods. Each of these is a Level 2 input.

•Interest rate swaps: We determine the fair values of our interest rate swaps using an income approach valuation technique which discounts future cash flows back to a single present value. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these is a Level 2 input.

Non-performance risk is incorporated by utilizing discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is in a liability position. See Note 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 AROs associated with the ongoing development of new oil and gas properties and certain share-based compensation awards. The determination of the fair value of AROs is based upon regional market and facility specific information. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these significant fair value inputs are typically not observable, we have categorized the initial estimates as Level 3 inputs.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 11 – Commitments and Contingencies

Drilling and Completion Commitments

As of March 31, 2022, we have a one year contract for one drilling rig and a contractual commitment on a pad-to-pad basis for one other drilling rig.

Gathering and Intermediate Transportation Commitments

We have long-term agreements that provide us with field gathering and intermediate pipeline transportation services for a majority of our crude oil and condensate production in Lavaca and Gonzales Counties, Texas. We also have volume capacity support for certain downstream interstate pipeline transportation. The following table provides details on these contractual arrangements as of March 31, 2022:

Description of contractual arrangement	Expiration of Contractual Arrangement	Minimum Volume Commitment (MVC) (bbl/d)	Expiration of Minimum Volume Commitment (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.

Under each of the arrangements, credits for deliveries of volumes in excess of the volume commitment may be applied to any deficiency arising in the succeeding 12-month period.

During the three months ended March 31, 2022 and 2021, we recorded expense of $10.2 million and $8.4 million, respectively, for these contractual obligations in connection with these arrangements.

Excluding the application of existing credits that we have earned during the preceding 12-month period ended March 31, 2022 for deliveries of volumes in excess of the volume commitment, and 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 2022, approximately $13.9 million per year for 2023 through 2025, $7.8 million for 2026, $3.8 million per year for 2027 through 2030 and $0.6 million for 2031.

Crude Oil Storage

As of March 31, 2022, we had access to up to approximately 180,000 barrels of dedicated tank capacity for no additional charge at the service provider’s central delivery point facility (“CDP”), in Lavaca County, Texas through February 2041. In addition, we had access for up to a maximum of 340,000 barrels of tank capacity and evergreen month-to-month at several locations in the South Texas region comprised of (i) access to an additional 70,000 barrels of tank capacity at the CDP on a month-to-month basis, which can be terminated by either party with 45 days’ notice to the counterparty, (ii) crude oil storage capacity for up to 90,000 barrels with a downstream interstate pipeline at a facility in DeWitt County, Texas, on a month-to-month basis, which expired in April 2022, and (iii) an agreement with a marketing affiliate of the aforementioned downstream interstate pipeline to utilize up to 62,000 barrels of capacity within their system on a firm basis and an additional 120,000 barrels, if available, on a flexible basis that both expired in April 2022. Costs associated with these agreements are in the form of monthly fixed rate short-term leases and are charged as incurred on a monthly basis to GPT in our condensed consolidated statements of operations.

Other Agreements

We have a long-term dedication of certain specific leases to a crude purchase and throughput terminal agreement into 2032. Under the agreement, we have rights to transfer dedicated oil for delivery to a gulf coast terminal in Point Comfort, Texas or oil may be transferred at alternate locations to third parties and pay the terminal fee.

We have agreements that provide us with field gathering, compression and short-haul transportation services for our natural gas production and gas lift for our hydrocarbon production under various terms through 2039.

We also have agreements that provide us with services to process our wet gas production into NGL products and dry, or residue, gas. Several agreements covering the majority of our wet gas production extend beyond three years, including one 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, 2022 and December 31, 2021, 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, 2022 and December 31, 2021, we had AROs of approximately $8.2 million and $8.4 million attributable to the plugging of abandoned wells, respectively. Additionally, we had $2.3 million of environmental remediation liabilities assumed in the Lonestar Acquisition as of March 31, 2022 and December 31, 2021. 

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.

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Share-Based Compensation and Other Benefit Plans

3 Months Ended

Mar. 31, 2022

Share-based Payment Arrangement [Abstract]

Share-Based Compensation and Other Benefit Plans

Note 12 – 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 (the “Plan”) for share-based compensation awards. A total of 762,259 RSUs and 484,197 PRSUs have been granted to employees and directors through March 31, 2022.

We recognized expense attributable to the RSUs and PRSUs of $0.9 million for the three months ended March 31, 2022 and $2.2 million, including approximately $1.9 million as a result of a change-in-control event associated with the Juniper Transactions for the three months ended March 31, 2021. We recognize share-based compensation expense as a component of 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, 2022 with respect to awarded RSUs:

	Restricted Stock Units	Weighted-Average Grant Date Fair Value
Balance at beginning of year	230,517	$	9.20
Granted	—	—
Vested	(69,206)	(7.94)
Forfeited	—	—
Balance at end of year	161,311	$	10.52

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, 2022, we had $1.2 million of unrecognized compensation cost attributable to RSUs. We expect that cost to be recognized over a weighted-average period of 1.71 years.

Performance-Based Restricted Stock Units

During the three months ended March 31, 2022, we did not have any activity with respect to the PRSUs. As of March 31, 2022, a total of 345,069 PRSUs were unvested and outstanding.

Compensation expense for PRSUs with a market condition is being charged to expense on a straight-line basis for the 2021 grants and graded-vesting for the 2020 and 2019 grants, over a range of less than one to three years. Compensation expense for PRSUs with a performance condition is recognized on a straight-line basis 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 2021 PRSU grants are based 50% on the Company’s return on average capital employed (“ROCE”) relative to a defined peer group and 50% based on the Company’s absolute total shareholder return and total shareholder return (“TSR”) relative to a defined peer group over the three-year performance period. The 2021 PRSUs cliff vest from 0% to 200% of the original grant at the end of a three-year performance period based on satisfaction of the respective underlying conditions.

Vesting of PRSUs granted in 2020 and 2019 range from 0% to 200% of the original grant based on TSR relative to a defined peer group over the three 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 grants is derived by using a Monte Carlo model. The ranges for the assumptions used in the Monte Carlo model for the PRSUs granted during 2021, 2020 and 2019 are presented as follows:

	2021 1		2020 1		2019
Expected volatility	131.74% to 134.74%		101.32% to 117.71%		49.9	%
Dividend yield	0.0	%	0.0	%	0.0	%
Risk-free interest rate	0.22% to 0.29%		0.18% to 0.51%		1.66	%
Performance period	2021-2023		2020-2022		2020-2022

_______________________

1    One executive officer’s inducement award originally granted in August 2020 was amended in April 2021 to conform vesting conditions to other PRSU awards granted in 2021. The Monte Carlo assumptions for both years are included above.

As of March 31, 2022, we had $3.9 million of unrecognized compensation cost attributable to PRSUs. We expect that cost to be recognized over a weighted-average period of 1.94 years.

Other Benefit Plans

We maintain the Penn Virginia Corporation and Affiliated Companies Employees 401(k) Plan (the “401(k) Plan”), a defined contribution plan, which covers substantially all of our employees. We recognized $0.2 million of expense attributable to the 401(k) Plan for both the three months ended March 31, 2022 and 2021. The charges for the 401(k) Plan are recorded 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, all of whom 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 and three months ended March 31, 2022 and 2021. The charges for these plans are recorded as a component of Other income (expense) in our condensed consolidated statements of operations.

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Earnings Per Share

3 Months Ended

Mar. 31, 2022

Earnings Per Share [Abstract]

Earnings Per Share

Note 13 – Earnings Per Share

Basic net earnings (loss) per share is calculated by dividing the net income (loss) available to common shareholders, excluding net income or loss attributable to Noncontrolling interest, 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, par value $0.01 per share (“Class B Common Stock”) as applicable to the three months ended March 31, 2022 and Series A Preferred Stock, par value $0.01 per share (“Series A Preferred Stock”) as applicable to the three months ended March 31, 2021) held by the Noncontrolling interest in the Partnership are exchanged for common shares. Accordingly, our reported net income (loss) attributable to common shareholders is adjusted to reflect the reallocation of the net income (loss) attributable to the Noncontrolling interest assuming exchange of the Common Units (and shares of Class B Common Stock as applicable to the three months ended March 31, 2022 and Series A Preferred Stock as applicable to the three months ended March 31, 2021) 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,
	2022		2021
Net loss	$	(20,661)	$	(20,021)
Net loss attributable to Noncontrolling interest	10,676		6,449
Net loss attributable to common shareholders (basic)	(9,985)		(13,572)
Reallocation of Noncontrolling interest net loss	(10,676)		(6,449)
Net loss attributable to common shareholders (diluted)	$	(20,661)	$	(20,021)
Weighted-average shares – basic	21,107		15,263
Effect of dilutive securities:
Common Units and Series A Preferred Stock or Class B Common Stock, as applicable, that are exchangeable for common shares 1	—		—
RSUs and PRSUs	—		—
Weighted-average shares – diluted 2	21,107		15,263

_______________________

1    In connection with the Juniper Transactions in January 2021, we issued shares of Series A Preferred Stock. In October 2021, the Company effected a recapitalization and the Series A Preferred Stock were exchanged with Class B Common Stock and the designation of the Series A Preferred Stock was cancelled.

2    For the three months ended March 31, 2022, approximately 22.5 million potentially dilutive Common Units (and the associated 22.5 million Class B Common Stock) and 0.6 million of RSUs and PRSUs had the effect of being anti-dilutive and were excluded from the calculation of earnings per share. For the three months ended March 31, 2021, approximately 22.7 million potentially dilutive securities represented by approximately 22.5 million Common Units (and the associated approximately 0.2 million shares of Series A Preferred Stock) as well as approximately 0.2 million of RSUs and PRSUs had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per share.

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Subsequent Events

3 Months Ended

Mar. 31, 2022

Subsequent Events [Abstract]

Subsequent Events

Note 14 – Subsequent Events

Share Repurchase Program

On April 13, 2022, our Board of Directors approved a share repurchase program, under which the Company is authorized to repurchase up to $100 million of its outstanding Class A common stock. The share repurchase authorization was effective immediately and is valid through March 31, 2023.

The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions, or by other means in accordance with federal securities laws. The Company intends to fund repurchases from available working capital and cash provided by operating activities. The timing, as well as the number and value of shares repurchased under the program, will be determined by the Company at its discretion and will depend on a variety of factors, including among other things, our earnings, liquidity, capital requirements, financial condition, management’s assessment of the intrinsic value of the Class A Common Stock, the market price of the Company's Class A common stock, general market and economic conditions, available liquidity, compliance with the Company’s debt and other agreements (including maintaining a leverage ratio of no more than 1.0 to 1.0), applicable legal requirements and other factors deemed relevant. The exact number of shares to be repurchased by the Company is not guaranteed, and the program may be suspended, modified, or discontinued at any time without prior notice.

Acquisitions

On May 3, 2022, we entered into separate agreements to acquire “bolt-on” oil producing properties in the Eagle Ford shale contiguous to our existing assets for a total purchase price of approximately $64 million in cash, subject to customary adjustments. The transactions are expected to close early in the third quarter, subject to customary closing conditions.

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Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2022

Accounting Policies [Abstract]

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 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. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications did not have a material impact on prior period financial statements. 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, 2021. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

We consider the applicability and impact of all Accounting Standard Updates (“ASUs”). ASUs not listed below were assessed and determined to be not applicable.

Recently Issued Accounting Pronouncements Not Yet Adopted

In October 2021, the Financial Accounting Standards Board issued ASU 2021-08, Business Combinations (Topic 805): (“ASU 2021-08”): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers. ASU 2021-08 amends Topic 805 to require the acquirer in a business combination to record contract assets and contract liabilities in accordance with Revenue from Contracts with Customers (Topic 606) at acquisition as if it had originated the contract, rather than at fair value. This update is effective for public companies beginning after December 15, 2022, with early adoption permitted. Adoption should be applied prospectively to business combinations occurring on or after the effective date of the amendments unless early adoption occurs during an interim period in which other application rules apply. We do not expect the adoption of this update to have a material impact to our financial statements.

Non-Recurring Fair Value Measurements

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 AROs associated with the ongoing development of new oil and gas properties and certain share-based compensation awards. The determination of the fair value of AROs is based upon regional market and facility specific information. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these significant fair value inputs are typically not observable, we have categorized the initial estimates as Level 3 inputs.

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Acquisition (Tables)

3 Months Ended

Mar. 31, 2022

Business Combination and Asset Acquisition [Abstract]

Schedule of Pro Forma Information

The following unaudited pro forma condensed financial data for the three months ended March 31, 2021 was derived from the historical financial statements of the Company giving effect to the Lonestar Acquisition, as if it had occurred on January 1, 2020.

	Three Months Ended March 31, 2021
Total revenues	$	128,371
Net income (loss) attributable to common shareholders	$	(23,850)

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Revenue Recognition (Tables)

3 Months Ended

Mar. 31, 2022

Receivables [Abstract]

Summary of Accounts Receivable

The following table summarizes our accounts receivable by type as of the dates presented:

	March 31, 2022		December 31, 2021
Customers	$	132,760	$	96,195
Joint interest partners	21,518		21,755
Derivative settlements from counterparties	55		1,037
Other	275		18
Total	154,608		119,005
Less: Allowance for credit losses	(429)		(411)
Accounts receivable, net of allowance for credit losses	$	154,179	$	118,594

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Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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, 2022:

	2Q2022		3Q2022		4Q2022		1Q2023		2Q2023		3Q2023		4Q2023		1Q2024		2Q2024
NYMEX WTI Crude Swaps
Average Volume Per Day (bbl)	3,000		3,000		3,000		2,500		2,400		2,807		2,657		462		462
Weighted Average Swap Price ($/bbl)	$	74.12	$	73.01	$	69.20	$	54.40	$	54.26	$	54.92	$	54.93	$	58.75	$58.75
NYMEX WTI Crude Collars
Average Volume Per Day (bbl)	17,720		14,266		9,375		6,250		6,181		1,630		1,630
Weighted Average Purchased Put Price ($/bbl)	$	59.12	$	57.14	$	52.17	$	50.67	$	50.67	$	60.00	$	60.00
Weighted Average Sold Call Price ($/bbl)	$	77.01	$	81.13	$	67.57	$	65.65	$	65.65	$	76.12	$	76.12
NYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (bbl)	20,879		14,674		14,674
Weighted Average Swap Price ($/bbl)	$	1.120	$	1.172	$	1.172
NYMEX HH Swaps
Average Volume Per Day (MMBtu)	12,500		12,500		12,500		10,000		7,500
Weighted Average Swap Price ($/MMBtu)	$	3.727	$	3.745	$	3.793	$	3.620	$	3.690
NYMEX HH Collars
Average Volume Per Day (MMBtu)	13,187		13,043		13,043				11,538		11,413		11,413		11,538		11,538
Weighted Average Purchased Put Price ($/MMBtu)	$	2.500	$	2.500	$	2.500			$	2.500	$	2.500	$	2.500	$	2.500	$	2.328
Weighted Average Sold Call Price($/MMBtu)	$	3.220	$	3.220	$	3.220			$	2.682	$	2.682	$	2.682	$	3.650	$	3.000
OPIS Mt Belv Ethane Swaps
Average Volume per Day (gal)	28,022		27,717		27,717				98,901		34,239		34,239		34,615
Weighted Average Fixed Price ($/gal)	$	0.2500	$	0.2500	$	0.2500			$	0.2288	$	0.2275	$	0.2275	$	0.2275

_______________________

1    NYMEX WTI refers to New York Mercantile Exchange West Texas Intermediate that serves as the benchmark for crude oil. NYMEX HH refers to NYMEX Henry Hub that serves as the benchmark for natural gas. OPIS Mt Belv refers to Oil Price Information Service Mt. Belvieu that serves as the benchmark for ethane which represents a commodity proxy for NGLs.

Impact of Derivative Activities on Condensed Consolidated Statements of Income

The following table summarizes the effects of our derivative activities for the periods presented:

	Three Months Ended March 31,
	2022		2021
Interest Rate Swap gains recognized in the condensed consolidated statements of operations	$	83	$	32
Commodity losses recognized in the condensed consolidated statements of operations	(167,970)		(44,400)
	$	(167,887)	$	(44,368)
Interest rate cash settlements recognized in the condensed consolidated statements of cash flows	$	(938)	$	(922)
Commodity cash settlements and premiums paid recognized in the condensed consolidated statements of cash flows	(28,470)		(6,247)
	$	(29,408)	$	(7,169)

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, 2022				December 31, 2021
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Interest rate contracts	Derivative assets/liabilities – current	$	—	$	458	$	—	$	1,480
Commodity contracts	Derivative assets/liabilities – current	9,631		148,550		11,478		48,892
Interest rate contracts	Derivative assets/liabilities – non-current	—		—		—		—
Commodity contracts	Derivative assets/liabilities – non-current	2,912		42,620		2,092		23,815
		$	12,543	$	191,628	$	13,570	$	74,187

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Property and Equipment (Tables)

3 Months Ended

Mar. 31, 2022

Property, Plant and Equipment [Abstract]

Summary of Property and Equipment

The following table summarizes our property and equipment as of the dates presented: 

	March 31, 2022		December 31, 2021
Oil and gas properties:
Proved	$	2,412,399	$	2,327,686
Unproved	58,686		57,900
Total oil and gas properties	2,471,085		2,385,586
Other property and equipment 1	31,060		31,055
Total properties and equipment	2,502,145		2,416,641
Accumulated depreciation, depletion, amortization and impairments	(1,084,430)		(1,033,293)
Total property and equipment, net	$	1,417,715	$	1,383,348

_______________________

1     Excludes the corporate office building and related assets acquired in connection with the Lonestar Acquisition that were classified as Assets held for sale on the condensed consolidated balance sheets as of March 31, 2022 and December 31, 2021.

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Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2022

Debt Disclosure [Abstract]

Schedule of Long-term Debt Instruments

The following table summarizes our debt obligations as of the dates presented:

	March 31, 2022		December 31, 2021
Credit Facility	$	128,000	$	208,000
9.25% Senior Notes due 2026	400,000		400,000
Mortgage debt 1	8,391		8,438
Other 2	322		2,516
Total	536,713		618,954
Less: Unamortized discount 3	(3,560)		(3,720)
Less: Unamortized deferred issuance costs 3, 4	(9,448)		(9,853)
Total, net	$	523,705	$	605,381
Less: Current portion	(1,925)		(4,129)
Long-term debt	$	521,780	$	601,252

_______________________

1     The mortgage debt relates to the corporate office building and related assets acquired in connection with the Lonestar Acquisition for which assets are held as collateral for such debt. As of March 31, 2022 and December 31, 2021, these assets met the held for sale criteria and were classified as Assets held for sale on the condensed consolidated balance sheets.

2     Other debt of $2.2 million was extinguished during the three months ended March 31, 2022 and recorded as a gain on extinguishment of debt.

3     The discount and issuance costs of the 9.25% Senior Notes due 2026 are being amortized over its respective term using the effective-interest method.

4     Excludes issuance costs associated with the Credit Facility, which 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.

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Supplemental Balance Sheet Detail (Tables)

3 Months Ended

Mar. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Components of Selected Balance Sheet Accounts

The following table summarizes components of selected balance sheet accounts as of the dates presented:

	March 31, 2022		December 31, 2021
Prepaid and other current assets:
Inventories 1	$	13,025	$	10,305
Prepaid expenses 2	2,964		10,693
	$	15,989	$	20,998
Other assets:
Deferred issuance costs of the Credit Facility, net of amortization	$	3,138	$	3,308
Right-of-use assets – operating leases	1,498		1,671
Other	—		38
	$	4,636	$	5,017
Accounts payable and accrued liabilities:
Trade accounts payable	$	32,463	$	32,452
Drilling and other lease operating costs	47,103		35,045
Revenue and royalties payable	110,493		95,521
Production, ad valorem and other taxes	12,224		7,905
Derivative settlements to counterparties	25,146		6,117
Compensation and benefits	7,957		13,942
Interest	5,003		15,321
Environmental remediation liability 3	2,277		2,287
Current operating lease obligations	891		914
Other	2,632		4,877
	$	246,189	$	214,381
Other non-current liabilities:
Asset retirement obligations	$	8,186	$	8,413
Non-current operating lease obligations	755		975
Postretirement benefit plan obligations	959		970
	$	9,900	$	10,358

_______________________

1    Includes tubular inventory and well materials of $12.2 million and $9.5 million and crude oil volumes in storage of $0.8 million and $0.8 million as of March 31, 2022 and December 31, 2021, respectively.

2 The balances as of March 31, 2022 and December 31, 2021 include $0.6 million and $9.6 million, respectively, for the prepayment of drilling and completion materials and services.

3 The balance as of March 31, 2022 and December 31, 2021 represents estimated costs associated with remediation activities for certain wells and tanks acquired as part of the Lonestar Acquisition.

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2022

Fair Value Disclosures [Abstract]

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, 2022
	Level 1		Level 2		Level 3		Total
Financial assets:
Commodity derivative assets – current	$	—	$	9,631	$	—	$	9,631
Commodity derivative assets – non-current	—		2,912		—		2,912
Total financial assets	$	—	$	12,543	$	—	$	12,543
Financial liabilities:
Interest rate swap liabilities – current	$	—	$	(458)	$	—	$	(458)
Commodity derivative liabilities – current	—		(148,550)		—		(148,550)
Commodity derivative liabilities – non-current	—		(42,620)		—		(42,620)
Total financial liabilities	$	—	$	(191,628)	$	—	$	(191,628)

	As of December 31, 2021
	Level 1		Level 2		Level 3		Total
Financial assets:
Commodity derivative assets – current	$	—	$	11,478	$	—	$	11,478
Commodity derivative assets – non-current	—		2,092		—		2,092
Total financial assets	$	—	$	13,570	$	—	$	13,570
Financial liabilities:
Interest rate swap liabilities – current	$	—	$	(1,480)	$	—	$	(1,480)
Commodity derivative liabilities – current	—		(48,892)		—		(48,892)
Commodity derivative liabilities – non-current	—		(23,815)		—		(23,815)
Total financial liabilities	$	—	$	(74,187)	$	—	$	(74,187)

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Commitment and Contingencies (Tables)

3 Months Ended

Mar. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Purchase Commitment, Excluding Long-term Commitment

The following table provides details on these contractual arrangements as of March 31, 2022:

Description of contractual arrangement	Expiration of Contractual Arrangement	Minimum Volume Commitment (MVC) (bbl/d)	Expiration of Minimum Volume Commitment (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

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Share-Based Compensation and Other Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2022

Share-based Payment Arrangement [Abstract]

Summary of Restricted Stock Unit Activity

The table below summarizes activity for the three months ended March 31, 2022 with respect to awarded RSUs:

	Restricted Stock Units	Weighted-Average Grant Date Fair Value
Balance at beginning of year	230,517	$	9.20
Granted	—	—
Vested	(69,206)	(7.94)
Forfeited	—	—
Balance at end of year	161,311	$	10.52

Schedule of Valuation Assumptions

The ranges for the assumptions used in the Monte Carlo model for the PRSUs granted during 2021, 2020 and 2019 are presented as follows:

	2021 1		2020 1		2019
Expected volatility	131.74% to 134.74%		101.32% to 117.71%		49.9	%
Dividend yield	0.0	%	0.0	%	0.0	%
Risk-free interest rate	0.22% to 0.29%		0.18% to 0.51%		1.66	%
Performance period	2021-2023		2020-2022		2020-2022

_______________________

1    One executive officer’s inducement award originally granted in August 2020 was amended in April 2021 to conform vesting conditions to other PRSU awards granted in 2021. The Monte Carlo assumptions for both years are included above.

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2022

Earnings Per Share [Abstract]

Components of Calculation of Basic and Diluted Earnings Per Share

The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings (loss) per share for the periods presented:

	Three Months Ended March 31,
	2022		2021
Net loss	$	(20,661)	$	(20,021)
Net loss attributable to Noncontrolling interest	10,676		6,449
Net loss attributable to common shareholders (basic)	(9,985)		(13,572)
Reallocation of Noncontrolling interest net loss	(10,676)		(6,449)
Net loss attributable to common shareholders (diluted)	$	(20,661)	$	(20,021)
Weighted-average shares – basic	21,107		15,263
Effect of dilutive securities:
Common Units and Series A Preferred Stock or Class B Common Stock, as applicable, that are exchangeable for common shares 1	—		—
RSUs and PRSUs	—		—
Weighted-average shares – diluted 2	21,107		15,263

_______________________

1    In connection with the Juniper Transactions in January 2021, we issued shares of Series A Preferred Stock. In October 2021, the Company effected a recapitalization and the Series A Preferred Stock were exchanged with Class B Common Stock and the designation of the Series A Preferred Stock was cancelled.

2    For the three months ended March 31, 2022, approximately 22.5 million potentially dilutive Common Units (and the associated 22.5 million Class B Common Stock) and 0.6 million of RSUs and PRSUs had the effect of being anti-dilutive and were excluded from the calculation of earnings per share. For the three months ended March 31, 2021, approximately 22.7 million potentially dilutive securities represented by approximately 22.5 million Common Units (and the associated approximately 0.2 million shares of Series A Preferred Stock) as well as approximately 0.2 million of RSUs and PRSUs had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per share.

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Organization and Description of Business (Details) $ / shares in Units, $ in Millions		3 Months Ended
	Jan. 15, 2021 USD ($) $ / shares shares	Mar. 31, 2022 segment $ / shares	Dec. 31, 2021 $ / shares
Juniper Transaction Table [Line Items]
Number of reportable segments | segment		1
Number of operating segments | segment		1
Common Class A
Juniper Transaction Table [Line Items]
Common stock, par value (in dollars per share) | $ / shares		$ 0.01	$ 0.01
Juniper Transaction
Juniper Transaction Table [Line Items]
Proceeds from contributed capital | $	$ 150
Contribution agreement, common (in shares) | shares	22,548,998
Juniper Transaction | Common Class A
Juniper Transaction Table [Line Items]
Common stock, par value (in dollars per share) | $ / shares	$ 0.01

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Acquisition - Narrative (Details) - Lonestar $ / shares in Units, $ in Millions	Oct. 05, 2021 USD ($) $ / shares	Mar. 31, 2022 USD ($)
Business Acquisition [Line Items]
Acquisition, share ratio	0.51
Acquisition, share price (in dollars per share) | $ / shares	$ 30.19
Acquisition, share value	$ 173.6
Acquisition, transaction costs		$ 1.7

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Acquisition - Schedule of Pro Forma Information (Details) - Lonestar $ in Thousands	3 Months Ended
	Mar. 31, 2021 USD ($)
Business Acquisition [Line Items]
Total revenues	$ 128,371
Net income (loss) attributable to common shareholders	$ (23,850)

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Revenue Recognition (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Receivables [Abstract]
Customers	$ 132,760	$ 96,195
Joint interest partners	21,518	21,755
Derivative settlements from counterparties	55	1,037
Other	275	18
Total	154,608	119,005
Less: Allowance for credit losses	(429)	(411)
Accounts receivable, net of allowance for credit losses	$ 154,179	$ 118,594

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Derivative Instruments - Commodity Derivative Positions (Details)	Mar. 31, 2022 bbl $ / bbl
Crude Oil | Swap | Second Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	3,000
Derivative, Swap Type, Average Fixed Price	74.12
Crude Oil | Swap | Third Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	3,000
Derivative, Swap Type, Average Fixed Price	73.01
Crude Oil | Swap | Fourth Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	3,000
Derivative, Swap Type, Average Fixed Price	69.20
Crude Oil | Swap | First Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	2,500
Derivative, Swap Type, Average Fixed Price	54.40
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 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	17,720
Derivative, Average Floor Price	59.12
Derivative, Average Cap Price	77.01
Crude Oil | 2-Way Collars | Third Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	14,266
Derivative, Average Floor Price	57.14
Derivative, Average Cap Price	81.13
Crude Oil | 2-Way Collars | Fourth Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	9,375
Derivative, Average Floor Price	52.17
Derivative, Average Cap Price	67.57
Crude Oil | 2-Way Collars | First Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	6,250
Derivative, Average Floor Price	50.67
Derivative, Average Cap Price	65.65
Crude Oil | 2-Way Collars | Second Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	6,181
Derivative, Average Floor Price	50.67
Derivative, Average Cap Price	65.65
Crude Oil | 2-Way Collars | Third Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	1,630
Derivative, Average Floor Price	60.00
Derivative, Average Cap Price	76.12
Crude Oil | 2-Way Collars | Fourth Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	1,630
Derivative, Average Floor Price	60.00
Derivative, Average Cap Price	76.12
Crude Oil | CMA Roll Basis Swap | Second Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	20,879
Derivative, CMA Roll Basis Swap, Price	1.120
Crude Oil | CMA Roll Basis Swap | Third Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	14,674
Derivative, CMA Roll Basis Swap, Price	1.172
Crude Oil | CMA Roll Basis Swap | Fourth Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	14,674
Derivative, CMA Roll Basis Swap, Price	1.172
Natural Gas | Swap | Second Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	12,500
Derivative, Swap Type, Average Fixed Price	3.727
Natural Gas | Swap | Third Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	12,500
Derivative, Swap Type, Average Fixed Price	3.745
Natural Gas | Swap | Fourth Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	12,500
Derivative, Swap Type, Average Fixed Price	3.793
Natural Gas | Swap | First Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	10,000
Derivative, Swap Type, Average Fixed Price	3.620
Natural Gas | Swap | 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 | 2-Way Collars | Second Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	13,187
Derivative, Average Floor Price	2.500
Derivative, Average Cap Price	3.220
Natural Gas | 2-Way Collars | Third Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	13,043
Derivative, Average Floor Price	2.500
Derivative, Average Cap Price	3.220
Natural Gas | 2-Way Collars | Fourth Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	13,043
Derivative, Average Floor Price	2.500
Derivative, Average Cap Price	3.220
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	3.000
Natural Gas Liquids | Swap | Second Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	28,022
Derivative, Swap Type, Average Fixed Price	0.2500
Natural Gas Liquids | Swap | Third Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	27,717
Derivative, Swap Type, Average Fixed Price	0.2500
Natural Gas Liquids | Swap | Fourth Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	27,717
Derivative, Swap Type, Average Fixed Price	0.2500
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

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Derivative Instruments - Narrative (Details) $ in Thousands	Mar. 31, 2022 USD ($) customer	Dec. 31, 2021 USD ($)
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative liabilities	$ 191,628	$ 74,187
Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, notional amount	$ 300,000
Derivative, average fixed interest rate	136.00%
Derivative liabilities	$ 500
Number of derivative counterparties | customer	4
Commodity contracts
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative liabilities	$ 178,600
Number of derivative counterparties | customer	8

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Derivative Instruments - Impact of Derivative Activities on Condensed Consolidated Statements of Income (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Interest Rate Swap gains recognized in the condensed consolidated statements of operations	$ 83	$ 32
Commodity losses recognized in the condensed consolidated statements of operations	(167,970)	(44,400)
Derivative losses	(167,887)	(44,368)
Interest rate cash settlements recognized in the condensed consolidated statements of cash flows	(938)	(922)
Commodity cash settlements and premiums paid recognized in the condensed consolidated statements of cash flows	(28,470)	(6,247)
Cash settlements and premiums paid, net	$ (29,408)	$ (7,169)

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Derivative Instruments - Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Derivatives, Fair Value [Line Items]
Derivative assets	$ 9,631	$ 11,478
Derivative liabilities	149,008	50,372
Derivative assets	2,912	2,092
Derivative liabilities	42,620	23,815
Derivative assets	12,543	13,570
Derivative liabilities	191,628	74,187
Interest Rate Swap
Derivatives, Fair Value [Line Items]
Derivative liabilities	500
Interest Rate Swap | Derivative assets/liabilities – current
Derivatives, Fair Value [Line Items]
Derivative assets	0	0
Derivative liabilities	458	1,480
Interest Rate Swap | Derivative assets/liabilities – non-current
Derivatives, Fair Value [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative liabilities	178,600
Commodity contracts | Derivative assets/liabilities – current
Derivatives, Fair Value [Line Items]
Derivative assets	9,631	11,478
Derivative liabilities	148,550	48,892
Commodity contracts | Derivative assets/liabilities – non-current
Derivatives, Fair Value [Line Items]
Derivative assets	2,912	2,092
Derivative liabilities	$ 42,620	$ 23,815

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Property and Equipment - Summary of Property and Equipment (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Oil and gas properties:
Proved	$ 2,412,399	$ 2,327,686
Unproved	58,686	57,900
Total oil and gas properties	2,471,085	2,385,586
Other property and equipment	31,060	31,055
Total properties and equipment	2,502,145	2,416,641
Accumulated depreciation, depletion, amortization and impairments	(1,084,430)	(1,033,293)
Total property and equipment, net	$ 1,417,715	$ 1,383,348

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Property and Equipment - Narrative (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2022 USD ($) $ / bbl $ / bbl	Mar. 31, 2021 USD ($) $ / bbl	Dec. 31, 2021 USD ($)
Property, Plant and Equipment [Line Items]
Unproved oil and gas property excluded	$ 58,700		$ 57,900
Undeveloped leasehold costs transferred	700	$ 7,600
Capitalized costs, proved properties	1,400	700
Interest costs capitalized	$ 1,100	$ 800
Amortization expense per physical unit of production | $ / bbl	14.98	12.92
Impairments of oil and gas properties	$ 0	$ 1,811
West Texas Intermediate
Property, Plant and Equipment [Line Items]
Oil price per barrel (in dollars per barrel) | $ / bbl	120

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Long-Term Debt - Summary of Long-Term Debt (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021	Aug. 10, 2021
Debt Instrument [Line Items]
Long-term debt, gross	$ 536,713		$ 618,954
Less: Unamortized discount	(3,560)		(3,720)
Less: Unamortized deferred issuance costs	(9,448)		(9,853)
Total, net	523,705		605,381
Less: Current portion	(1,925)		(4,129)
Long-term debt, net	521,780		601,252
Gain (loss) on extinguishment of debt	2,157	$ (1,231)
Line of Credit
Debt Instrument [Line Items]
Long-term debt, gross	128,000		208,000
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%
Mortgage debt
Debt Instrument [Line Items]
Long-term debt, gross	8,391		8,438
Other
Debt Instrument [Line Items]
Long-term debt, gross	322		$ 2,516
Gain (loss) on extinguishment of debt	$ 2,200

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Long-Term Debt - Narrative (Details) - USD ($)	3 Months Ended
	Mar. 31, 2022	Aug. 10, 2021	Mar. 31, 2021
Debt Disclosure [Line Items]
Current ratio	1.00
Debt to EBITD ratio, maximum	3.50
Debt issuance costs, line of credit arrangements, gross			$ 400,000
Senior notes		$ 400,000,000
Senior notes, redemption percentage		99.018%
Revolving Credit Facility
Debt Disclosure [Line Items]
Line of credit facility, interest rate at period end	3.02%
Commitment fee	0.50%
Revolving Credit Facility | Minimum
Debt Disclosure [Line Items]
Interest rate	1.50%
Revolving Credit Facility | Maximum
Debt Disclosure [Line Items]
Interest rate	2.50%
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 | LIBOR | Minimum
Debt Disclosure [Line Items]
Applicable margin	2.50%
Revolving Credit Facility | LIBOR | Maximum
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	400,000,000
Outstanding borrowings	128,000,000
Letters of credit outstanding	700,000
Remaining borrowing capacity	271,300,000
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	$ 725,000,000
Senior Notes Due 2026 | Senior Notes
Debt Disclosure [Line Items]
Interest rate		9.25%

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Income Taxes (Details) - USD ($)	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income tax benefit	$ 200,000	$ 300,000
Change in deferred tax assets valuation allowance, percent	0.90%	1.50%
Deferred tax liabilities, tax deferred income	$ 2,100,000
Unrecognized tax benefits	0		$ 0
Income tax examination, penalties and interest expense	$ 0	$ 0

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Supplemental Balance Sheet Detail (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Prepaid and other current assets:
Inventories	$ 13,025	$ 10,305
Prepaid expenses	2,964	10,693
Prepaid and other current assets	15,989	20,998
Other assets:
Deferred issuance costs of the Credit Facility, net of amortization	3,138	3,308
Right-of-use assets – operating leases	1,498	1,671
Other	0	38
Other assets	4,636	5,017
Accounts payable and accrued liabilities:
Trade accounts payable	32,463	32,452
Drilling and other lease operating costs	47,103	35,045
Revenue and royalties payable	110,493	95,521
Production, ad valorem and other taxes	12,224	7,905
Derivative settlements to counterparties	25,146	6,117
Compensation and benefits	7,957	13,942
Interest	5,003	15,321
Environmental remediation liability	2,277	2,287
Current operating lease obligations	891	914
Other	2,632	4,877
Accounts payable and accrued liabilities	246,189	214,381
Other non-current liabilities:
Asset retirement obligations	8,186	8,413
Non-current operating lease obligations	755	975
Postretirement benefit plan obligations	959	970
Other non-current liabilities	9,900	10,358
Tubular inventory and well materials	12,200	9,500
Capitalized costs - crude oil in storage	800	800
Drilling and completion prepayment	$ 600	$ 9,600

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Fair Value Measurements - Narrative (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021	Aug. 10, 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, gross	$ 536,713	$ 618,954
Long-term debt, fair value	559,400	634,600
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%

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Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - USD ($) $ in Thousands	Mar. 31, 2022	Dec. 31, 2021
Financial assets:
Commodity derivative assets – current	$ 9,631	$ 11,478
Commodity derivative assets – non-current	2,912	2,092
Derivative assets	12,543	13,570
Financial liabilities:
Derivative liabilities – current	(149,008)	(50,372)
Derivative liabilities, noncurrent	(42,620)	(23,815)
Derivative liabilities	(191,628)	(74,187)
Fair Value, Measurements, Recurring
Financial assets:
Derivative assets	12,543	13,570
Financial liabilities:
Derivative liabilities	(191,628)	(74,187)
Commodity contracts
Financial liabilities:
Derivative liabilities	(178,600)
Commodity contracts | Fair Value, Measurements, Recurring
Financial assets:
Commodity derivative assets – current	9,631	11,478
Commodity derivative assets – non-current	2,912	2,092
Financial liabilities:
Derivative liabilities – current	(148,550)	(48,892)
Derivative liabilities, noncurrent	(42,620)	(23,815)
Interest Rate Swap
Financial liabilities:
Derivative liabilities	(500)
Interest Rate Swap | Fair Value, Measurements, Recurring
Financial liabilities:
Derivative liabilities – current	(458)	(1,480)
Level 1 | Fair Value, Measurements, Recurring
Financial assets:
Derivative assets	0	0
Financial liabilities:
Derivative 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 1 | Interest Rate Swap | Fair Value, Measurements, Recurring
Financial liabilities:
Derivative liabilities – current	0	0
Level 2 | Fair Value, Measurements, Recurring
Financial assets:
Derivative assets	12,543	13,570
Financial liabilities:
Derivative liabilities	(191,628)	(74,187)
Level 2 | Commodity contracts | Fair Value, Measurements, Recurring
Financial assets:
Commodity derivative assets – current	9,631	11,478
Commodity derivative assets – non-current	2,912	2,092
Financial liabilities:
Derivative liabilities – current	(148,550)	(48,892)
Derivative liabilities, noncurrent	(42,620)	(23,815)
Level 2 | Interest Rate Swap | Fair Value, Measurements, Recurring
Financial liabilities:
Derivative liabilities – current	(458)	(1,480)
Level 3 | Fair Value, Measurements, Recurring
Financial assets:
Derivative assets	0	0
Financial liabilities:
Derivative 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
Level 3 | Interest Rate Swap | Fair Value, Measurements, Recurring
Financial liabilities:
Derivative liabilities – current	$ 0	$ 0

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Commitments and Contingencies - Narrative (Details)	3 Months Ended
	Mar. 31, 2022 USD ($) rig bbl	Mar. 31, 2021 USD ($)	Dec. 31, 2021 USD ($)
Commitments and Contingencies Disclosure [Line Items]
Drilling rig, contract period	1 year
Unrecorded unconditional purchase obligation, change of amount as result of variable components	$ 90
Unrecorded unconditional purchase obligation, purchases	10,200,000	$ 8,400,000
Estimated litigation liability, current	100,000		$ 100,000
Asset retirement obligation	8,200,000		8,400,000
Environmental remediation liability	$ 2,277,000		$ 2,287,000
Drilling Rig With Contractual Term
Commitments and Contingencies Disclosure [Line Items]
Drilling rigs | rig	1
Drilling Rig With Pad-to-Pad Basis Commitment
Commitments and Contingencies Disclosure [Line Items]
Drilling rigs | rig	1
Crude Oil Gathering And Transportation Services
Commitments and Contingencies Disclosure [Line Items]
Purchase obligation, remainder of 2022	$ 10,500,000
Purchase obligation, year 2023	13,900,000
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
Nuevo G&T | Crude Oil Storage Capacity with Downstream Interstate Pipeline
Commitments and Contingencies Disclosure [Line Items]
Number of barrels | bbl	90,000
South Texas Region | Crude Oil Storage Capacity
Commitments and Contingencies Disclosure [Line Items]
Number of barrels | bbl	340,000
Nuevo Dos Gathering and Transportation, LLC-Marketing Affiliate | Crude Oil Storage Capacity with Downstream Interstate Pipeline
Commitments and Contingencies Disclosure [Line Items]
Number of barrels | bbl	62,000
Nuevo Dos Gathering and Transportation, LLC-Marketing Affiliate | Additional Crude Oil Storage Capacity With Downstream Interstate Pipeline
Commitments and Contingencies Disclosure [Line Items]
Number of barrels | bbl	120,000

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Commitments and Contingencies - Purchase Commitment, Excluding Long-term Commitment (Details)	3 Months Ended
	Mar. 31, 2022 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

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Share-Based Compensation and Other Benefit Plans - Narrative (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based compensation	$ 924	$ 2,246
Defined contribution plan, cost	200	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)	762,259
Award vesting period	3 years
Cost not yet recognized, amount	$ 1,200
Cost not yet recognized, period for recognition	1 year 8 months 15 days
Performance Shares
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Number of shares authorized (in shares)	484,197
Award vesting period	3 years
Cost not yet recognized, amount	$ 3,900
Cost not yet recognized, period for recognition	1 year 11 months 8 days
Options, outstanding, number (in shares)	345,069
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	0.00%
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	200.00%
Change in Control
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based compensation	$ 1,900
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

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Share-Based Compensation and Other Benefit Plans - Summary of Restricted Stock Unit Activity (Details) - Restricted Stock Units (RSUs)	3 Months Ended
	Mar. 31, 2022 $ / shares shares
Restricted Stock Units
Balance at beginning of period (in shares) | shares	230,517
Granted (in shares) | shares	0
Vested (in shares) | shares	(69,206)
Forfeited (in shares) | shares	0
Balance at end of period (in shares) | shares	161,311
Weighted-Average Grant Date Fair Value
Balance at beginning of period (in dollars per share) | $ / shares	$ 9.20
Granted (in dollars per share) | $ / shares	0
Vested (in dollars per share) | $ / shares	(7.94)
Forfeited (in shares) | $ / shares	0
Balance at end of period (in shares) | $ / shares	$ 10.52

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Share-Based Compensation and Other Benefit Plans - Schedule of Valuation Assumptions (Details) - Performance Shares	3 Months Ended
	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	0.00%	0.00%	0.00%
Risk-free interest rate, minimum	0.22%	0.18%
Risk-free interest rate, maximum	0.29%	0.51%
Risk-free interest rate			1.66%
Minimum
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expected volatility	131.74%	101.32%
Maximum
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expected volatility	134.74%	117.71%

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Earnings Per Share - Narrative (Details) - $ / shares	Mar. 31, 2022	Dec. 31, 2021
Common Class B
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Series A Preferred Stock
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01

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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, 2022	Mar. 31, 2021
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net loss	$ (20,661)	$ (20,021)
Net loss attributable to Noncontrolling interest	10,676	6,449
Net loss attributable to common shareholders (basic)	(9,985)	(13,572)
Reallocation of Noncontrolling interest net loss	(10,676)	(6,449)
Net loss attributable to common shareholders (diluted)	$ (20,661)	$ (20,021)
Weighted-average shares – basic (in shares)	21,107	15,263
Effect of dilutive securities:
Common Units and Series A Preferred Stock that are exchangeable for common shares (in shares)	0	0
RSUs and PRSUs (in shares)	0	0
Weighted-average shares – diluted (in shares)	21,107	15,263
Antidilutive securities excluded from computation of earnings per share (in shares)		22,700
Restricted Stock Units and Performance Stock Units
Effect of dilutive securities:
Antidilutive securities excluded from computation of earnings per share (in shares)	600	200
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
Series A Preferred Stock
Effect of dilutive securities:
Antidilutive securities excluded from computation of earnings per share (in shares)		200

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Subsequent Events (Details) - Subsequent Event - USD ($)	May 03, 2022	Apr. 13, 2022
Subsequent Event [Line Items]
Maximum debt leverage ratio		100.00%
Bolt-On
Subsequent Event [Line Items]
Cash payment to acquire business	$ 64,000,000
Common Class A
Subsequent Event [Line Items]
Stock repurchase program, authorized amount		$ 100,000,000