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 September 30, 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 October 28, 2022, there were 41,669,837 shares of common stock outstanding, including 19,120,839 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 September 30, 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 Income - 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 – Basis of Presentation and Significant Accounting Policies	8
	Note 3 – Acquisitions	10
	Note 4 – Revenue Recognition	11
	Note 5 – Derivative Instruments	13
	Note 6 – Property and Equipment, Net	15
	Note 7 – Long-Term Debt	16
	Note 8 – Income Taxes	17
	Note 9 – Supplemental Balance Sheet Detail	18
	Note 10 – Fair Value Measurements	18
	Note 11 – Commitments and Contingencies	20
	Note 12 – Shareholders’ Equity	21
	Note 13 – Share-Based Compensation and Other Benefit Plans	23
	Note 14 – Earnings per Share	25
	Note 15 – Subsequent Events	25
Forward-Looking Statements		26
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
	Overview and Executive Summary	28
	Results of Operations	31
	Liquidity and Capital Resources	40
	Critical Accounting Estimates	43
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	44
Item 4.	Controls and Procedures	45
	Part II - Other Information
Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	45
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3.	Defaults Upon Senior Securities	45
Item 4.	Mine Safety Disclosures	45
Item 5.	Other Information	45
Item 6.	Exhibits	46
Signatures		47

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 September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Revenues and other
Crude oil	$	262,537	$	127,995	$	762,858	$	326,222
Natural gas liquids	18,669		7,165		54,227		15,115
Natural gas	22,899		4,973		56,063		10,893
Other operating income, net	985		928		2,888		2,085
Total revenues and other	305,090		141,061		876,036		354,315
Operating expenses
Lease operating	24,123		10,647		61,133		29,200
Gathering, processing and transportation	9,794		5,688		27,472		15,535
Production and ad valorem taxes	16,698		7,534		46,612		19,768
General and administrative	9,829		10,932		30,243		31,094
Depreciation, depletion and amortization	66,204		30,975		171,387		83,654
Impairments of oil and gas properties	—		—		—		1,811
Total operating expenses	126,648		65,776		336,847		181,062
Operating income	178,442		75,285		539,189		173,253
Other income (expense)
Interest expense, net of amounts capitalized	(13,160)		(10,582)		(34,895)		(21,282)
Gain (loss) on extinguishment of debt	—		—		2,157		(1,231)
Derivative gains (losses)	63,756		(21,084)		(149,073)		(119,679)
Other, net	599		(7)		757		(13)
Income before income taxes	229,637		43,612		358,135		31,048
Income tax expense	(2,052)		(549)		(3,171)		(410)
Net income	227,585		43,063		354,964		30,638
Net income attributable to Noncontrolling interest	(121,349)		(25,676)		(187,529)		(23,778)
Net income attributable to common shareholders	$	106,236	$	17,387	$	167,435	$	6,860
Net income per share attributable to common shareholders:
Basic	$	5.38	$	1.13	$	8.14	$	0.45
Diluted	$	5.26	$	1.11	$	7.97	$	0.44
Weighted average shares outstanding – basic	19,741		15,319		20,573		15,298
Weighted average shares outstanding – diluted	20,341		15,713		21,155		15,669

See accompanying notes to condensed consolidated financial statements.

3

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME – UNAUDITED

(in thousands) 

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Net income	$	227,585	$	43,063	$	354,964	$	30,638
Other comprehensive income:
Change in pension and postretirement obligations, net of tax	—		1		—		4
Comprehensive income	227,585		43,064		354,964		30,642
Net income attributable to Noncontrolling interest	(121,349)		(25,676)		(187,529)		(23,778)
Other comprehensive income attributable to Noncontrolling interest	—		(1)		—		(4)
Comprehensive income attributable to common shareholders	$	106,236	$	17,387	$	167,435	$	6,860

See accompanying notes to condensed consolidated financial statements.

4

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS – UNAUDITED

(in thousands, except share data)

	September 30, 2022		December 31, 2021
Assets
Current assets
Cash and cash equivalents	$	20,344	$	23,681
Accounts receivable, net of allowance for credit losses	147,823		118,594
Derivative assets	30,725		11,478
Prepaid and other current assets	13,049		20,998
Assets held for sale	1,186		11,400
Total current assets	213,127		186,151
Property and equipment, net	1,711,367		1,383,348
Derivative assets	6,176		2,092
Other assets	4,686		5,017
Total assets	$	1,935,356	$	1,576,608
Liabilities and Equity
Current liabilities
Accounts payable and accrued liabilities	$	264,364	$	214,381
Derivative liabilities	75,327		50,372
Current portion of long-term debt	41		4,129
Total current liabilities	339,732		268,882
Deferred income taxes	4,957		2,793
Derivative liabilities	12,748		23,815
Other non-current liabilities	9,930		10,358
Long-term debt, net	603,457		601,252
Commitments and contingencies (Note 11)
Equity
Preferred stock of $0.01 par value – 5,000,000 shares authorized; none issued as of September 30, 2022 and December 31, 2021	—		—
Class A common stock, $0.01 par value – 110,000,000 shares authorized; 19,422,156 and 21,090,259 issued and outstanding as of September 30, 2022 and December 31, 2021, respectively	194		729
Class B common stock, $0.01 par value – 30,000,000 shares authorized; 22,548,998 shares issued and outstanding as of September 30, 2022 and December 31, 2021	2		2
Paid-in capital	230,777		273,329
Retained earnings	215,475		49,583
Accumulated other comprehensive loss	(111)		(111)
Ranger Oil shareholders’ equity	446,337		323,532
Noncontrolling interest	518,195		345,976
Total equity	964,532		669,508
Total liabilities and equity	$	1,935,356	$	1,576,608

See accompanying notes to condensed consolidated financial statements.

5

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – UNAUDITED

(in thousands)

	Nine Months Ended September 30,
	2022		2021
Cash flows from operating activities
Net income	$	354,964	$	30,638
Adjustments to reconcile net income to net cash provided by operating activities:
(Gain) loss on extinguishment of debt	(2,157)		1,231
Depreciation, depletion and amortization	171,387		83,654
Impairments of oil and gas properties	—		1,811
Derivative contracts:
Net losses	149,073		119,679
Cash settlements and premiums paid, net	(159,224)		(46,041)
Deferred income tax expense	2,164		130
Non-cash interest expense	2,441		1,742
Share-based compensation	4,327		4,179
Other, net	(180)		13
Changes in operating assets and liabilities, net	(33,613)		7,671
Net cash provided by operating activities	489,182		204,707
Cash flows from investing activities
Capital expenditures	(307,766)		(146,638)
Acquisitions of oil and gas properties	(129,784)		—
Proceeds from sales of assets, net	10,900		157
Net cash used in investing activities	(426,650)		(146,481)
Cash flows from financing activities
Proceeds from credit facility borrowings	483,000		20,000
Repayments of credit facility borrowings	(476,000)		(121,500)
Repayments of second lien term loan	—		(56,890)
Proceeds from 9.25% Senior Notes due 2026, net of discount	—		396,072
Repayments of acquired debt	(8,513)		—
Payments for share repurchases	(59,414)		—
Distributions to Noncontrolling interest	(1,691)		—
Dividends paid	(1,492)		—
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	(954)		(623)
Debt issuance costs paid	(805)		(3,397)
Net cash (used in) provided by financing activities	(65,869)		375,523
Net increase (decrease) in cash, cash equivalents and restricted cash	(3,337)		433,749
Cash, cash equivalents and restricted cash – beginning of period	23,681		13,020
Cash, cash equivalents and restricted cash – end of period	$	20,344	$	446,769
Supplemental disclosures:
Cash paid for:
Interest, net of amounts capitalized	$	42,678	$	14,298
Income taxes refunds, net	$	—	$	360
Non-cash investing and financing activities:
Changes in property and equipment related to capital contributions	$	—	$	(38,561)
Changes in accrued liabilities related to capital expenditures	$	55,008	$	30,303

 See accompanying notes to condensed consolidated financial statements.

6

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - UNAUDITED

(in thousands)

	Shares
	Class A Common Shares Outstanding	Class B Common Shares Outstanding	Class A Common Stock		Class B Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Loss		Noncontrolling interest		Total Equity
Balance as of December 31, 2021	21,090	22,549	$	729	$	2	$	273,329	$	49,583	$	(111)	$	345,976	$	669,508
Net loss	—	—	—		—		—		(9,985)		—		(10,676)		(20,661)
Common stock issued related to share-based compensation and other, net	56	—	—		—		478		—		—		—		478
Balance as of March 31, 2022	21,146	22,549	$	729	$	2	$	273,807	$	39,598	$	(111)	$	335,300	$	649,325
Net income	—	—	—		—		—		71,184		—		76,856		148,040
Repurchase of Class A Common Stock	(681)	—	(7)		—		(25,052)		—		—		—		(25,059)
Change in ownership, net	—	—	—		—		6,498		—		—		(6,498)		—
Common stock issued related to share-based compensation and other, net	18	—	(517)		—		2,362		—		—		—		1,845
Balance as of June 30, 2022	20,483	22,549	$	205	$	2	$	257,615	$	110,782	$	(111)	$	405,658	$	774,151
Net income	—	—	—		—		—		106,236		—		121,349		227,585
Repurchase of Class A Common Stock	(1,075)	—	(11)		—		(35,011)		—		—		—		(35,022)
Change in ownership, net	—	—	—		—		7,121		—		—		(7,121)		—
Distributions to Noncontrolling interest	—	—	—		—		—		—		—		(1,691)		(1,691)
Dividends declared ($0.075 per share of Class A common stock)	—	—	—		—		—		(1,543)		—		—		(1,543)
Common stock issued related to share-based compensation and other, net	14	—	—		—		1,052		—		—		—		1,052
Balance as of September 30, 2022	19,422	22,549	$	194	$	2	$	230,777	$	215,475	$	(111)	$	518,195	$	964,532

	Shares
	Preferred Shares Outstanding		Common Shares Outstanding		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	—		15,200		$	—	$	152	$	203,463	$	9,354	$	(131)	$	—	$	212,838
Net loss	—		—		—		—		—		(13,572)		—		(6,449)		(20,021)
Issuance of preferred stock	225,490		—		2		—		—		—		—		—		2
Issuance of Noncontrolling interest	—		—		—		—		(50,068)		—		—		229,620		179,552
Common stock issued related to share-based compensation and other, net	—		110		—		1		1,769		—		1		1		1,772
Balance as of March 31, 2021	225,490		15,310		$	2	$	153	$	155,164	$	(4,218)	$	(130)	$	223,172	$	374,143
Net income	—		—		—		—		—		3,045		—		4,551		7,596
Common stock issued related to share-based compensation and other, net	—		2		—		—		922		—		1		1		924
Balance as of June 30, 2021	225,490		15,312		$	2	$	153	$	156,086	$	(1,173)	$	(129)	$	227,724	$	382,663
Net income	—		—		—		—		—		17,387		—		25,676		43,063
Common stock issued related to share-based compensation and other, net	—		19		—		—		864		—		(1)		1		864
Balance as of September 30, 2021	$	225,490	$	15,331	$	2	$	153	$	156,950	$	16,214	$	(130)	$	253,401	$	426,590

_______________________

In October 2021, the Company effected a recapitalization, pursuant to which, among other things, the Company’s common stock was renamed and reclassified as Class A common stock, par value $0.01 per share (“Class A Common Stock”), a new class of capital stock of the Company, Class B Common Stock, par value $0.01 per share (“Class B Common Stock”) was authorized, and the designation of the Series A Preferred Stock was cancelled. See Note 12 in the notes to condensed consolidated financial statements for further details.

See accompanying notes to condensed consolidated financial statements.

7

RANGER OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – UNAUDITED

For the Quarterly Period Ended September 30, 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, ROCC Energy Holdings, L.P. (formerly 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 (“Rocky Creek”), 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. See Note 2 for further discussion.

Note 2 – Basis of Presentation and Significant Accounting Policies

Basis of Presentation

Our unaudited condensed consolidated financial statements include the accounts of Ranger Oil and all of our subsidiaries as of the relevant dates. Intercompany balances and transactions have been eliminated. A substantial noncontrolling interest in our subsidiaries is provided for in our condensed consolidated statements of operations and comprehensive income 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 (“2021 Annual Report”). Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

Principles of Consolidation

In January 2021, Ranger Oil completed a reorganization into an Up-C structure with JSTX and Rocky Creek. Under the Up-C structure, Juniper owns all of the shares of the Company’s Class B Common Stock which are non-economic voting only shares of the Company. Juniper’s economic interest in the Company is held through its ownership of limited partner interests (the “Common Units”) in the Partnership. Pursuant to the amended and restated limited partnership agreement of the Partnership (the “Partnership Agreement”), the Company’s ownership of Common Units in the Partnership at all times equals the number of shares of the Company’s Class A Common Stock then outstanding, and Juniper’s ownership of Common Units in the Partnership at all times equals the number of shares of Class B Common Stock then outstanding. The Partnership was formed for the purpose of executing the Company’s reorganization with Juniper into an Up-C structure. The Partnership, through its subsidiaries, owns, operates, and manages oil and gas properties in Texas and manages the Company’s outstanding debt and derivative instruments. The Company’s wholly-owned subsidiary, ROCC Energy Holdings GP LLC (formerly, PV Energy Holdings GP, LLC, the “GP”), is the general partner of the Partnership. Subsidiaries of the Partnership own and operate all our oil and gas assets. Ranger Oil and the Partnership are holding companies with no other operations, material cash flows, or material assets or liabilities other than the equity interests in their subsidiaries.

8

The Common Units are redeemable (concurrently with the cancellation of an equivalent number of shares of Class B Common Stock) by Juniper at any time on a one-for-one basis in exchange for shares of Class A Common Stock or, if the Partnership elects, cash based on the 5-day average volume-weighted closing price for the Class A Common Stock immediately prior to the redemption. In determining whether to make a cash election, the Company would consider the interests of the holders of the Class A Common Stock, the Company’s financial condition, results of operations, earnings, projections, liquidity and capital requirements, management’s assessment of the intrinsic value of the Class A Common Stock, the trading price of the Class A Common Stock, legal requirements, covenant compliance, restrictions in the Company’s debt agreements and other factors it deems relevant.

The Partnership is considered a variable interest entity for which the Company is the primary beneficiary. The Company has benefits in the Partnership through the Common Units, and it has power over the activities most significant to the Partnership’s economic performance through its 100% controlling interest in the GP (which, accordingly, is acting as an agent on behalf of the Company). This conclusion was based on a qualitative analysis that considered the Partnership’s governance structure and the GP’s control over operations of the Partnership. The GP manages the business and affairs of the Partnership, including key Partnership decision-making, and the limited partners do not possess any substantive participating or kick-out rights that would allow Juniper to block or participate in certain operational and financial decisions that most significantly impact the Partnership’s economic performance or that would remove the GP. As such, because the Company has both power and benefits in the Partnership, the Company determined it is the primary beneficiary of the Partnership and consolidates the Partnership in the Company’s consolidated financial statements. The Company reflects a noncontrolling interest in the consolidated financial statements based on the proportion of Common Units owned by Juniper relative to the total number of Common Units outstanding. The noncontrolling interest is presented as a component of equity in the accompanying condensed consolidated financial statements and represents the ownership interest held by Juniper in the Partnership.

Noncontrolling Interest

The noncontrolling interest percentage may be affected by the issuance of shares of Class A Common Stock, repurchases or cancellation of Class A Common Stock, the exchange of Class B Common Stock and the redemption of Common Units (and concurrent cancellation of Class B Common Stock), among other things. The percentage is based on the proportionate number of Common Units held by Juniper relative to the total Common Units outstanding. As of September 30, 2022, the Company owned 19,422,156 Common Units, representing a 46.3% limited partner interest in the Partnership, and Juniper owned 22,548,998 Common Units, representing the remaining 53.7% limited partner interest. As of December 31, 2021, the Company owned 21,090,259 Common Units, representing a 48.3% limited partner interest in the Partnership, and Juniper owned 22,548,998 Common Units, representing the remaining 51.7% limited partner interest. During the three and nine months ended September 30, 2022, changes in the ownership interests were the result of share repurchases and issuances of Class A Common Stock in connection with the vesting of employees’ share-based compensation. See Note 12 for information regarding share repurchases and Note 13 for vesting of share-based compensation.

When the Company’s relative ownership interest in the Partnership changes, adjustments to Noncontrolling interest and Paid-in capital, tax effected, will occur. Because these changes in the ownership interest in the Partnership do not result in a change of control, the transactions are accounted for as equity transactions under Accounting Standards Codification Topic 810, Consolidation, which requires that any differences between the carrying value of the Company’s basis in the Partnership and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. Additionally, based on the Partnership Agreement, there are no substantive profit sharing arrangements that would cause distributions to be other than pro rata. Therefore, profits and losses are attributed to the common shareholders and noncontrolling interest pro rata based on ownership interests in the Partnership.

9

Cash, Cash Equivalents and Restricted Cash

Cash and cash equivalents includes cash and highly liquid investments with original maturities of three months or less from the date of purchase. Restricted cash represents cash that is not readily available for general purpose cash needs. As of September 30, 2022 and December 31, 2021, the Company had no cash equivalents or restricted cash.

Of the $446.8 million in total cash, cash equivalents and restricted cash presented on the condensed consolidated statement of cash flows as of September 30, 2021, the Company had cash of $35.3 million, restricted cash – current of $15.4 million and restricted cash – non-current of $396.1 million. The restricted cash related to the net proceeds received from the offering of senior unsecured notes and certain additional funds that were held in escrow and subsequently released upon the acquisition of Lonestar Resources US Inc., a Delaware corporation (“Lonestar”). See Note 3 for additional information on this acquisition and Note 7 for additional information on the senior unsecured notes.

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 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.

Note 3 – Acquisitions and Dispositions

2022

Asset Acquisitions

In the second and third quarters of 2022, we completed acquisitions of additional working interests in Ranger-operated wells along with certain contiguous oil and gas producing assets and undeveloped acreage in the Eagle Ford shale. The aggregate cash consideration for these acquisitions was $129.8 million, subject to customary post-closing adjustments. These transactions were accounted for as asset acquisitions.

Asset Disposition

On July 22, 2022, we closed on the sale of 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 September 30, 2022 and December 31, 2021. Gross proceeds were $11.0 million with costs to sell of approximately $0.8 million and included the payoff of the related mortgage debt and accrued interest of $8.4 million for total net proceeds of $1.8 million. This transaction did not result in any material change to the purchase allocation further described below.

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2021

Acquisition of Lonestar Resources

On October 5, 2021 (the “Closing Date”), the Company acquired 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 are recorded at their respective fair values as of the date of completion of the Lonestar Acquisition. The Company completed the purchase price allocation during the third quarter of 2022, and there were no material changes to the allocation presented in the 2021 Form 10-K.

We expensed $2.0 million in acquisition-related costs for the nine months ended September 30, 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 and nine months ended September 30, 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 September 30, 2021		Nine Months Ended September 30, 2021
Total revenues	$	200,995	$	500,087
Net income (loss) attributable to common shareholders	$	12,531	$	(19,174)

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.

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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. Our oil, natural gas, and NGL receivables are typically collected within 30 to 90 days. The following table summarizes our accounts receivable by type as of the dates presented:

	September 30, 2022		December 31, 2021
Customers	$	123,493	$	96,195
Joint interest partners	22,964		21,755
Derivative settlements from counterparties 1	1,619		1,037
Other	99		18
Total	148,175		119,005
Less: Allowance for credit losses	(352)		(411)
Accounts receivable, net of allowance for credit losses	$	147,823	$	118,594

_______________________

1     See Note 5 for information regarding our derivative instruments.

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Note 5 – Derivative Instruments

We utilize derivative instruments, typically swaps, put options and call options which are placed with financial institutions that we believe are acceptable credit risks, to mitigate our financial exposure to commodity price volatility associated with anticipated sales of our future production and volatility in interest rates attributable to our variable rate debt instruments. Our derivative instruments are not designated as hedges for accounting purposes. While the use of derivative instruments limits the risk of adverse commodity price and interest rate movements, such use may also limit the beneficial impact of future product revenues and interest expense from favorable commodity price and interest rate movements. From time to time, we may enter into incremental derivative contracts in order to increase the notional volume of production we are hedging, restructure existing derivative contracts or enter into other derivative contracts resulting in modification to the terms of existing contracts. In accordance with our internal policies, we do not utilize derivative instruments for speculative purposes.

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

Commodity Derivatives 1

The following table sets forth our commodity derivative positions, presented on a net basis by period of maturity, as of September 30, 2022:

	4Q2022		1Q2023		2Q2023		3Q2023		4Q2023		1Q2024		2Q2024
NYMEX WTI Crude Swaps
Average Volume Per Day (bbl)	3,000		2,500		2,400		2,807		2,657		462		462
Weighted Average Swap Price ($/bbl)	$	69.20	$	54.40	$	54.26	$	54.92	$	54.93	$	58.75	$	58.75
NYMEX WTI Crude Collars
Average Volume Per Day (bbl)	20,245		12,917		11,126		8,152		4,891
Weighted Average Purchased Put Price ($/bbl)	$	64.56	$	63.23	$	61.48	$	72.00	$	70.00
Weighted Average Sold Call Price ($/bbl)	$	88.78	$	79.67	$	74.31	$	89.91	$	86.04
NYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (bbl)	3,804
Weighted Average Swap Price ($/bbl)	$	1.751
NYMEX HH Swaps
Average Volume Per Day (MMBtu)	12,500		10,000		7,500
Weighted Average Swap Price ($/MMBtu)	$	3.793	$	3.620	$	3.690
NYMEX HH Collars
Average Volume Per Day (MMBtu)	14,511		14,617		11,538		11,413		11,413		11,538		11,538
Weighted Average Purchased Put Price ($/MMBtu)	$	2.854	$	6.561	$	2.500	$	2.500	$	2.500	$	2.500	$	2.328
Weighted Average Sold Call Price ($/MMBtu)	$	3.791	$	12.334	$	2.682	$	2.682	$	2.682	$	3.650	$	3.000
OPIS Mt. Belv Ethane Swaps
Average Volume per Day (gal)	27,717				98,901		34,239		34,239		34,615
Weighted Average Fixed Price ($/gal)	$	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

Through May 2022, we had a series of interest rate swap contracts (the “Interest Rate Swaps”) establishing fixed interest rates on a portion of our variable interest rate indebtedness. The notional amount of the Interest Rate Swaps totaled $300 million, with us paying a weighted average fixed rate of 1.36% on the notional amount, and the counterparties paying a variable rate equal to LIBOR. As of September 30, 2022, we did not have any interest rate derivatives.

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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. Adjustments to reconcile net income to net cash provided by operating activities include derivative losses and cash settlements that are reported under Net losses and Cash settlements and premiums paid, net, on our condensed consolidated statements of cash flows, respectively.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Interest Rate Swap gains (losses) recognized in the condensed consolidated statements of operations	$	—	$	(84)	$	64	$	(48)
Commodity gains (losses) recognized in the condensed consolidated statements of operations	63,756		(21,000)		(149,137)		(119,631)
	$	63,756	$	(21,084)	$	(149,073)	$	(119,679)
Interest rate cash settlements recognized in the condensed consolidated statements of cash flows	$	—	$	(973)	$	(1,415)	$	(2,851)
Commodity cash settlements and premiums paid recognized in the condensed consolidated statements of cash flows	(55,302)		(21,265)		(157,809)		(43,190)
	$	(55,302)	$	(22,238)	$	(159,224)	$	(46,041)

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
		September 30, 2022				December 31, 2021
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Interest rate contracts	Derivative assets/liabilities – current	$	—	$	—	$	—	$	1,480
Commodity contracts	Derivative assets/liabilities – current	30,725		75,327		11,478		48,892
Interest rate contracts	Derivative assets/liabilities – non-current	—		—		—		—
Commodity contracts	Derivative assets/liabilities – non-current	6,176		12,748		2,092		23,815
		$	36,901	$	88,075	$	13,570	$	74,187

As of September 30, 2022, we reported net commodity derivative liabilities of $51.2 million. The contracts associated with these positions are with seven counterparties for commodity derivatives, all of which are investment grade financial institutions and are participants in our revolving credit facility (the “Credit Facility”). This concentration may impact our overall credit risk in that these counterparties may be similarly affected by changes in economic or other conditions. Non-performance risk is incorporated by utilizing discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is in a liability position.

The agreements underlying our derivative instruments include provisions for the netting of settlements with the counterparties for contracts of similar type. We have neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. Furthermore, our derivative contracts are not subject to margin calls or similar accelerations. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.

See Note 10 for information regarding the fair value of our derivative instruments.

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Note 6 – Property and Equipment, Net

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

	September 30, 2022		December 31, 2021
Oil and gas properties (full cost accounting method):
Proved	$	2,828,400	$	2,327,686
Unproved	55,429		57,900
Total oil and gas properties	2,883,829		2,385,586
Other property and equipment 1	32,156		31,055
Total properties and equipment	2,915,985		2,416,641
Accumulated depreciation, depletion, amortization and impairments	(1,204,618)		(1,033,293)
Total property and equipment, net	$	1,711,367	$	1,383,348

_______________________

1     Excludes the corporate office building and related other assets acquired in connection with the Lonestar Acquisition that were classified as Assets held for sale on the condensed consolidated balance sheets as of December 31, 2021. We closed on the sale of the corporate office building in July 2022. See Note 3 for additional information. As of September 30, 2022, we had $1.2 million remaining other assets classified as Assets held for sale excluded from above.

Unproved property costs of $55.4 million and $57.9 million have been excluded from amortization as of September 30, 2022 and December 31, 2021, respectively. We transferred $8.7 million and $13.8 million of unproved 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 nine months ended September 30, 2022 and 2021, respectively. We capitalized internal costs of $4.0 million and $2.8 million and interest of $3.3 million and $2.6 million during the nine months ended September 30, 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 $15.84 and $12.96 for the nine months ended September 30, 2022 and 2021, respectively.

Ceiling Test

Beginning in early 2020, certain events such as the COVID-19 pandemic coupled with 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, the deployment of vaccines and resulting increased mobility and global economic activity, and other factors have resulted in increased oil demand and commodity prices. Prior to the announced significant production cut to take effect in November 2022, OPEC+ had previously employed a strategy to gradually increase production. These shifts in OPEC+ production levels as well as the Russia-Ukraine war and related sanctions, which began in the first quarter of 2022, continue to contribute to a high level of uncertainty surrounding energy supply and demand resulting in volatile commodity prices. WTI crude oil and natural gas prices surged with prices over $120 per bbl and over $9 per Mcf, respectively, during the first half of 2022 due to oil supply shortage concerns. During the third quarter of 2022, WTI crude oil and natural gas prices dropped to lows under $77 per bbl and $6 per Mcf, 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”). The Ceiling Test utilizes commodity prices based on a trailing 12-month average based on the closing prices on the first day of each month. We did not record any impairments of our oil and gas properties during the three and nine months ended September 30, 2022. The first quarter of 2021 was impacted by the decline in commodity prices as a result of COVID-19 and macroeconomic factors as discussed above, resulting in an impairment of our oil and gas properties of $1.8 million during the three months ended March 31, 2021. No further impairments were recorded during the remainder of 2021.

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Note 7 – Long-Term Debt

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

	September 30, 2022		December 31, 2021
Credit Facility	$	215,000	$	208,000
9.25% Senior Notes due 2026	400,000		400,000
Mortgage debt 1	—		8,438
Other 2	284		2,516
Total	615,284		618,954
Less: Unamortized discount 3	(3,227)		(3,720)
Less: Unamortized deferred issuance costs 3, 4	(8,559)		(9,853)
Total, net	603,498		605,381
Less: Current portion	(41)		(4,129)
Long-term debt	$	603,457	$	601,252

_______________________

1     The mortgage debt related to the corporate office building and related other assets acquired in connection with the Lonestar Acquisition for which assets were held as collateral for such debt. As of December 31, 2021, these assets met the held for sale criteria and were classified as Assets held for sale on the condensed consolidated balance sheets. In July 2022, the mortgage debt was fully repaid in connection with the sale of the corporate office building. See Note 3 for additional information on the sale.

2     Other debt of $2.2 million was extinguished during the nine months ended September 30, 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 September 30, 2022, the Credit Facility had a $1.0 billion revolving commitment and a $950 million borrowing base with aggregate elected commitments of $500 million, and a $25 million sublimit for the issuance of letters of credit. Availability under the Credit Facility may not exceed the lesser of the aggregate elected commitments or the borrowing base less outstanding advances and letters of credit. The borrowing base under the Credit Facility is redetermined semi-annually, generally in the Spring and Fall of each year. Additionally, we and the Credit Facility lenders may, upon request, initiate a redetermination at any time during the six-month period between scheduled redeterminations. The Credit Facility is available to us for general corporate purposes, including working capital.

In June 2022, we entered into the Agreement and Amendment No. 12 to Credit Agreement (the “Twelfth Amendment”). The Twelfth Amendment, in addition to other changes described therein, amended the Credit Facility to, effective on June 1, 2022, (1) increase the borrowing base from $725 million to $875 million, with aggregate elected commitments remaining at $400 million and (2) replaced LIBOR with the Secured Overnight Financing Rate (“SOFR”), an index supported by short-term Treasury repurchase agreements.

In September 2022, we entered into the Agreement and Amendment No. 13 to Credit Agreement (the “Thirteenth Amendment”). The Thirteenth Amendment, in addition to other changes described therein, amended the Credit Facility to (1) increase the borrowing base from $875 million to $950 million and (2) increase the aggregate elected commitment amounts under the Credit Facility from $400 million to $500 million.

The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 1.50% to 2.50%, determined based on the utilization level under the Credit Facility or (b) effective June 1, 2022, a term SOFR reference rate (a Eurodollar rate, including LIBOR prior to June 1, 2022), 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 September 30, 2022, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 5.63%. Unused commitment fees are charged at a rate of 0.50%.

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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 September 30, 2022, we were in compliance with all debt covenants under the Credit Facility.

We had $215.0 million in outstanding borrowings and $0.7 million in outstanding letters of credit under the Credit Facility as of September 30, 2022. Factoring in the outstanding letters of credit, we had $284.3 million of availability under the Credit Facility as of September 30, 2022. During the nine months ended September 30, 2022 and 2021, we incurred and capitalized approximately $0.8 million and $0.7 million of issue costs associated with amendments to the Credit Facility, respectively.

9.25% Senior Notes due 2026

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

Interest on the 9.25% Senior Notes due 2026 is payable semi-annually in arrears on February 15 and August 15 of each year. We may redeem the 9.25% Senior Notes due 2026 at any time in whole or in part from time to time at specified redemption prices.

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

As of September 30, 2022, we were in compliance with all debt covenants under the indenture.

Note 8 – Income Taxes

The income tax provision resulted in an expense of $2.1 million and an expense of $3.2 million for the three and nine months ended September 30, 2022, respectively. 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 $5.0 million as of September 30, 2022 is also fully attributable to the State of Texas and primarily related to property.

The income tax provision resulted in an expense of $0.5 million and an expense of $0.4 million for the three and nine months ended September 30, 2021, respectively. 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 1.3%, which is fully attributable to the State of Texas.

We had no liability for unrecognized tax benefits as of September 30, 2022 and December 31, 2021. There were no interest and penalty charges recognized during the nine months ended September 30, 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:

	September 30, 2022		December 31, 2021
Prepaid and other current assets:
Inventories 1	$	10,504	$	10,305
Prepaid expenses 2	2,545		10,693
	$	13,049	$	20,998
Other assets:
Deferred issuance costs of the Credit Facility, net of amortization	$	3,603	$	3,308
Right-of-use assets – operating leases	1,083		1,671
Other	—		38
	$	4,686	$	5,017
Accounts payable and accrued liabilities:
Trade accounts payable	$	31,135	$	32,452
Drilling and other lease operating costs	81,225		35,045
Revenue and royalties payable	110,867		95,521
Production, ad valorem and other taxes	15,949		7,905
Derivative settlements to counterparties	5,991		6,117
Compensation and benefits	6,848		13,942
Interest	5,341		15,321
Environmental remediation liability 3	1,519		2,287
Current operating lease obligations	876		914
Other	4,613		4,877
	$	264,364	$	214,381
Other non-current liabilities:
Asset retirement obligations	$	8,691	$	8,413
Non-current operating lease obligations	332		975
Postretirement benefit plan obligations	907		970
	$	9,930	$	10,358

_______________________

1    Includes tubular inventory and well materials of $9.9 million and $9.5 million and crude oil volumes in storage of $0.6 million and $0.8 million as of September 30, 2022 and December 31, 2021, respectively.

2 The balances as of September 30, 2022 and December 31, 2021 include $0.8 million and $9.6 million, respectively, for the prepayment of drilling and completion materials and services.

3 The balance as of September 30, 2022 and December 31, 2021 represents estimated costs associated with remediation activities for certain wells and tanks acquired as part of the Lonestar Acquisition; the remediation will be substantially complete in the fourth quarter of 2022.

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 September 30, 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 September 30, 2022, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $615.3 million and $548.7 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.

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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 September 30, 2022
	Level 1		Level 2		Level 3		Total
Financial assets:
Commodity derivative assets – current	$	—	$	30,725	$	—	$	30,725
Commodity derivative assets – non-current	—		6,176		—		6,176
Total financial assets	$	—	$	36,901	$	—	$	36,901
Financial liabilities:
Interest rate swap liabilities – current	$	—	$	—	$	—	$	—
Commodity derivative liabilities – current	—		(75,327)		—		(75,327)
Commodity derivative liabilities – non-current	—		(12,748)		—		(12,748)
Total financial liabilities	$	—	$	(88,075)	$	—	$	(88,075)

	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, Magellan East Houston (“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 determined the fair values of our interest rate swaps using an income approach valuation technique which discounts future cash flows back to a single present value. We estimated the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these was a Level 2 input. All interest rate swaps matured in May 2022, and as of September 30, 2022, we had not entered into any new interest rate derivative instruments.

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

Non-Recurring Fair Value Measurements

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

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Note 11 – Commitments and Contingencies

Drilling and Completion Commitments

As of September 30, 2022, we had a two year contract for one drilling rig and contracts for two drilling rigs with terms less than one year.

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 September 30, 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 the field gathering and volume capacity support 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 September 30, 2022 and 2021, we recorded expense of $11.1 million and $9.2 million, respectively, and $31.9 million and $26.3 million during the nine months ended September 30, 2022 and 2021, respectively for these contractual obligations.

Excluding the application of credits earned during the 12-month period ended September 30, 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: $3.5 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 September 30, 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 an additional 70,000 barrels of tank capacity at the CDP on a month-to-month basis, which can be terminated by either party with 45 days’ notice to the counterparty. Costs associated with this monthly agreement are in the form of a monthly fixed rate short-term lease and are charged as incurred on a monthly basis to GPT in our condensed consolidated statements of operations.

Other Agreements

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

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

We also have agreements that provide us with services to process our wet gas production into NGL products and dry, or residue, gas. Several agreements covering the majority of our wet gas production extend beyond three years, including one agreement that extends into 2029.

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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 September 30, 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 September 30, 2022 and December 31, 2021, we had AROs of approximately $8.7 million and $8.4 million attributable to the plugging of abandoned wells, respectively. Additionally, we had $1.5 million and $2.3 million of environmental remediation liabilities recorded as part of the Lonestar Acquisition as of September 30, 2022 and December 31, 2021, respectively. The majority of the work related to the environmental remediation liabilities will be completed during the fourth quarter of 2022.

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 – Shareholders’ Equity

Capital Stock

Prior to the Lonestar Acquisition, the Company’s authorized capital stock consisted of 115,000,000 shares including (i) 110,000,000 shares of common stock, par value $0.01 per share and (ii) 5,000,000 shares of Series A Preferred Stock, par value $0.01 per share.

On October 6, 2021, in connection with the consummation of the Lonestar Acquisition, the Company effected a recapitalization, pursuant to which (i) the Company’s common stock was renamed and reclassified as Class A Common Stock, (ii) the authorized number of shares of capital stock of the Company was increased to 145,000,000 shares, (iii) 30,000,000 shares of Class B Common Stock was authorized, (iv) all 225,489.98 outstanding shares of the Series A Preferred Stock were exchanged for 22,548,998 newly issued shares of Class B Common Stock, and (v) the designation of the Series A Preferred Stock was cancelled.

As of September 30, 2022, the Company had two classes of common stock: Class A Common Stock and Class B Common Stock. The holders of record of Class A Common Stock and Class B Common Stock vote together as a single class on all matters on which holders of Class A Common Stock and Class B Common Stock are entitled to vote; except that certain directors are elected by holders of a majority of the shares of Class B Common Stock voting as a separate class.

The holders of Class A Common Stock have no preemptive rights to purchase shares of Class A Common Stock. Shares of Class A Common Stock are not subject to any redemption or sinking fund provisions and are not convertible into any of the Company’s other securities. In the event of the Company’s voluntary or involuntary liquidation, dissolution or winding up, holders of Class A Common Stock will share equally in the assets remaining after it pays its creditors and preferred shareholders. Holders of Class A Common Stock are entitled to receive dividends when and if declared by the Board of Directors.

Shares of Class B Common Stock are non-economic interests in the Company, and no dividends can be declared or paid on the Class B Common Stock. The holders of Class B Common Stock have no preemptive rights to purchase shares of Class B Common Stock. Shares of Class B common stock are not subject to any redemption or sinking fund provisions. In the event of the Company’s voluntary or involuntary liquidation, dissolution or winding up, after payment or provision for payment of its debts and other liabilities, the holders of Class B Common Stock will be entitled to receive, out of its assets or proceeds thereof available for distribution to our shareholders, before any distribution of such assets or proceeds is made to or set aside for the holders of Class A Common Stock and any other of the Company’s stock ranking junior to the Class B Common Stock as to such distribution, payment in full in an amount equal to $0.01 per share of Class B Common Stock. With the exception of the aforementioned distribution, the holders of shares of Class B Common Stock will not be entitled to receive any of the Company’s assets in the event of its voluntary or involuntary liquidation, dissolution or winding up.

The Company’s Class B Common Stock is not convertible into any of the Company’s other securities. However, if a holder exchanges one common unit of the Partnership, for one share of the Company’s Class A Common Stock, it must also surrender to the Company a share of its Class B Common Stock for each common unit exchanged.

As of September 30, 2022, the Company had (i) 110,000,000 authorized shares of Class A Common Stock and 19,422,156 shares of Class A Common Stock issued and outstanding, (ii) 30,000,000 authorized shares of Class B Common Stock and 22,548,998 shares of Class B Common Stock issued and outstanding, and (iii) 5,000,000 authorized shares of preferred stock, par value $0.01 per share, and no shares of preferred stock were issued or outstanding.

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Dividends

On July 7, 2022, the Company’s Board of Directors declared a cash dividend of $0.075 per share of Class A Common Stock. The dividend was paid on August 4, 2022 to holders of record of Class A Common Stock as of the close of business on July 25, 2022. In connection with any dividend, Ranger’s operating subsidiary will also make a corresponding distribution to its common unitholders. During the third quarter of 2022, the dividend to the holders of our Class A Common Stock and distribution to common unitholders totaled $3.2 million in the aggregate. The Company’s Credit Facility and the Indenture have restrictive covenants that limit its ability to pay dividends. See Note 15 for details on dividends declared subsequent to September 30, 2022.

Share Repurchase Program

On April 13, 2022, our Board of Directors approved a share repurchase program that authorized the Company to repurchase up to $100 million of its outstanding Class A Common Stock. The share repurchase authorization was effective immediately and was valid through March 31, 2023. On July 7, 2022, the Board of Directors authorized an increase in the share repurchase program from $100 million to $140 million and extended the term of the program through June 30, 2023.

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 continue 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, 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. On August 16, 2022, the Inflation Reduction Act was signed into law and imposes a 1% excise tax on the repurchase of stock by publicly traded U.S. corporations. The excise tax is effective for stock repurchases after December 31, 2022. We are currently evaluating the impacts, if any, of this provision to our results of operations and cash flows.

During the three and nine months ended September 30, 2022, we repurchased 1,074,960 and 1,755,836 shares of our Class A Common Stock at a total cost of $35.0 million and $60.0 million at average purchase prices of $32.58 and $34.19, respectively. The share repurchases were recorded to Class A common stock and Paid-in capital on our condensed consolidated balance sheets. As of September 30, 2022, the remaining authorized repurchase amount under the share repurchase program was $80.0 million.

Change in Ownership of Consolidated Subsidiaries

As discussed above and in Note 13, in the three and nine months ended September 30, 2022, we repurchased shares of our Class A Common Stock and issued shares of our Class A Common Stock related to the vesting of employees’ share-based compensation resulting in a change in the proportionate share of Common Units held by the Company relative to Juniper. As such, we recognized an adjustment to the carrying amount of noncontrolling interest and a corresponding adjustment to Class A Common Shareholders’ equity of $7.1 million and $13.6 million for the three and nine months ended September 30, 2022 to reflect the revised ownership percentage of total equity, respectively.

The following table summarizes changes in the ownership interest in consolidated subsidiaries during the period:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Net income attributable to common shareholders	$	106,236	$	17,387	$	167,435	$	6,860
Transfers from the noncontrolling interest, net 1	7,121		N/A		13,619		N/A
Change from net income attributable to common shareholders and net transfers to Noncontrolling interest	$	113,357	$	17,387	$	181,054	$	6,860

_____________________________________________

1     The three and nine months ended September 30, 2022 includes a net transfer of $7.1 million and $13.6 million, respectively, from Noncontrolling interest for share repurchases and common stock issuances related to employees’ share-based compensation with a corresponding adjustment to Paid-in capital. This equity adjustment had no impact on earnings other than a resulting increase to the noncontrolling interest proportionate share of net income and a corresponding decrease to the proportionate share of net income attributable to common shareholders.

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Note 13 – Share-Based Compensation and Other Benefit Plans

Share-Based Compensation

We reserved 4,424,600 shares of Class A Common Stock for issuance under the Ranger Oil Management Incentive Plan (the “Plan”) for share-based compensation awards. A total of 811,573 time-vested restricted stock units (“RSUs”) and 664,414 performance-based restricted stock units (“PRSUs”) have been granted to employees and directors through September 30, 2022.

We recognized expense attributable to the RSUs and PRSUs of $1.3 million and $4.3 million for the three and nine months ended September 30, 2022, respectively. During the three months ended September 30, 2021, we recognized $1.0 million of expense attributable to the RSUs and PRSUs and during the nine months ended September 30, 2021, we recognized $4.2 million of expense attributable to the RSUs and PRSUs, including approximately $1.9 million as a result of a change-in-control event associated with the Juniper Transactions. 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 nine months ended September 30, 2022 with respect to awarded RSUs:

	Time-Vested Restricted Stock Units	Weighted-Average Grant Date Fair Value
Balance at January 1, 2022	230,517	$	9.20
Granted	49,314	$	35.07
Vested	(111,479)	$	10.02
Forfeited	(16,101)	$	12.12
Balance at September 30, 2022	152,251	$	17.50

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 September 30, 2022, we had $2.0 million of unrecognized compensation cost attributable to RSUs. We expect that cost to be recognized over a weighted-average period of 1.89 years.

Performance-Based Restricted Stock Units

The table below summarizes activity for the nine months ended September 30, 2022 with respect to awarded PRSUs:

	Performance Restricted Stock Units	Weighted-Average Grant Date Fair Value
Balance at January 1, 2022	345,069	$	16.20
Granted	180,217	$	47.77
Vested	(2,688)	$	18.24
Forfeited	(11,516)	$	23.31
Balance at September 30, 2022	511,082	$	27.16

Compensation expense for PRSUs with a market condition is being charged to expense on a straight-line basis for the 2022 and 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.

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The 2022 and 2021 PRSU grants contain performance measures of which 50% are based on the Company’s return on average capital employed (“ROCE”) and 50% are based on the Company’s absolute total shareholder return and total shareholder return (“TSR”) relative to a defined peer group over the three-year performance period. The 2022 and 2021 PRSUs cliff vest from 0% to 200% of the original grant at the end of a three-year performance period based on satisfaction of the respective underlying conditions.

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 and 2022 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 2022, 2021, 2020 and 2019 are presented as follows:

	2022		2021 1		2020 1		2019
Expected volatility	134.98% to 138.75%		131.74% to 134.74%		101.32% to 117.71%		49.9	%
Dividend yield	0.0	%	0.0	%	0.0	%	0.0	%
Risk-free interest rate	2.59	%	0.22% to 0.29%		0.18% to 0.51%		1.66	%
Performance period	2022-2024		2021-2023		2020-2022		2020-2022

_______________________

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

As of September 30, 2022, we had $9.2 million of unrecognized compensation cost attributable to PRSUs. We expect that cost to be recognized over a weighted-average period of 1.93 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 expense attributable to the 401(k) Plan of $0.1 million and $0.5 million for the three and nine months ended September 30, 2022, respectively, and $0.2 million and $0.5 million for the three and nine months ended September 30, 2021, respectively. 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 nine months ended September 30, 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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Note 14 – 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 and nine months ended September 30, 2022 and Series A Preferred Stock, par value $0.01 per share (“Series A Preferred Stock”) as applicable to the three and nine months ended September 30, 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 due to the elimination of the Noncontrolling interest assuming exchange of the Common Units (and shares of Class B Common Stock as applicable to the three and nine months ended September 30, 2022 and Series A Preferred Stock as applicable to the three and nine months ended September 30, 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 September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Numerator:
Net income	$	227,585	$	43,063	$	354,964	$	30,638
Net income attributable to Noncontrolling interest	(121,349)		(25,676)		(187,529)		(23,778)
Net income attributable to common shareholders for Basic EPS	106,236		17,387		167,435		6,860
Adjustment for assumed conversions and elimination of Noncontrolling interest net income	785		25,676		1,154		23,778
Net income attributable to common shareholders for Diluted EPS	$	107,021	$	43,063	$	168,589	$	30,638
Denominator:
Weighted average shares outstanding used in Basic EPS	19,741		15,319		20,573		15,298
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, 2	—		—		—		—
RSUs and PRSUs	600		394		582		371
Weighted average shares outstanding used in Diluted EPS 2	20,341		15,713		21,155		15,669

_______________________

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 and nine months ended September 30, 2022, approximately 22.5 million potentially dilutive Common Units (and the associated 22.5 million Class B Common Stock) had the effect of being anti-dilutive and were excluded from the calculation of earnings per share. For the three and nine months ended September 30, 2021, approximately 22.5 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).

Note 15 – Subsequent Events

Dividends

On November 2, 2022, the Company’s Board of Directors declared a cash dividend of $0.075 per share of Class A Common Stock, payable on November 28, 2022 to holders of record of Class A Common Stock as of the close of business on November 16, 2022.

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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. and other completed acquisitions, 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;

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

•general economic conditions, including as a result of governmental actions to address elevated inflation levels caused by labor shortages, supply shortages and increased demand, and other inflationary pressures;

•the impact of world health events, including the COVID-19 pandemic, economic slowdown, governmental actions, stay-at-home orders and interruptions to our operations or our customer’s operations;

•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 on favorable terms, 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 share repurchase program or declare dividends;

•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;

•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;

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•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 and our Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2022, June 30, 2022 and September 30, 2022.

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 September 30, 2022 or 2021, as applicable.

This section of the Form 10-Q discusses the results of operations for the three and nine months ended September 30, 2022 compared to the three and nine months ended September 30, 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 three and nine months ended September 30, 2022. Results for the three and nine months ended September 30, 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.

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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

Share Repurchase Program

On April 13, 2022, our Board of Directors approved a share repurchase program, under which the Company was authorized to repurchase up to $100 million of its outstanding Class A Common Stock through March 31, 2023. On July 7, 2022, the Board of Directors authorized an increase in the share repurchase program from $100 million to $140 million and extended the term of the program through June 30, 2023.

During the three and nine months ended September 30, 2022, we repurchased 1,074,960 and 1,755,836 shares of our Class A Common Stock at a total cost of $35.0 million and $60.0 million at average purchase prices of $32.58 and $34.19, respectively. Subsequent to September 30, 2022 through November 1, 2022, we repurchased an additional 331,917 shares of our Class A Common Stock at an average price of $37.72 for a total cost of $12.5 million.

See Note 12 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information.

Dividends

On July 7, 2022, the Company’s Board of Directors declared a cash dividend of $0.075 per share of Class A Common Stock. The dividend was paid on August 4, 2022 to holders of record of Class A Common Stock as of the close of business on July 25, 2022. Additionally, on November 2, 2022, the Company’s Board of Directors declared a cash dividend of $0.075 per share of Class A Common Stock payable on November 28, 2022 to holders of record of Class A Common Stock as of the close of business on November 16, 2022.

Recent Acquisitions

During the second and third quarters of 2022, we closed on several acquisitions of oil and gas producing properties in the Eagle Ford Shale, comprised of additional working interests in Ranger-operated wells and adjacent producing assets and undeveloped acreage for aggregate cash consideration totaling $129.8 million, subject to customary post-closing adjustments.

See Note 3 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information on our acquisitions.

Increased Borrowing Base of Credit Facility

On September 27, 2022, the aggregate elected commitment amounts under the Credit Facility increased from $400 million to $500 million and our borrowing base increased from $875 million to $950 million.

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

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. Beginning in early 2021, increased mobility, deployment of vaccines and other factors have resulted in increased oil demand and commodity prices.

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A high level of uncertainty remains regarding the volatility of energy supply and demand. The Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, collectively “OPEC+”) has recently changed its strategy from one which had seen gradually increasing production throughout 2021 and 2022 to one of drastically cutting oil production. In October 2022, OPEC+ announced its intent to decrease output targets by 2 Mbbls per day in November 2022, after increasing output targets by 100,000 bbls per day in September 2022 and following the raising of output by 648,000 bbls per day in July and August 2022. These shifts in OPEC+ production levels as well as the Russia-Ukraine war and related sanctions, which began in the first quarter of 2022, continue to contribute to a high level of uncertainty surrounding energy supply and demand resulting in volatile commodity prices. During the first half of 2022, WTI crude oil and natural gas prices surged, closing at over $120 per bbl and over $9 per Mcf, respectively, due to oil supply shortage concerns. During the third quarter of 2022, WTI crude oil and natural gas prices dropped to lows under $77 per bbl and $6 per Mcf, respectively. Higher commodity prices, along with the global supply chain issues and other factors, have increased inflation, which has led or may lead to increased costs of services and certain materials necessary for our operations. Recent governmental actions to combat inflation, including the Inflation Reduction Act passed into law in August 2022 as well as recent interest rate hikes by the Federal Reserve and increased recession fears continue to create pricing and economic volatility in the markets. The ultimate effect of these measures on inflation and overall energy supply and demand is uncertain at this time.

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 increased substantially and remain volatile as a result of the Russia-Ukraine war and other factors discussed above, with NYMEX Henry Hub (“NYMEX HH”) closing as low as $5.63 per Mcf and as high as $9.85 per Mcf during the third quarter of 2022. 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. We continue to work 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.

Capital Expenditures, Development Progress and Production

As of September 30, 2022, we operated two drilling rigs and during the nine months ended September 30, 2022, we incurred capital expenditures of approximately $362.6 million, of which $356.9 million was directed to drilling and completion projects. During the third quarter 2022, a total of 13 gross (12.4 net) wells were completed and turned to sales.

As of October 28, 2022, we had approximately 183,800 gross (160,600 net) acres in the Eagle Ford, net of expirations, of which approximately 95% is held by production.

Total sales volume for the third quarter 2022 was 3,921 thousand barrels of oil equivalent (“Mboe”), or 42,624 barrels of oil equivalent (“boe”) per day, with approximately 72%, or 2,822 thousand barrels of oil (“Mbbl”), of sales volume from crude oil, 15% from NGLs and 13% from natural gas.

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Commodity Hedging Program

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

	4Q2022		1Q2023		2Q2023		3Q2023		4Q2023		1Q2024		2Q2024
NYMEX WTI Crude Swaps
Average Volume Per Day (bbl)	4,630		2,500		2,400		2,807		2,657		462		462
Weighted Average Swap Price ($/bbl)	$	74.91	$	54.40	$	54.26	$	54.92	$	54.93	$	58.75	$	58.75
NYMEX WTI Crude Collars
Average Volume Per Day (bbl)	21,875		17,083		11,126		8,152		4,891
Weighted Average Purchased Put Price ($/bbl)	$	66.09	$	66.10	$	61.48	$	72.00	$	70.00
Weighted Average Sold Call Price ($/bbl)	$	89.05	$	82.08	$	74.31	$	89.91	$	86.04
NYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (bbl)	3,804
Weighted Average Swap Price ($/bbl)	$	1.751
NYMEX HH Swaps
Average Volume Per Day (MMBtu)	12,500		10,000		7,500
Weighted Average Swap Price ($/MMBtu)	$	3.793	$	3.620	$	3.690
NYMEX HH Collars
Average Volume Per Day (MMBtu)	14,511		14,617		11,538		11,413		11,413		11,538		11,538
Weighted Average Purchased Put Price ($/MMBtu)	$	2.854	$	6.561	$	2.500	$	2.500	$	2.500	$	2.500	$	2.328
Weighted Average Sold Call Price ($/MMBtu)	$	3.791	$	12.334	$	2.682	$	2.682	$	2.682	$	3.650	$	3.000
OPIS Mt. Belv Ethane Swaps
Average Volume per Day (gal)	27,717				98,901		34,239		34,239		34,615
Weighted Average Fixed Price ($/gal)	$	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									Nine Months Ended September 30,
	September 30, 2022			June 30, 2022			September 30, 2021			2022			2021
Total sales volume (Mboe) 1	3,921			3,502			2,344			10,821			6,453
Average daily sales volume (boe/d) 1	42,624			38,479			25,483			39,636			23,638
Crude oil sales volume (Mbbl) 1	2,822			2,502			1,879			7,752			5,179
Crude oil sold as a percent of total 1	72		%	71		%	80		%	72		%	80		%
Product revenues	$	304,105		$	313,444		$	140,133		$	873,148		$	352,230
Crude oil revenues	$	262,537		$	273,589		$	127,995		$	762,858		$	326,222
Crude oil revenues as a percent of total	86		%	87		%	91		%	87		%	93		%
Realized prices:
Crude oil ($/bbl)	$	93.03		$	109.34		$	68.10		$	98.40		$	62.99
NGLs ($/bbl)	$	31.97		$	36.77		$	27.24		$	33.96		$	21.21
Natural gas ($/Mcf)	$	7.41		$	7.19		$	4.11		$	6.35		$	3.23
Aggregate ($/boe)	$	77.55		$	89.51		$	59.77		$	80.69		$	54.58
Realized prices, including effects of derivatives, net 2
Crude oil ($/bbl)	$	83.14		$	84.43		$	57.15		$	80.69		$	52.08
NGLs ($/bbl)	$	30.67		$	35.10		$	25.77		$	32.95		$	20.52
Natural gas ($/Mcf)	$	4.26		$	4.08		$	3.44		$	4.10		$	3.01
Aggregate ($/boe)	$	67.76		$	68.87		$	50.49		$	66.02		$	45.63
Production and lifting costs:
Lease operating ($/boe)	$	6.15		$	5.40		$	4.54		$	5.65		$	4.52
Gathering, processing and transportation ($/boe)	$	2.50		$	2.47		$	2.43		$	2.54		$	2.41
Production and ad valorem taxes ($/boe)	$	4.26		$	4.79		$	3.21		$	4.31		$	3.06
General and administrative ($/boe) 3	$	2.51		$	3.04		$	4.66		$	2.79		$	4.82
Depreciation, depletion and amortization ($/boe)	$	16.88		$	15.50		$	13.21		$	15.84		$	12.96

_______________________

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 $0.48, $0.71 and $1.55 per boe for the three months ended September 30, 2022, June 30, 2022 and September 30, 2021, respectively, attributable to share-based compensation and certain special charges, comprised of acquisition, integration and strategic transaction costs including costs attributable to the Lonestar Acquisition during those periods as well as costs attributable to our acquisitions in the second and third quarters of 2022 as described in the discussion of “Results of Operations - General and Administrative” that follows.

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Sequential Quarterly Analysis

The following summarizes our key operating and financial highlights for the three months ended September 30, 2022, with comparison to the three months ended June 30, 2022. The year-over-year highlights for the quarterly periods ended September 30, 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 increased to 42,624 boe per day from 38,479 boe per day with 12.4 net wells turned to sales for the third quarter 2022 compared to 12.3 net wells turned to sales for the second quarter 2022. Total sales volume increased 12% to 3,921 Mboe from 3,502 Mboe primarily due to the recent acquisitions that closed in the third quarter of 2022.

•Product revenues decreased 3% to $304.1 million from $313.4 million as a result of 13% lower aggregate realized prices offset by 12% higher total sales volumes. Crude oil revenues were 4% lower due to 15% lower realized prices, or $46.0 million, offset by 13% higher crude oil sales volume, or $35.0 million. NGL revenues were 1% lower due to 13% lower realized prices, or $2.8 million, substantially offset by 14% higher total sales volume, or $2.7 million. Natural gas revenues were 9% higher as a result of 3% higher realized prices and 6% higher volume for an overall increase of $1.9 million.

•Production and lifting costs, consisting of Lease operating expenses (“LOE”) and Gathering, processing and transportation expenses (“GPT”), increased on an absolute basis to $33.9 million from $27.5 million primarily due to the effects of 12% higher sales volume and increased on a per unit basis to $8.65 per boe from $7.87 per boe primarily due to increased workover activity.

•Production and ad valorem taxes decreased on an absolute and per unit basis to $16.7 million and $4.26 per boe from $16.8 million and $4.79 per boe, respectively, due to the overall effects of 13% lower aggregate realized product pricing.

•General and administrative (“G&A”) expenses decreased on an absolute and per unit basis to $9.8 million and $2.51 per boe from $10.6 million and $3.04 per boe, respectively, primarily due to a $0.7 million decrease in compensation cost associated with employee share-based compensation granted during second quarter 2022.

•Depreciation, depletion and amortization (“DD&A”) increased on an absolute and per unit basis to $66.2 million and $16.88 per boe during the third quarter 2022 as compared to $54.3 million and $15.50 per boe during the second quarter 2022 due primarily to higher future development costs driven by inflation.

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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 September 30,					Nine Months Ended September 30,
Total Sales Volume 1	2022	2021	Change	% Change		2022	2021	Change	% Change
Crude oil (Mbbl)	2,822	1,879	943	50	%	7,752	5,179	2,573	50	%
NGLs (Mbbl)	584	263	321	122	%	1,597	713	884	124	%
Natural gas (MMcf)	3,092	1,211	1,881	155	%	8,829	3,367	5,462	162	%
Total (Mboe)	3,921	2,344	1,577	67	%	10,821	6,453	4,368	68	%
	Three Months Ended September 30,					Nine Months Ended September 30,
Average Daily Sales Volume 1	2022	2021	Change	% Change		2022	2021	Change	% Change
Crude oil (bbl/d)	30,675	20,429	10,246	50	%	28,397	18,972	9,425	50	%
NGLs (bbl/d)	6,347	2,860	3,487	122	%	5,849	2,611	3,238	124	%
Natural gas (MMcf/d)	34	13	21	162	%	32	12	20	167	%
Total (boe/d)	42,624	25,483	17,141	67	%	39,636	23,638	15,998	68	%

_______________________

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 67% and 68% during the three and nine month periods in 2022, respectively, when compared to the corresponding periods in 2021 as a result of the Lonestar Acquisition that closed in fourth quarter of 2021, recent acquisitions that closed in the second and third quarters of 2022 and increased drilling activity.

Approximately 72% of total sales volume during the three and nine month periods in 2022 was attributable to crude oil 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 September 30,								Nine Months Ended September 30,
Total Product Revenues	2022		2021		Change		% Change		2022		2021		Change		% Change
Crude oil	$	262,537	$	127,995	$	134,542	105	%	$	762,858	$	326,222	$	436,636	134	%
NGLs	18,669		7,165		11,504		161	%	54,227		15,115		39,112		259	%
Natural gas	22,899		4,973		17,926		360	%	56,063		10,893		45,170		415	%
Total	$	304,105	$	140,133	$	163,972	117	%	$	873,148	$	352,230	$	520,918	148	%
Realized Prices	Three Months Ended September 30,								Nine Months Ended September 30,
($ per unit of volume)	2022		2021		Change		% Change		2022		2021		Change		% Change
Crude oil	$	93.03	$	68.10	$	24.93	37	%	$	98.40	$	62.99	$	35.41	56	%
NGLs	$	31.97	$	27.24	$	4.73	17	%	$	33.96	$	21.21	$	12.75	60	%
Natural gas	$	7.41	$	4.11	$	3.30	80	%	$	6.35	$	3.23	$	3.12	97	%
Total	$	77.55	$	59.77	$	17.78	30	%	$	80.69	$	54.58	$	26.11	48	%

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

	Three Months Ended September 30, 2022 vs. 2021						Nine Months Ended September 30, 2022 vs. 2021
	Revenue Variance Due to						Revenue Variance Due to
	Volume		Price		Total		Volume		Price		Total
Crude oil	$	64,198	$	70,344	$	134,542	$	162,076	$	274,560	$	436,636
NGLs	8,740		2,764		11,504		18,747		20,365		39,112
Natural gas	7,719		10,207		17,926		17,667		27,503		45,170
	$	80,657	$	83,315	$	163,972	$	198,490	$	322,428	$	520,918

Our product revenues during the three and nine month periods in 2022 increased compared to the corresponding periods in 2021 due to significantly higher prices stemming from macroeconomic factors and volatility in the global commodity markets as a result of continued economic recovery, as well as supply concerns resulting from the Russia-Ukraine war. These factors resulted in an increase to the NYMEX WTI benchmark price of 30% and 51% for the three and nine month periods in 2022, respectively, as compared to the corresponding periods in 2021. Also contributing to the higher product revenues was an increase in volumes across all commodities as discussed above, with an overall increase in Mboe of 67% and 68% for three and nine month periods in 2022, respectively.

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 September 30,								Nine Months Ended September 30,
	2022		2021		Change		% Change		2022		2021		Change		% Change
Average WTI prices ($/bbl)	$	91.43	$	70.52	$	20.91	30	%	$	98.25	$	65.04	$	33.21	51	%
Realized differential to WTI	1.60		(2.42)		4.02		166	%	0.15		(2.05)		2.20		107	%
Realized crude oil prices ($/bbl)	$	93.03	$	68.10	$	24.93	37	%	$	98.40	$	62.99	$	35.41	56	%
Average HH prices ($/MMBtu)	$	7.96	$	4.27	$	3.69	86	%	$	6.66	$	3.52	$	3.14	89	%
Realized differential to HH	(0.55)		(0.16)		(0.39)		(244)	%	(0.31)		(0.29)		(0.02)		(7)	%
Realized natural gas prices ($/Mcf)	$	7.41	$	4.11	$	3.30	80	%	$	6.35	$	3.23	$	3.12	97	%

Our differential to NYMEX WTI for the three and nine month periods in 2022 improved by 166% and 107%, respectively, compared to the corresponding periods in 2021 due to more favorable NYMEX Calendar Month Average contractual pricing and more favorable pricing negotiated with certain crude purchasers effective early in first quarter 2022. Our differential to NYMEX HH was negatively impacted for the three and nine month periods in 2022 as compared to the corresponding period in 2021 due to more unfavorable 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, NGLs 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, NGLs 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, NGLs and natural gas, as adjusted for the effects of derivatives, net and reconciles to realized prices for crude oil, NGLs and natural gas determined in accordance with GAAP: 

	Three Months Ended September 30,								Nine Months Ended September 30,
	2022		2021		Change		% Change		2022		2021		Change		% Change
Realized crude oil prices ($/bbl)	$	93.03	$	68.10	$	24.93	37	%	$	98.40	$	62.99	$	35.41	56	%
Effects of derivatives, net ($/bbl)	(9.89)		(10.95)		1.06		10	%	(17.71)		(10.91)		(6.80)		(62)	%
Crude oil realized prices, including effects of derivatives, net ($/bbl)	$	83.14	$	57.15	$	25.99	45	%	$	80.69	$	52.08	$	28.61	55	%
Realized natural gas liquid prices ($/bbl)	$	31.97	$	27.24	$	4.73	17	%	$	33.96	$	21.21	$	12.75	60	%
Effects of derivatives, net ($/bbl)	(1.30)		(1.47)		0.17		12	%	(1.01)		(0.69)		(0.32)		(46)	%
Natural gas liquids realized prices, including effects of derivatives, net ($/bbl)	$	30.67	$	25.77	$	4.90	19	%	$	32.95	$	20.52	$	12.43	61	%
Realized natural gas prices ($/Mcf)	$	7.41	$	4.11	$	3.30	80	%	$	6.35	$	3.23	$	3.12	97	%
Effects of derivatives, net ($/Mcf)	(3.15)		(0.67)		(2.48)		NM		(2.25)		(0.22)		(2.03)		NM
Natural gas realized prices, including effects of derivatives, net ($/Mcf)	$	4.26	$	3.44	$	0.82	24	%	$	4.10	$	3.01	$	1.09	36	%

_______________________

NM - percentage change not meaningful

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 September 30,								Nine Months Ended September 30,
	2022		2021		Change		% Change		2022		2021		Change		% Change
Other operating income, net	$	985	$	928	$	57	6	%	$	2,888	$	2,085	$	803	39	%

Our marketing fee income increased in the three and nine month periods in 2022, as compared to the corresponding periods in 2021 due primarily to the higher commodity-based pricing. Additionally, the nine month period in 2022 included a 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 for gas lift, chemicals, water disposal, repairs and maintenance, including down-hole repairs, field labor, equipment rentals, utilities and supplies, among others.

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

	Three Months Ended September 30,								Nine Months Ended September 30,
	2022		2021		Change		% Change		2022		2021		Change		% Change
Lease operating	$	24,123	$	10,647	$	13,476	127	%	$	61,133	$	29,200	$	31,933	109	%
Per unit ($/boe)	$	6.15	$	4.54	$	1.61	35	%	$	5.65	$	4.52	$	1.13	25	%

LOE increased on an absolute basis and per unit basis during three and nine month periods in 2022 as compared to the corresponding periods in 2021 due primarily to the impact of the Lonestar Acquisition and recent acquisitions that closed in the second and third quarters of 2022, increased workovers and higher fuel, service and equipment costs driven by higher sales volume coupled with inflationary pressures throughout 2022.

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.

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

	Three Months Ended September 30,								Nine Months Ended September 30,
	2022		2021		Change		% Change		2022		2021		Change		% Change
GPT	$	9,794	$	5,688	$	4,106	72	%	$	27,472	$	15,535	$	11,937	77	%
Per unit ($/boe)	$	2.50	$	2.43	$	0.07	3	%	$	2.54	$	2.41	$	0.13	5	%

GPT expense increased on an absolute basis during the three and nine month periods in 2022 as compared to the corresponding periods in 2021 due primarily to the impact of the Lonestar Acquisition and recent acquisitions that closed in the second and third quarters of 2022, which contributed to the 155% and 162% higher natural gas sales volumes, respectively, and 50% higher crude oil sales volumes for both the three and nine month periods in 2022. 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 the three and nine month periods in 2022, as compared to the corresponding periods in 2021, we incurred higher gathering costs associated with these volumes which caused an increase during the three and nine month periods in 2022 as compared to the corresponding periods in 2021 on a per unit basis. 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, which reduces 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 September 30,											Nine Months Ended September 30,
	2022			2021			Change			% Change		2022			2021			Change			% Change
Production/severance taxes	$	14,121		$	6,589		$7,532			114	%	$	40,195		$	16,608		$	23,587		142	%
Ad valorem taxes	2,577			945			1,632			173	%	6,417			3,160			3,257			103	%
	$	16,698		$	7,534		$9,164			122	%	$	46,612		$	19,768		$	26,844		136	%
Per unit ($/boe)	$	4.26		$	3.21		$	1.05		33	%	$	4.31		$	3.06		$	1.25		41	%
Production/severance tax rate as a percent of product revenues	4.6		%	4.7		%	(0.1)		%	(2)	%	4.6		%	4.7		%	(0.1)		%	(2)	%

Production and ad valorem taxes increased on an absolute basis and per unit basis during the three and nine month periods in 2022 as compared to the corresponding periods in 2021 due primarily to the impact of higher volumes from the Lonestar Acquisition and recent acquisitions that closed in the second and third quarters of 2022. Additionally, Production taxes increased on an absolute and per unit basis due to higher aggregate commodity sales prices during the three and nine month periods in 2022.

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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 special charges that are generally attributable to stand-alone transactions or corporate actions that are not otherwise in the normal course.

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

	Three Months Ended September 30,								Nine Months Ended September 30,
	2022		2021		Change		% Change		2022		2021		Change		% Change
Primary G&A expenses	$	7,954	$	7,281	$	673	9	%	$	23,217	$	19,341	$	3,876	20	%
Share-based compensation	1,354		971		383		39	%	4,327		4,179		148		4	%
Significant special charges:
Organizational restructuring, including severance	—		—		—		—	%	—		239		(239)		(100)	%
Acquisition/integration and strategic transaction costs	521		2,680		(2,159)		(81)	%	2,699		7,335		(4,636)		(63)	%
Total G&A expenses	$	9,829	$	10,932	$	(1,103)	(10)	%	$	30,243	$	31,094	$	(851)	(3)	%
Per unit ($/boe)	$	2.51	$	4.66	$	(2.15)	(46)	%	$	2.79	$	4.82	$	(2.03)	(42)	%
Per unit ($/boe) excluding share-based compensation and other special charges identified above	$	2.03	$	3.11	$	(1.08)	(35)	%	$	2.15	$	3.00	$	(0.85)	(28)	%

Our total G&A expenses were lower on an absolute and per unit basis during the three month and nine month periods in 2022 when compared to the corresponding periods in 2021 due primarily to lower acquisition and integration related costs associated with the Juniper Transactions and the Lonestar Acquisition, partially offset by increased headcount discussed below and higher share-based compensation cost.

Our primary G&A expenses increased on an absolute basis during the three and nine month periods in 2022 as compared to the corresponding periods 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 in 2022.

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 13 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 September 30,								Nine Months Ended September 30,
	2022		2021		Change		% Change		2022		2021		Change		% Change
DD&A expense	$	66,204	$	30,975	$	35,229	114	%	$	171,387	$	83,654	$	87,733	105	%
DD&A rate ($/boe)	$	16.88	$	13.21	$	3.67	28	%	$	15.84	$	12.96	$	2.88	22	%

DD&A expense increased on an absolute and per unit basis during the three and nine month periods in 2022 as compared to the corresponding periods in 2021. Higher production volume provided for an increase of $20.8 million and $56.6 million and a higher DD&A rate resulted in an increase of $14.4 million and $31.2 million, for the three and nine month periods in 2022, respectively. The higher DD&A rate in 2022 is primarily due to the Lonestar Acquisition and recent acquisitions that closed in the second and third quarters of 2022, which contributed to an increase in our total proved reserves at a higher relative cost per boe as compared to the corresponding periods in 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.

We did not record an impairment of our oil and gas properties during the three and nine month periods in 2022. We recorded an impairment of $1.8 million in the nine months ended September 30, 2021 as a result of capitalized costs of oil and gas properties exceeding the ceiling test in the first quarter of 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 periods 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 periods 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 September 30,								Nine Months Ended September 30,
	2022		2021		Change		% Change		2022		2021		Change		% Change
Interest on borrowings and related fees	$	13,361	$	10,936	$	2,425	22	%	$	35,608	$	22,101	$	13,507	61	%
Accretion of original issue discount	168		84		84		100	%	493		274		219		80	%
Amortization of debt issuance costs	705		479		226		47	%	2,051		1,468		583		40	%
Capitalized interest	(1,074)		(917)		(157)		17	%	(3,257)		(2,561)		(696)		27	%
Total interest expense, net of capitalized interest	$	13,160	$	10,582	$	2,578	24	%	$	34,895	$	21,282	$	13,613	64	%

The increase in interest expense during the three month period in 2022 is primarily attributable to interest incurred in the amount of $9.2 million for the 9.25% Senior Notes due 2026 and $3.9 million for the Credit Facility compared to interest incurred in the corresponding period in 2021 of $5.3 million for the 9.25% Senior Notes due 2026, $3.4 million for the Second Lien Term Loan and $1.9 million for the Credit Facility as well as increased amortization of OID and debt issuance costs in 2022 compared to the corresponding period in 2021. These increases are partially offset by increased capitalized interest during the three month period in 2022, driven by higher overall weighted-average interest rates in 2022 as compared to the corresponding period in 2021.

The increase in interest expense during the nine month period in 2022 is primarily attributable to interest incurred in the amount of $27.3 million for the 9.25% Senior Notes due 2026 and $7.2 million for the Credit Facility compared to interest incurred in the corresponding period in 2021 of $10.4 million for the Second Lien Term Loan, $5.7 million for the Credit Facility and $5.3 million for the 9.25% Senior Notes due 2026 as well as increased amortization of OID and debt issuance costs in 2022 compared to the corresponding period in 2021. These increases are partially offset by increased capitalized interest during the nine month period in 2022, driven by higher overall weighted-average interest rates in 2022 as compared to the corresponding periods 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 September 30,								Nine Months Ended September 30,
	2022		2021		Change		% Change		2022		2021		Change		% Change
Commodity derivative gains (losses)	$	63,756	$	(21,000)	$	84,756	(404)	%	$	(149,137)	$	(119,631)	$	(29,506)	25	%
Interest rate swap gains (losses)	—		(84)		84		(100)	%	64		(48)		112		(233)	%
Total	$	63,756	$	(21,084)	$	84,840	(402)	%	$	(149,073)	$	(119,679)	$	(29,394)	25	%

In the three and nine month periods in 2022, commodity prices were significantly higher on an average aggregate basis than those during the corresponding periods in 2021. The derivative gains in the three month period in 2022 reflect the increase in the mark-to-market values consistent with the decrease in prices attributable to open positions for this period. The derivative losses in the nine month period in 2022 and the three and nine month periods in 2021 reflect the decline in the mark-to-market values consistent with the increase in prices attributable to open positions for the respective periods. Realized settlement payments, net for crude oil, NGL and natural gas derivatives were $55.3 million and $157.8 million for the three and nine month periods in 2022, respectively, and $21.3 million and $43.2 million during the three and nine month periods in 2021, respectively. Through May 2022, we hedged a portion of our exposure to variable interest rates associated with our Credit Facility and, in the three and nine month periods in 2021, our Second Lien Term Loan. As of September 30, 2022, we did not have any interest rate derivatives. We paid $1.4 million of net settlements from our interest rate swaps for the nine month period in 2022 and $1.0 million and $2.9 million for the three and nine month periods in 2021, respectively.

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 September 30,											Nine Months Ended September 30,
	2022			2021			Change			% Change		2022			2021			Change			% Change
Income tax expense	$	(2,052)		$	(549)		$	(1,503)		274	%	$	(3,171)		$	(410)		$	(2,761)		673	%
Effective tax rate	0.9		%	1.3		%	(0.4)		%	(31)	%	0.9		%	1.3		%	(0.4)		%	(31)	%

The income tax provision resulted in an expense of $2.1 million and an expense of $3.2 million for the three and nine month periods in 2022, respectively. 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 $5.0 million as of September 30, 2022 is also fully attributable to the State of Texas and primarily related to property.

The income tax provision resulted in an expense of $0.5 million and an expense of $0.4 million for the three and nine month periods in 2021, respectively. 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 1.3% 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 September 30, 2022, we had liquidity of $304.6 million, comprised of cash and cash equivalents of $20.3 million and availability under our Credit Facility of $284.3 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 $950.0 million with aggregate elected commitments of $500.0 million.

Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for crude oil, NGLs and natural gas, 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 volatility and uncertainty in the global economic markets stemming from the COVID-19 pandemic and subsequent recovery, the Russia-Ukraine war, OPEC+ production decisions and related instability in the global energy markets, as well as inflationary pressures and recession fears that impact demand. 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

We expect full year 2022 drilling and completions capital expenditures of between $507 and $527 million. We plan to continue 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 continued volatility 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.”

Dividends

On July 7, 2022, the Company’s Board of Directors declared an inaugural cash dividend of $0.075 per share of Class A Common Stock. The dividend was paid on August 4, 2022 to holders of record of Class A Common Stock as of the close of business on July 25, 2022. In connection with any dividend, Ranger’s operating subsidiary will also make a corresponding distribution to its common unitholders. During the third quarter of 2022, the dividend to the holders of our Class A Common Stock and distribution to common unitholders totaled $3.2 million in the aggregate. On November 2, 2022, the Company’s Board of Directors declared a cash dividend of $0.075 per share of Class A Common Stock payable on November 28, 2022 to holders of record of Class A Common Stock as of the close of business on November 16, 2022. We expect to fund dividends and distributions from available working capital and cash provided by operating activities.

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Share Repurchase Program

In April 2022, we announced that the Board of Directors approved a share repurchase program under which we were authorized to repurchase up to $100 million of outstanding Class A Common Stock through March 31, 2023. Subsequently on July 7, 2022, the Board of Directors authorized an increase in the share repurchase program from $100 million to $140 million and extended the term of the program through June 30, 2023. 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, and applicable legal requirements. We expect to fund repurchases from available working capital and cash provided by operating activities. On August 16, 2022, the Inflation Reduction Act was signed into law and imposes a 1% excise tax on the repurchase of stock by publicly traded U.S. corporations. The excise tax is effective for stock repurchases after December 31, 2022. We are currently evaluating the impacts, if any, of this provision to our results of operations and cash flows.

Subsequent to September 30, 2022 through November 1, 2022, we repurchased an additional 331,917 shares of our Class A Common Stock at an average price of $37.72 for a total cost of $12.5 million.

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. At this time, we do not anticipate that the Partnership will be required to make Tax Advances for the year ending December 31, 2022.

Cash Flows

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

	Nine Months Ended September 30,
	2022		2021
Net cash provided by operating activities	$	489,182	$	204,707
Net cash used in investing activities	(426,650)		(146,481)
Net cash (used in) provided by financing activities	(65,869)		375,523
Net increase (decrease) in cash, cash equivalents and restricted cash	$	(3,337)	$	433,749

Cash Flows from Operating Activities. The increase of $284.5 million in net cash provided by operating activities for the nine months ended September 30, 2022 compared to the corresponding period in 2021 was primarily attributable to the effect of 2022 cash receipts that were derived from higher average commodity prices and higher total sales volume, partially offset by higher net payments for commodity derivatives settlements and premiums. Additionally, during the nine months ended September 30, 2021, there were higher acquisition, integration and strategic transaction costs and executive restructuring costs, including severance payments.

Cash Flows from Investing Activities. Our cash payments for capital expenditures were higher during the nine months ended September 30, 2022 as compared to the corresponding period in 2021, due primarily to significantly increased drilling and completions activities in 2022, coupled with the current economic impacts of inflation and higher costs, and oil and gas property acquisitions closed and paid for in 2022. Early 2021 was impacted by the temporary suspension of the drilling program that began in 2020 due to the global economic downturn associated with COVID-19.

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

	Nine Months Ended September 30,
	2022		2021
Drilling and completion	$	356,883	$	181,144
Lease acquisitions, land-related costs, and geological and geophysical (seismic) costs	4,806		2,315
Pipeline, gathering facilities and other equipment, net 1	890		(632)
Total capital expenditures incurred	$	362,579	$	182,827

_______________________

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:

	Nine Months Ended September 30,
	2022		2021
Total capital expenditures program costs (from above)	$	362,579	$	182,827
Increase in accounts payable for capital items and accrued capitalized costs	(55,008)		(30,303)
Net purchases of tubular inventory and well materials 1	1,712		1,858
Prepayments for drilling and completion services, net of (transfers)	(8,762)		(12,653)
Capitalized internal labor, capitalized interest and other	7,245		4,909
Total cash paid for capital expenditures	$	307,766	$	146,638

_______________________

1    Includes purchases made in advance of drilling.

Cash Flows from Financing Activities. During the nine months ended September 30, 2022, we had borrowings of $483.0 million and repayments of $476.0 million under the Credit Facility and $59.4 million of share repurchases. During the nine months ended September 30, 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 nine months ended September 30, 2021 includes additional net repayments of $21.0 million under the Credit Facility and $5.6 million quarterly amortization payments under the Second Lien Term Loan as well as $396.1 million net proceeds received from the 9.25% Senior Notes due 2026.

Capitalization

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

	September 30, 2022			December 31, 2021
Credit Facility	$	215,000		$	208,000
9.25% Senior Notes due 2026, net	388,214			386,427
Mortgage debt 1	—			8,438
Other 2	284			2,516
Total debt, net	603,498			605,381
Total equity	964,532			669,508
Total capitalization	$	1,568,030		$	1,274,889
Debt as a % of total capitalization	38		%	47		%

_______________________

1     The mortgage debt at December 31, 2021 related to the corporate office building and related other assets acquired in connection with the Lonestar Acquisition for which assets were held as collateral for such debt. As of December 31, 2021, these assets were classified as Assets held for sale on the condensed consolidated balance sheets. In July 2022, the mortgage debt was fully repaid in connection with the sale of the corporate office building. See Note 3 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information on the sale.

2     Other debt of $2.2 million was extinguished during the nine months ended September 30, 2022 and recorded as a gain on extinguishment of debt.

Credit Facility. As of September 30, 2022, the Credit Facility had a $1.0 billion revolving commitment and an $950 million borrowing base, with aggregate elected commitments of $500 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. 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 September 30, 2022 and December 31, 2021, respectively. The maturity date under the Credit Facility is October 6, 2025.

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In September 2022, we entered into the Agreement and Amendment No. 13 to Credit Agreement (the “Thirteenth Amendment”). The Thirteenth Amendment, in addition to other changes described therein, amended the Credit Facility to (1) increase the borrowing base from $875 million to $950 million and (2) increase the aggregate elected commitment amounts under the Credit Facility from $400 million to $500 million.

The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 1.50% to 2.50%, determined based on the utilization level under the Credit Facility or (b) effective June 1, 2022, a term SOFR reference rate (a Eurodollar rate, including LIBOR prior to June 1, 2022), 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 SOFR, 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 September 30, 2022, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 5.63%. Unused commitment fees are charged at a rate of 0.50%.

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 September 30, 2022	$	215,000	$	262,065	$	301,000	5.83	%
Nine months ended September 30, 2022	$	215,000	$	205,315	$	301,000	4.54	%

The Credit Facility is guaranteed by all of the subsidiaries of the borrower (the “Guarantor Subsidiaries”), except for Boland Building, LLC. 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 completed an offering of $400 million aggregate principal amount of senior unsecured notes due 2026 (the “9.25% Senior Notes due 2026”) that bear interest at 9.25% and were sold at 99.018% of par. Obligations under the 9.25% Senior Notes due 2026 were assumed by ROCC Holdings, LLC (formerly, Penn Virginia Holdings, LLC, hereinafter referred to as “Holdings”), as borrower, and are guaranteed by the subsidiaries of Holdings that guarantee the Credit Facility.

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 September 30, 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 2022.

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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 September 30, 2022, we had variable-rate borrowings of $215.0 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 5.63% 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 $2.2 million on an annual basis.

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 September 30, 2022, our commodity derivative portfolio was in a net liability position in the amount of $51.2 million. The contracts associated with this position are with seven 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 nine months ended September 30, 2022, we reported a net commodity derivative loss of $149.1 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 crude oil prices. This illustration assumes that crude oil production volumes, NGL prices and production volumes, 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	$	(37.4)	$	37.8
Effect of crude oil price changes for the remainder of 2022 on operating income, excluding derivatives 2	$	13.4	$	(9.7)

_______________________

1 Based on derivatives outstanding as of September 30, 2022.

2    These sensitivities are subject to significant change.

44

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 September 30, 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 September 30, 2022, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

During the quarter ended September 30, 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.

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 and Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2022 and June 30, 2022.

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

The following table summarizes our repurchase of equity securities during the three months ended September 30, 2022:

Period	Total Number of Shares Repurchased	Average Price Paid Per Unit		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares Yet to be Purchased Under the Publicly Announced Plans or Programs 1
July 1, 2022 - July 31, 2022	672,985	$	30.57	672,985	$	94,416,322
August 1, 2022 - August 31, 2022	202,800	$	37.14	202,800	$	86,883,893
September 1, 2022 - September 30, 2022	199,175	$	34.74	199,175	$	79,964,948
Total	1,074,960	$	32.58	1,074,960	$	79,964,948

_______________________

1    On April 13, 2022, our Board of Directors approved a share repurchase program, under which the Company was authorized to repurchase up to $100 million of its outstanding Class A Common Stock through March 31, 2023. On July 7, 2022, the Board of Directors authorized an increase in the share repurchase program from $100 million to $140 million and extended the term of the program through June 30, 2023. 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, applicable legal requirements and other factors deemed relevant and may be discontinued at any time.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5.    Other Information

None.

45

Item 6.    Exhibits

(10.1) *	Fifth Amendment to Second Amended and Restated Construction and Field Gathering Agreement dated as of July 26, 2022 but made effective as of July 1, 2022, by and between Ironwood Shiner Pipeline, LLC, as successor to Nuevo Dos Gathering and Transportation, LLC, as successor to Republic Midstream, LLC and Penn Virginia Oil & Gas L.P.
(10.2)	Master Assignment, Agreement and Amendment No. 13 to Credit Agreement, dated as of September 27, 2022, among ROCC Holdings, LLC, as borrower, Ranger Oil Corporation, as holdings, the subsidiaries of holdings party thereto, certain lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent for the lenders and as an issuing lender (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on September 28, 2022).
(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 September 30, 2022, formatted in Inline XBRL (included within the Exhibit 101 attachments).

_____________________________

*    Filed herewith.

**    Furnished herewith.

46

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
November 3, 2022	By:	/s/ RUSSELL T KELLEY, JR.
		Russell T Kelley, Jr.
		Senior Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)
November 3, 2022	By:	/s/ KAYLA D. BAIRD
		Kayla D. Baird
		Vice President, Chief Accounting Officer and Controller
		(Principal Accounting Officer)

47

EX-10.1

Exhibit 10.1

Execution Version

FIFTH AMENDMENT TO SECOND AMENDED AND RESTATED
CONSTRUCTION AND FIELD GATHERING AGREEMENT

This Fifth Amendment (this "Amendment")to the Second Amended and Restated Construction and Field Gathering Agreement is dated as of July 26, 2022 (the "Execution Date") but made effective as of July 1, 2022,by and between Ironwood Shiner Pipeline, LLC, as successor to Nuevo Dos Gathering and Transportation, LLC, as successor to Republic Midstream, LLC ("Gatherer")and Penn Virginia Oil & Gas, L.P. ("Shipper").Gatherer and Shipper may hereinafter be referred to singularly as a "Party" and, together, as the "Parties".

RECITALS

WHEREAS, Republic Midstream, LLC and Penn Virginia Oil & Gas, L.P. entered into that certain Second Amended and Restated Construction and Field Gathering Agreement effective as of August 1, 2016 (the "Original Gathering Agreement");

WHEREAS, the Original Gathering Agreement was amended (as so amended, the “GatheringAgreement”) by that certain First Amendment to Second Amended and Restated Construction and Field Gathering Agreement, dated as of April 13, 2017, Second Amendment to Second Amended and Restated Construction and Field Gathering Agreement, dated as of July 2, 2018, Third Amendment to Second Amended and Restated Construction and Field Gathering Agreement, dated as of December 14, 2018, and Fourth Amendment to Second Amended and Restated Construction and Field Gathering Agreement, dated as of May 21, 2020; and

WHEREAS, the Parties desire to further amend the Gathering Agreement as provided in this Amendment;

NOW, THEREFORE, in consideration of the mutual covenants, terms and conditions herein contained, together with other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and intending to be legally bound hereby, the Parties, for themselves and for their successors and assigns, do hereby mutually covenant and agree as follows:

1.Amendment of Definitions in the Gathering Agreement. Article I of the Gathering Agreement is hereby amended by:

(a) adding the following definitions in appropriate alphabetical order

"Hawn Holt Pad Connection Pipe” means an Additional Segment consisting of an approximately 2,038 feet low gravity (below 45 API) pipeline that will permit Crude Oil produced from the Hawn Holt Pad Wells and Tremolite Pad Wells to be delivered to Gatherer under the Agreement.

"Hawn Holt Pad Well Fee” has the meaning given such term in Section 9.2(e).

"Hawn Holt Pad Wells” means the Hawn Holt 12H, 13H, 22H & 28H wells.

"Tremolite Pad Wells” means the Tremolite A1H & Tremolite B2H wells.

(b)deleting the word “and” before clause (c) of the definition of “Dedication Area” and adding the following before the period at the end of such definition:

“, and (d) the Hawn Holt Pad Wells and the Tremolite Pad Wells.”

2.Waiver of Construction Notice and Installation of Hawn Holt Pad Facilities. Gatherer hereby waives the obligation set forth in Section 3.3(a) of the Gathering Agreement for Shipper to deliver a Construction Notice for the Hawn Holt Pad Connection Pipe, and hereby agrees and elects, at its sole cost and expense, to construct, install, own and operate an Additional Segment consisting of the Hawn Holt Pad Connection Pipe, and a LACT/ACT Unit at the interconnection of the Hawn Holt Pad Connection Pipe and the Hawn Holt Pad Wells (such interconnection point is referred to in this Amendment as the “Hawn Holt Pad Interconnection Point”). Shipper shall, at its sole cost and expense, construct, install, own and operate all facilities upstream of the Hawn Holt Pad Interconnection Point that are reasonably necessary to deliver Crude Oil from the Hawn Holt Pad Wells and the Tremolite Pad Wells to the Hawn Holt Pad Interconnection Point.

3.Receipt Point. The Hawn Holt Pad Interconnection Point shall be a Receipt Point under the Gathering Agreement.

747972963.5

4.Fees.

(c)Sections 9.2(a) and 9.2(b) of the Gathering Agreement are hereby amended by deleting the parenthetical in such sections and replacing it in its entirety with “(other than from the Excluded Units, Outside Units, Other Wells, Future Wells, Hawn Holt Pad Wells and Tremolite Pad Wells)”;

(d)Section 9.2(e) of the Gathering Agreement is hereby deleted and replaced in its entirety with the following:

“(e)    A gathering fee on all of Shipper's Oil delivered at the Delivery Points via the Gathering System from all Future Wells equal to $1.00 per Barrel during such Month (the "Future Well Fee"), and from all Hawn Holt Pad Wells and Tremolite Pad Wells equal to $1.00 per Barrel during such Month (the "Hawn Holt and Tremolite Pad Well Fee");” and

(e)Sections 9.2(f), 9.2(g) and 9.2(h) of the Gathering Agreement are hereby amended by deleting the parenthetical in such sections and replacing it in its entirety with “(which shall in no event include Shipper's Oil from the Other Wells, Future Wells, Hawn Holt Pad Wells and Tremolite Pad Wells except as otherwise agreed by Shipper)”.

5.Fee Adjustment. Section 9.4 of the Gathering Agreement is hereby amended by adding the following parenthetical after the phrase “aggregate Monthly Fees” each time it appears in such Section:

“(other than the portion of such aggregate Monthly Fees that consist of Hawn Holt and Tremolite Pad Well Fees)”

For the avoidance of doubt, Shipper's Oil delivered at the Delivery Points via the Gathering System from the Hawn Holt Pad Wells and the Tremolite Pad Wells will be (i) charged the Transportation Fee (as defined in the TSA) under the TSA, (ii) charged the Marketing Fee (as defined in the Marketing Agreement) under the Marketing Agreement, and (iii) credited towards the first 20,000 bpd minimum volume commitment specified in the Gathering Agreement, TSA and Marketing Agreement during the respective terms of the applicable agreement.

6.Ratification; Primacy. Except as expressly amended by this Amendment, all of the terms, provisions, covenants and conditions contained in the Gathering Agreement remain in full force and effect; provided, if there is ever any conflict between the Gathering Agreement and this Amendment, the terms, provisions, covenants and conditions contained in this Amendment shall govern. The terms and provisions of the Gathering Agreement as amended by this Amendment are binding upon and inure to the benefit of the Parties, their representatives, successors and assigns. As amended by this Amendment, the Gathering Agreement is ratified and confirmed by the Parties, and declared to be a valid and enforceable contract between them.

7.Counterparts. This Amendment may be executed in as many counterparts as deemed necessary. When so executed, the aggregate counterparts shall constitute one agreement and shall have the same effect as if all Parties signing counterparts had executed the same instrument.

8.Amendment; Waiver. Neither this Amendment nor the Gathering Agreement may be amended or modified except pursuant to a written instrument signed by all of the Parties. Each Party may waive on its own behalf compliance by any other Party with any term or provision hereof; provided, however, that any such waiver shall be in writing and shall not bind the non-waiving Party. The waiver by any Party of a breach of any term or provision shall not be construed as a waiver of any subsequent breach of the same or any other provision.

9.Joint Preparation. The Parties agree and confirm that this Amendment was prepared jointly by all Parties and not by any one Party to the exclusion of the other.

10.No Third Party Beneficiaries. This Amendment is not intended to confer upon any person not a party hereto any rights or remedies hereunder, and no person other than the Parties is entitled to rely on or enforce any provision hereof.

11.Miscellaneous Provisions. The provisions of Articles XVII, XIX, XX and XXI of the Gathering Agreement are incorporated herein by this reference as if set out fully herein and shall apply in all respects to this Amendment.

[Signature Page Follows]

2

IN WITNESS WHEREOF, this Amendment has been executed by the Parties effective as of the Execution Date.

IRONWOOD SHINER PIPELINE, LLC

By: Ironwood Midstream Energy Partners II, LLC,

Its sole member

By: /s/ Justin Johnson______________

Name:    Justin Johnson

Title:    CCO & CFO

PENN VIRGINIA OIL & GAS, LP

By: /s/ Jill T. Zivley________________

Name:    Jill T. Zivley

Title:    VP, Land and Marketing

Signature Page to

Fifth Amendment to the Second Amended and Restated Construction and Field Gathering Agreement

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: November 3, 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: November 3, 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 September 30, 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: November 3, 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 September 30, 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: November 3, 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	9 Months Ended
	Sep. 30, 2022	Oct. 28, 2022
Document Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 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	Q3
Entity Central Index Key	0000077159
Current Fiscal Year End Date	--12-31
Common Class A
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		19,120,839
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		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Revenues
Total revenues and other	$ 305,090	$ 141,061	$ 876,036	$ 354,315
Operating expenses
Lease operating	24,123	10,647	61,133	29,200
Gathering, processing and transportation	9,794	5,688	27,472	15,535
Production and ad valorem taxes	16,698	7,534	46,612	19,768
General and administrative	9,829	10,932	30,243	31,094
Depreciation, depletion and amortization	66,204	30,975	171,387	83,654
Impairments of oil and gas properties	0	0	0	1,811
Total operating expenses	126,648	65,776	336,847	181,062
Operating income	178,442	75,285	539,189	173,253
Other income (expense)
Interest expense, net of amounts capitalized	(13,160)	(10,582)	(34,895)	(21,282)
Gain (loss) on extinguishment of debt	0	0	2,157	(1,231)
Derivative gains (losses)	63,756	(21,084)	(149,073)	(119,679)
Other, net	599	(7)	757	(13)
Income before income taxes	229,637	43,612	358,135	31,048
Income tax expense	(2,052)	(549)	(3,171)	(410)
Net income	227,585	43,063	354,964	30,638
Net income attributable to Noncontrolling interest	(121,349)	(25,676)	(187,529)	(23,778)
Net income attributable to common shareholders	$ 106,236	$ 17,387	$ 167,435	$ 6,860
Net income per share attributable to common shareholders:
Basic (in dollars per share)	$ 5.38	$ 1.13	$ 8.14	$ 0.45
Diluted (in dollars per share)	$ 5.26	$ 1.11	$ 7.97	$ 0.44
Weighted average shares outstanding – basic (in shares)	19,741	15,319	20,573	15,298
Weighted average shares outstanding – diluted (in shares)	20,341	15,713	21,155	15,669
Crude oil
Revenues
Revenues	$ 262,537	$ 127,995	$ 762,858	$ 326,222
Natural gas liquids
Revenues
Revenues	18,669	7,165	54,227	15,115
Natural gas
Revenues
Revenues	22,899	4,973	56,063	10,893
Other operating income, net
Revenues
Revenues	$ 985	$ 928	$ 2,888	$ 2,085

XML

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME – UNAUDITED - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Statement of Comprehensive Income [Abstract]
Net income	$ 227,585	$ 43,063	$ 354,964	$ 30,638
Other comprehensive income:
Change in pension and postretirement obligations, net of tax	0	1	0	4
Comprehensive income	227,585	43,064	354,964	30,642
Net income attributable to Noncontrolling interest	(121,349)	(25,676)	(187,529)	(23,778)
Other comprehensive income attributable to Noncontrolling interest	0	(1)	0	(4)
Comprehensive income attributable to common shareholders	$ 106,236	$ 17,387	$ 167,435	$ 6,860

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CONDENSED CONSOLIDATED BALANCE SHEETS – UNAUDITED - USD ($) $ in Thousands	Sep. 30, 2022	Dec. 31, 2021
Current assets
Cash and cash equivalents	$ 20,344	$ 23,681
Accounts receivable, net of allowance for credit losses	147,823	118,594
Derivative assets	30,725	11,478
Prepaid and other current assets	13,049	20,998
Assets held for sale	1,186	11,400
Total current assets	213,127	186,151
Property and equipment, net	1,711,367	1,383,348
Derivative assets	6,176	2,092
Other assets	4,686	5,017
Total assets	1,935,356	1,576,608
Current liabilities
Accounts payable and accrued liabilities	264,364	214,381
Derivative liabilities	75,327	50,372
Current portion of long-term debt	41	4,129
Total current liabilities	339,732	268,882
Deferred income taxes	4,957	2,793
Derivative liabilities	12,748	23,815
Other non-current liabilities	9,930	10,358
Long-term debt, net	603,457	601,252
Commitments and contingencies (Note 11)
Equity
Preferred stock of $0.01 par value – 5,000,000 shares authorized; none issued as of September 30, 2022 and December 31, 2021	0	0
Paid-in capital	230,777	273,329
Retained earnings	215,475	49,583
Accumulated other comprehensive loss	(111)	(111)
Ranger Oil shareholders’ equity	446,337	323,532
Noncontrolling interest	518,195	345,976
Total equity	964,532	669,508
Total liabilities and equity	1,935,356	1,576,608
Common Class A
Equity
Common stock	194	729
Common Class B
Equity
Common stock	$ 2	$ 2

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CONDENSED CONSOLIDATED BALANCE SHEETS – UNAUDITED (Parenthetical) - $ / shares	Sep. 30, 2022	Dec. 31, 2021	Oct. 31, 2021	Oct. 06, 2021	Oct. 05, 2021
Preferred stock, par value (in dollars per share)	$ 0.01
Preferred stock, shares authorized (in shares)	5,000,000
Preferred stock, issued (in shares)	0
Common stock, par value (in dollars per share)					$ 0.01
Common stock, authorized (in shares)					110,000,000
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, issued (in shares)	0	0
Common Class A
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01
Common stock, authorized (in shares)	110,000,000	110,000,000
Common stock, issued (in shares)	19,422,156	21,090,259
Common stock, outstanding (in shares)	19,422,156	21,090,259
Common Class B
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01
Common stock, authorized (in shares)	30,000,000	30,000,000		30,000,000
Common stock, issued (in shares)	22,548,998	22,548,998
Common stock, outstanding (in shares)	22,548,998	22,548,998

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – UNAUDITED - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021
Cash flows from operating activities
Net income	$ 354,964	$ 30,638
Adjustments to reconcile net income to net cash provided by operating activities:
(Gain) loss on extinguishment of debt	(2,157)	1,231
Depreciation, depletion and amortization	171,387	83,654
Impairments of oil and gas properties	0	1,811
Derivative contracts:
Net losses	149,073	119,679
Cash settlements and premiums paid, net	159,224	46,041
Deferred income tax expense	2,164	130
Non-cash interest expense	2,441	1,742
Share-based compensation	4,327	4,179
Other, net	(180)	13
Changes in operating assets and liabilities, net	(33,613)	7,671
Net cash provided by operating activities	489,182	204,707
Cash flows from investing activities
Capital expenditures	(307,766)	(146,638)
Acquisitions of oil and gas properties	(129,784)	0
Proceeds from sales of assets, net	10,900	157
Net cash used in investing activities	(426,650)	(146,481)
Cash flows from financing activities
Proceeds from credit facility borrowings	483,000	20,000
Repayments of credit facility borrowings	(476,000)	(121,500)
Repayments of second lien term loan	0	(56,890)
Proceeds from 9.25% Senior Notes due 2026, net of discount	0	396,072
Repayments of acquired debt	(8,513)	0
Payments for share repurchases	(59,414)	0
Distributions to Noncontrolling interest	(1,691)	0
Dividends paid	(1,492)	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	(954)	(623)
Debt issuance costs paid	(805)	(3,397)
Net cash (used in) provided by financing activities	(65,869)	375,523
Net increase (decrease) in cash, cash equivalents and restricted cash	(3,337)	433,749
Cash, cash equivalents and restricted cash – beginning of period	23,681	13,020
Cash, cash equivalents and restricted cash – end of period	20,344	446,769
Cash paid for:
Interest, net of amounts capitalized	42,678	14,298
Income taxes refunds, net	0	360
Non-cash investing and financing activities:
Changes in property and equipment related to capital contributions	0	(38,561)
Changes in accrued liabilities related to capital expenditures	$ 55,008	$ 30,303

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CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - UNAUDITED - USD ($) $ in Thousands	Total	Common Class A	Common Class B	Common Stock	Common Stock Common Class A	Common Stock Common Class B	Preferred Stock	Paid-in Capital	Retained Earnings/(Accumulated Deficit)	Accumulated Other Comprehensive Loss	Noncontrolling interest
Balance at beginning of period (in shares) at Dec. 31, 2020				15,200,000
Balance at beginning of period (in shares) at Dec. 31, 2020							0
Balance at beginning of period at Dec. 31, 2020	$ 212,838			$ 152			$ 0	$ 203,463	$ 9,354	$ (131)	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	(20,021)								(13,572)		(6,449)
Issuance of preferred stock (in shares)							225,490,000
Issuance of preferred stock	2						$ 2
Issuance of Noncontrolling interest	179,552							(50,068)			229,620
Common stock issued related to share-based compensation and other, net (in shares)				110,000
Common stock issued related to share-based compensation and other, net	1,772			$ 1				1,769		1	1
Balance at end of period (in shares) at Mar. 31, 2021							225,490,000
Balance at end of period (in shares) at Mar. 31, 2021				15,310,000
Balance at end of period at Mar. 31, 2021	374,143			$ 153			$ 2	155,164	(4,218)	(130)	223,172
Balance at beginning of period (in shares) at Dec. 31, 2020				15,200,000
Balance at beginning of period (in shares) at Dec. 31, 2020							0
Balance at beginning of period at Dec. 31, 2020	212,838			$ 152			$ 0	203,463	9,354	(131)	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	30,638
Balance at end of period (in shares) at Sep. 30, 2021							225,490,000
Balance at end of period (in shares) at Sep. 30, 2021				15,331,000
Balance at end of period at Sep. 30, 2021	426,590			$ 153			$ 2	156,950	16,214	(130)	253,401
Balance at beginning of period (in shares) at Mar. 31, 2021				15,310,000
Balance at beginning of period (in shares) at Mar. 31, 2021							225,490,000
Balance at beginning of period at Mar. 31, 2021	374,143			$ 153			$ 2	155,164	(4,218)	(130)	223,172
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	7,596								3,045		4,551
Common stock issued related to share-based compensation and other, net (in shares)				2,000
Common stock issued related to share-based compensation and other, net	924							922		1	1
Balance at end of period (in shares) at Jun. 30, 2021							225,490,000
Balance at end of period (in shares) at Jun. 30, 2021				15,312,000
Balance at end of period at Jun. 30, 2021	382,663			$ 153			$ 2	156,086	(1,173)	(129)	227,724
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	43,063								17,387		25,676
Common stock issued related to share-based compensation and other, net (in shares)				19,000
Common stock issued related to share-based compensation and other, net	864							864		(1)	1
Balance at end of period (in shares) at Sep. 30, 2021							225,490,000
Balance at end of period (in shares) at Sep. 30, 2021				15,331,000
Balance at end of period at Sep. 30, 2021	426,590			$ 153			$ 2	156,950	16,214	(130)	253,401
Balance at beginning of period (in shares) at Dec. 31, 2021		21,090,259	22,548,998		21,090,000	22,549,000
Balance at beginning of period at Dec. 31, 2021	669,508				$ 729	$ 2		273,329	49,583	(111)	345,976
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	(20,661)								(9,985)		(10,676)
Common stock issued related to share-based compensation and other, net (in shares)					56,000
Common stock issued related to share-based compensation and other, net	478							478
Balance at end of period (in shares) at Mar. 31, 2022					21,146,000	22,549,000
Balance at end of period at Mar. 31, 2022	649,325				$ 729	$ 2		273,807	39,598	(111)	335,300
Balance at beginning of period (in shares) at Dec. 31, 2021		21,090,259	22,548,998		21,090,000	22,549,000
Balance at beginning of period at Dec. 31, 2021	669,508				$ 729	$ 2		273,329	49,583	(111)	345,976
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	$ 354,964
Balance at end of period (in shares) at Sep. 30, 2022	0
Balance at end of period (in shares) at Sep. 30, 2022		19,422,156	22,548,998		19,422,000	22,549,000
Balance at end of period at Sep. 30, 2022	$ 964,532				$ 194	$ 2		230,777	215,475	(111)	518,195
Balance at beginning of period (in shares) at Mar. 31, 2022					21,146,000	22,549,000
Balance at beginning of period at Mar. 31, 2022	649,325				$ 729	$ 2		273,807	39,598	(111)	335,300
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	148,040								71,184		76,856
Repurchase of Class A Common Stock (in shares)					(681,000)
Repurchase of Class A Common Stock	(25,059)				$ (7)			(25,052)
Change in ownership, net	0							6,498			(6,498)
Common stock issued related to share-based compensation and other, net (in shares)					18,000
Common stock issued related to share-based compensation and other, net	1,845				$ (517)			2,362
Balance at end of period (in shares) at Jun. 30, 2022					20,483,000	22,549,000
Balance at end of period at Jun. 30, 2022	774,151				$ 205	$ 2		257,615	110,782	(111)	405,658
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	227,585								106,236		121,349
Repurchase of Class A Common Stock (in shares)					(1,075,000)
Repurchase of Class A Common Stock	(35,022)				$ (11)			(35,011)
Change in ownership, net	0							7,121			(7,121)
Distributions to Noncontrolling interest	(1,691)										(1,691)
Dividends declared ($0.075 per share of Class A common stock)	(1,543)	$ (3,200)							(1,543)
Common stock issued related to share-based compensation and other, net (in shares)					14,000
Common stock issued related to share-based compensation and other, net	$ 1,052							1,052
Balance at end of period (in shares) at Sep. 30, 2022	0
Balance at end of period (in shares) at Sep. 30, 2022		19,422,156	22,548,998		19,422,000	22,549,000
Balance at end of period at Sep. 30, 2022	$ 964,532				$ 194	$ 2		$ 230,777	$ 215,475	$ (111)	$ 518,195

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CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - UNAUDITED (Parenthetical) - $ / shares	3 Months Ended
	Sep. 30, 2022	Dec. 31, 2021	Oct. 31, 2021	Oct. 05, 2021
Common stock, par value (in dollars per share)				$ 0.01
Common Class A
Cash dividend declared (in dollars per share)	$ 0.075
Common stock, par value (in dollars per share)	0.01	$ 0.01	$ 0.01
Common Class B
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01

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Organization and Description of Business

9 Months Ended

Sep. 30, 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, ROCC Energy Holdings, L.P. (formerly 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 (“Rocky Creek”), 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. See Note 2 for further discussion.

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Basis of Presentation and Significant Accounting Policies

9 Months Ended

Sep. 30, 2022

Accounting Policies [Abstract]

Basis of Presentation and Significant Accounting Policies

Note 2 – Basis of Presentation and Significant Accounting Policies

Basis of Presentation

Our unaudited condensed consolidated financial statements include the accounts of Ranger Oil and all of our subsidiaries as of the relevant dates. Intercompany balances and transactions have been eliminated. A substantial noncontrolling interest in our subsidiaries is provided for in our condensed consolidated statements of operations and comprehensive income 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 (“2021 Annual Report”). Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

Principles of Consolidation

In January 2021, Ranger Oil completed a reorganization into an Up-C structure with JSTX and Rocky Creek. Under the Up-C structure, Juniper owns all of the shares of the Company’s Class B Common Stock which are non-economic voting only shares of the Company. Juniper’s economic interest in the Company is held through its ownership of limited partner interests (the “Common Units”) in the Partnership. Pursuant to the amended and restated limited partnership agreement of the Partnership (the “Partnership Agreement”), the Company’s ownership of Common Units in the Partnership at all times equals the number of shares of the Company’s Class A Common Stock then outstanding, and Juniper’s ownership of Common Units in the Partnership at all times equals the number of shares of Class B Common Stock then outstanding. The Partnership was formed for the purpose of executing the Company’s reorganization with Juniper into an Up-C structure. The Partnership, through its subsidiaries, owns, operates, and manages oil and gas properties in Texas and manages the Company’s outstanding debt and derivative instruments. The Company’s wholly-owned subsidiary, ROCC Energy Holdings GP LLC (formerly, PV Energy Holdings GP, LLC, the “GP”), is the general partner of the Partnership. Subsidiaries of the Partnership own and operate all our oil and gas assets. Ranger Oil and the Partnership are holding companies with no other operations, material cash flows, or material assets or liabilities other than the equity interests in their subsidiaries.

The Common Units are redeemable (concurrently with the cancellation of an equivalent number of shares of Class B Common Stock) by Juniper at any time on a one-for-one basis in exchange for shares of Class A Common Stock or, if the Partnership elects, cash based on the 5-day average volume-weighted closing price for the Class A Common Stock immediately prior to the redemption. In determining whether to make a cash election, the Company would consider the interests of the holders of the Class A Common Stock, the Company’s financial condition, results of operations, earnings, projections, liquidity and capital requirements, management’s assessment of the intrinsic value of the Class A Common Stock, the trading price of the Class A Common Stock, legal requirements, covenant compliance, restrictions in the Company’s debt agreements and other factors it deems relevant.

The Partnership is considered a variable interest entity for which the Company is the primary beneficiary. The Company has benefits in the Partnership through the Common Units, and it has power over the activities most significant to the Partnership’s economic performance through its 100% controlling interest in the GP (which, accordingly, is acting as an agent on behalf of the Company). This conclusion was based on a qualitative analysis that considered the Partnership’s governance structure and the GP’s control over operations of the Partnership. The GP manages the business and affairs of the Partnership, including key Partnership decision-making, and the limited partners do not possess any substantive participating or kick-out rights that would allow Juniper to block or participate in certain operational and financial decisions that most significantly impact the Partnership’s economic performance or that would remove the GP. As such, because the Company has both power and benefits in the Partnership, the Company determined it is the primary beneficiary of the Partnership and consolidates the Partnership in the Company’s consolidated financial statements. The Company reflects a noncontrolling interest in the consolidated financial statements based on the proportion of Common Units owned by Juniper relative to the total number of Common Units outstanding. The noncontrolling interest is presented as a component of equity in the accompanying condensed consolidated financial statements and represents the ownership interest held by Juniper in the Partnership.

Noncontrolling Interest

The noncontrolling interest percentage may be affected by the issuance of shares of Class A Common Stock, repurchases or cancellation of Class A Common Stock, the exchange of Class B Common Stock and the redemption of Common Units (and concurrent cancellation of Class B Common Stock), among other things. The percentage is based on the proportionate number of Common Units held by Juniper relative to the total Common Units outstanding. As of September 30, 2022, the Company owned 19,422,156 Common Units, representing a 46.3% limited partner interest in the Partnership, and Juniper owned 22,548,998 Common Units, representing the remaining 53.7% limited partner interest. As of December 31, 2021, the Company owned 21,090,259 Common Units, representing a 48.3% limited partner interest in the Partnership, and Juniper owned 22,548,998 Common Units, representing the remaining 51.7% limited partner interest. During the three and nine months ended September 30, 2022, changes in the ownership interests were the result of share repurchases and issuances of Class A Common Stock in connection with the vesting of employees’ share-based compensation. See Note 12 for information regarding share repurchases and Note 13 for vesting of share-based compensation.

When the Company’s relative ownership interest in the Partnership changes, adjustments to Noncontrolling interest and Paid-in capital, tax effected, will occur. Because these changes in the ownership interest in the Partnership do not result in a change of control, the transactions are accounted for as equity transactions under Accounting Standards Codification Topic 810, Consolidation, which requires that any differences between the carrying value of the Company’s basis in the Partnership and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. Additionally, based on the Partnership Agreement, there are no substantive profit sharing arrangements that would cause distributions to be other than pro rata. Therefore, profits and losses are attributed to the common shareholders and noncontrolling interest pro rata based on ownership interests in the Partnership.

Cash, Cash Equivalents and Restricted Cash

Cash and cash equivalents includes cash and highly liquid investments with original maturities of three months or less from the date of purchase. Restricted cash represents cash that is not readily available for general purpose cash needs. As of September 30, 2022 and December 31, 2021, the Company had no cash equivalents or restricted cash.

Of the $446.8 million in total cash, cash equivalents and restricted cash presented on the condensed consolidated statement of cash flows as of September 30, 2021, the Company had cash of $35.3 million, restricted cash – current of $15.4 million and restricted cash – non-current of $396.1 million. The restricted cash related to the net proceeds received from the offering of senior unsecured notes and certain additional funds that were held in escrow and subsequently released upon the acquisition of Lonestar Resources US Inc., a Delaware corporation (“Lonestar”). See Note 3 for additional information on this acquisition and Note 7 for additional information on the senior unsecured notes.

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 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.

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Acquisitions and Dispositions

9 Months Ended

Sep. 30, 2022

Business Combination and Asset Acquisition [Abstract]

Acquisitions and Dispositions

Note 3 – Acquisitions and Dispositions

2022

Asset Acquisitions

In the second and third quarters of 2022, we completed acquisitions of additional working interests in Ranger-operated wells along with certain contiguous oil and gas producing assets and undeveloped acreage in the Eagle Ford shale. The aggregate cash consideration for these acquisitions was $129.8 million, subject to customary post-closing adjustments. These transactions were accounted for as asset acquisitions.

Asset Disposition

On July 22, 2022, we closed on the sale of 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 September 30, 2022 and December 31, 2021. Gross proceeds were $11.0 million with costs to sell of approximately $0.8 million and included the payoff of the related mortgage debt and accrued interest of $8.4 million for total net proceeds of $1.8 million. This transaction did not result in any material change to the purchase allocation further described below.

2021

Acquisition of Lonestar Resources

On October 5, 2021 (the “Closing Date”), the Company acquired 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 are recorded at their respective fair values as of the date of completion of the Lonestar Acquisition. The Company completed the purchase price allocation during the third quarter of 2022, and there were no material changes to the allocation presented in the 2021 Form 10-K.

We expensed $2.0 million in acquisition-related costs for the nine months ended September 30, 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 and nine months ended September 30, 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 September 30, 2021		Nine Months Ended September 30, 2021
Total revenues	$	200,995	$	500,087
Net income (loss) attributable to common shareholders	$	12,531	$	(19,174)

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Revenue Recognition

9 Months Ended

Sep. 30, 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. Our oil, natural gas, and NGL receivables are typically collected within 30 to 90 days. The following table summarizes our accounts receivable by type as of the dates presented:

	September 30, 2022		December 31, 2021
Customers	$	123,493	$	96,195
Joint interest partners	22,964		21,755
Derivative settlements from counterparties 1	1,619		1,037
Other	99		18
Total	148,175		119,005
Less: Allowance for credit losses	(352)		(411)
Accounts receivable, net of allowance for credit losses	$	147,823	$	118,594

_______________________

1     See Note 5 for information regarding our derivative instruments.

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Derivative Instruments

9 Months Ended

Sep. 30, 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 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 September 30, 2022:

	4Q2022		1Q2023		2Q2023		3Q2023		4Q2023		1Q2024		2Q2024
NYMEX WTI Crude Swaps
Average Volume Per Day (bbl)	3,000		2,500		2,400		2,807		2,657		462		462
Weighted Average Swap Price ($/bbl)	$	69.20	$	54.40	$	54.26	$	54.92	$	54.93	$	58.75	$	58.75
NYMEX WTI Crude Collars
Average Volume Per Day (bbl)	20,245		12,917		11,126		8,152		4,891
Weighted Average Purchased Put Price ($/bbl)	$	64.56	$	63.23	$	61.48	$	72.00	$	70.00
Weighted Average Sold Call Price ($/bbl)	$	88.78	$	79.67	$	74.31	$	89.91	$	86.04
NYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (bbl)	3,804
Weighted Average Swap Price ($/bbl)	$	1.751
NYMEX HH Swaps
Average Volume Per Day (MMBtu)	12,500		10,000		7,500
Weighted Average Swap Price ($/MMBtu)	$	3.793	$	3.620	$	3.690
NYMEX HH Collars
Average Volume Per Day (MMBtu)	14,511		14,617		11,538		11,413		11,413		11,538		11,538
Weighted Average Purchased Put Price ($/MMBtu)	$	2.854	$	6.561	$	2.500	$	2.500	$	2.500	$	2.500	$	2.328
Weighted Average Sold Call Price ($/MMBtu)	$	3.791	$	12.334	$	2.682	$	2.682	$	2.682	$	3.650	$	3.000
OPIS Mt. Belv Ethane Swaps
Average Volume per Day (gal)	27,717				98,901		34,239		34,239		34,615
Weighted Average Fixed Price ($/gal)	$	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

Through May 2022, we had a series of interest rate swap contracts (the “Interest Rate Swaps”) establishing fixed interest rates on a portion of our variable interest rate indebtedness. The notional amount of the Interest Rate Swaps totaled $300 million, with us paying a weighted average fixed rate of 1.36% on the notional amount, and the counterparties paying a variable rate equal to LIBOR. As of September 30, 2022, we did not have any interest rate derivatives.

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. Adjustments to reconcile net income to net cash provided by operating activities include derivative losses and cash settlements that are reported under Net losses and Cash settlements and premiums paid, net, on our condensed consolidated statements of cash flows, respectively.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Interest Rate Swap gains (losses) recognized in the condensed consolidated statements of operations	$	—	$	(84)	$	64	$	(48)
Commodity gains (losses) recognized in the condensed consolidated statements of operations	63,756		(21,000)		(149,137)		(119,631)
	$	63,756	$	(21,084)	$	(149,073)	$	(119,679)
Interest rate cash settlements recognized in the condensed consolidated statements of cash flows	$	—	$	(973)	$	(1,415)	$	(2,851)
Commodity cash settlements and premiums paid recognized in the condensed consolidated statements of cash flows	(55,302)		(21,265)		(157,809)		(43,190)
	$	(55,302)	$	(22,238)	$	(159,224)	$	(46,041)

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
		September 30, 2022				December 31, 2021
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Interest rate contracts	Derivative assets/liabilities – current	$	—	$	—	$	—	$	1,480
Commodity contracts	Derivative assets/liabilities – current	30,725		75,327		11,478		48,892
Interest rate contracts	Derivative assets/liabilities – non-current	—		—		—		—
Commodity contracts	Derivative assets/liabilities – non-current	6,176		12,748		2,092		23,815
		$	36,901	$	88,075	$	13,570	$	74,187

As of September 30, 2022, we reported net commodity derivative liabilities of $51.2 million. The contracts associated with these positions are with seven counterparties for commodity derivatives, all of which are investment grade financial institutions and are participants in our revolving credit facility (the “Credit Facility”). This concentration may impact our overall credit risk in that these counterparties may be similarly affected by changes in economic or other conditions. Non-performance risk is incorporated by utilizing discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is in a liability position.

The agreements underlying our derivative instruments include provisions for the netting of settlements with the counterparties for contracts of similar type. We have neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. Furthermore, our derivative contracts are not subject to margin calls or similar accelerations. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.

See Note 10 for information regarding the fair value of our derivative instruments.

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Property and Equipment, Net

9 Months Ended

Sep. 30, 2022

Property, Plant and Equipment [Abstract]

Property and Equipment, Net

Note 6 – Property and Equipment, Net

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

	September 30, 2022		December 31, 2021
Oil and gas properties (full cost accounting method):
Proved	$	2,828,400	$	2,327,686
Unproved	55,429		57,900
Total oil and gas properties	2,883,829		2,385,586
Other property and equipment 1	32,156		31,055
Total properties and equipment	2,915,985		2,416,641
Accumulated depreciation, depletion, amortization and impairments	(1,204,618)		(1,033,293)
Total property and equipment, net	$	1,711,367	$	1,383,348

_______________________

1     Excludes the corporate office building and related other assets acquired in connection with the Lonestar Acquisition that were classified as Assets held for sale on the condensed consolidated balance sheets as of December 31, 2021. We closed on the sale of the corporate office building in July 2022. See Note 3 for additional information. As of September 30, 2022, we had $1.2 million remaining other assets classified as Assets held for sale excluded from above.

Unproved property costs of $55.4 million and $57.9 million have been excluded from amortization as of September 30, 2022 and December 31, 2021, respectively. We transferred $8.7 million and $13.8 million of unproved 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 nine months ended September 30, 2022 and 2021, respectively. We capitalized internal costs of $4.0 million and $2.8 million and interest of $3.3 million and $2.6 million during the nine months ended September 30, 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 $15.84 and $12.96 for the nine months ended September 30, 2022 and 2021, respectively.

Ceiling Test

Beginning in early 2020, certain events such as the COVID-19 pandemic coupled with 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, the deployment of vaccines and resulting increased mobility and global economic activity, and other factors have resulted in increased oil demand and commodity prices. Prior to the announced significant production cut to take effect in November 2022, OPEC+ had previously employed a strategy to gradually increase production. These shifts in OPEC+ production levels as well as the Russia-Ukraine war and related sanctions, which began in the first quarter of 2022, continue to contribute to a high level of uncertainty surrounding energy supply and demand resulting in volatile commodity prices. WTI crude oil and natural gas prices surged with prices over $120 per bbl and over $9 per Mcf, respectively, during the first half of 2022 due to oil supply shortage concerns. During the third quarter of 2022, WTI crude oil and natural gas prices dropped to lows under $77 per bbl and $6 per Mcf, 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”). The Ceiling Test utilizes commodity prices based on a trailing 12-month average based on the closing prices on the first day of each month. We did not record any impairments of our oil and gas properties during the three and nine months ended September 30, 2022. The first quarter of 2021 was impacted by the decline in commodity prices as a result of COVID-19 and macroeconomic factors as discussed above, resulting in an impairment of our oil and gas properties of $1.8 million during the three months ended March 31, 2021. No further impairments were recorded during the remainder of 2021.

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Long-Term Debt

9 Months Ended

Sep. 30, 2022

Debt Disclosure [Abstract]

Long-Term Debt

Note 7 – Long-Term Debt

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

	September 30, 2022		December 31, 2021
Credit Facility	$	215,000	$	208,000
9.25% Senior Notes due 2026	400,000		400,000
Mortgage debt 1	—		8,438
Other 2	284		2,516
Total	615,284		618,954
Less: Unamortized discount 3	(3,227)		(3,720)
Less: Unamortized deferred issuance costs 3, 4	(8,559)		(9,853)
Total, net	603,498		605,381
Less: Current portion	(41)		(4,129)
Long-term debt	$	603,457	$	601,252

_______________________

1     The mortgage debt related to the corporate office building and related other assets acquired in connection with the Lonestar Acquisition for which assets were held as collateral for such debt. As of December 31, 2021, these assets met the held for sale criteria and were classified as Assets held for sale on the condensed consolidated balance sheets. In July 2022, the mortgage debt was fully repaid in connection with the sale of the corporate office building. See Note 3 for additional information on the sale.

2     Other debt of $2.2 million was extinguished during the nine months ended September 30, 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 September 30, 2022, the Credit Facility had a $1.0 billion revolving commitment and a $950 million borrowing base with aggregate elected commitments of $500 million, and a $25 million sublimit for the issuance of letters of credit. Availability under the Credit Facility may not exceed the lesser of the aggregate elected commitments or the borrowing base less outstanding advances and letters of credit. The borrowing base under the Credit Facility is redetermined semi-annually, generally in the Spring and Fall of each year. Additionally, we and the Credit Facility lenders may, upon request, initiate a redetermination at any time during the six-month period between scheduled redeterminations. The Credit Facility is available to us for general corporate purposes, including working capital.

In June 2022, we entered into the Agreement and Amendment No. 12 to Credit Agreement (the “Twelfth Amendment”). The Twelfth Amendment, in addition to other changes described therein, amended the Credit Facility to, effective on June 1, 2022, (1) increase the borrowing base from $725 million to $875 million, with aggregate elected commitments remaining at $400 million and (2) replaced LIBOR with the Secured Overnight Financing Rate (“SOFR”), an index supported by short-term Treasury repurchase agreements.

In September 2022, we entered into the Agreement and Amendment No. 13 to Credit Agreement (the “Thirteenth Amendment”). The Thirteenth Amendment, in addition to other changes described therein, amended the Credit Facility to (1) increase the borrowing base from $875 million to $950 million and (2) increase the aggregate elected commitment amounts under the Credit Facility from $400 million to $500 million.

The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 1.50% to 2.50%, determined based on the utilization level under the Credit Facility or (b) effective June 1, 2022, a term SOFR reference rate (a Eurodollar rate, including LIBOR prior to June 1, 2022), 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 September 30, 2022, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 5.63%. 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 September 30, 2022, we were in compliance with all debt covenants under the Credit Facility.

We had $215.0 million in outstanding borrowings and $0.7 million in outstanding letters of credit under the Credit Facility as of September 30, 2022. Factoring in the outstanding letters of credit, we had $284.3 million of availability under the Credit Facility as of September 30, 2022. During the nine months ended September 30, 2022 and 2021, we incurred and capitalized approximately $0.8 million and $0.7 million of issue costs associated with amendments to the Credit Facility, respectively.

9.25% Senior Notes due 2026

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

Interest on the 9.25% Senior Notes due 2026 is payable semi-annually in arrears on February 15 and August 15 of each year. We may redeem the 9.25% Senior Notes due 2026 at any time in whole or in part from time to time at specified redemption prices.

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

As of September 30, 2022, we were in compliance with all debt covenants under the indenture.

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Income Taxes

9 Months Ended

Sep. 30, 2022

Income Tax Disclosure [Abstract]

Income Taxes

Note 8 – Income Taxes

The income tax provision resulted in an expense of $2.1 million and an expense of $3.2 million for the three and nine months ended September 30, 2022, respectively. 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 $5.0 million as of September 30, 2022 is also fully attributable to the State of Texas and primarily related to property.

The income tax provision resulted in an expense of $0.5 million and an expense of $0.4 million for the three and nine months ended September 30, 2021, respectively. 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 1.3%, which is fully attributable to the State of Texas.

We had no liability for unrecognized tax benefits as of September 30, 2022 and December 31, 2021. There were no interest and penalty charges recognized during the nine months ended September 30, 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

9 Months Ended

Sep. 30, 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:

	September 30, 2022		December 31, 2021
Prepaid and other current assets:
Inventories 1	$	10,504	$	10,305
Prepaid expenses 2	2,545		10,693
	$	13,049	$	20,998
Other assets:
Deferred issuance costs of the Credit Facility, net of amortization	$	3,603	$	3,308
Right-of-use assets – operating leases	1,083		1,671
Other	—		38
	$	4,686	$	5,017
Accounts payable and accrued liabilities:
Trade accounts payable	$	31,135	$	32,452
Drilling and other lease operating costs	81,225		35,045
Revenue and royalties payable	110,867		95,521
Production, ad valorem and other taxes	15,949		7,905
Derivative settlements to counterparties	5,991		6,117
Compensation and benefits	6,848		13,942
Interest	5,341		15,321
Environmental remediation liability 3	1,519		2,287
Current operating lease obligations	876		914
Other	4,613		4,877
	$	264,364	$	214,381
Other non-current liabilities:
Asset retirement obligations	$	8,691	$	8,413
Non-current operating lease obligations	332		975
Postretirement benefit plan obligations	907		970
	$	9,930	$	10,358

_______________________

1    Includes tubular inventory and well materials of $9.9 million and $9.5 million and crude oil volumes in storage of $0.6 million and $0.8 million as of September 30, 2022 and December 31, 2021, respectively.

2 The balances as of September 30, 2022 and December 31, 2021 include $0.8 million and $9.6 million, respectively, for the prepayment of drilling and completion materials and services.

3 The balance as of September 30, 2022 and December 31, 2021 represents estimated costs associated with remediation activities for certain wells and tanks acquired as part of the Lonestar Acquisition; the remediation will be substantially complete in the fourth quarter of 2022.

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Fair Value Measurements

9 Months Ended

Sep. 30, 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 September 30, 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 September 30, 2022, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $615.3 million and $548.7 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 September 30, 2022
	Level 1		Level 2		Level 3		Total
Financial assets:
Commodity derivative assets – current	$	—	$	30,725	$	—	$	30,725
Commodity derivative assets – non-current	—		6,176		—		6,176
Total financial assets	$	—	$	36,901	$	—	$	36,901
Financial liabilities:
Interest rate swap liabilities – current	$	—	$	—	$	—	$	—
Commodity derivative liabilities – current	—		(75,327)		—		(75,327)
Commodity derivative liabilities – non-current	—		(12,748)		—		(12,748)
Total financial liabilities	$	—	$	(88,075)	$	—	$	(88,075)

	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, Magellan East Houston (“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 determined the fair values of our interest rate swaps using an income approach valuation technique which discounts future cash flows back to a single present value. We estimated the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these was a Level 2 input. All interest rate swaps matured in May 2022, and as of September 30, 2022, we had not entered into any new interest rate derivative instruments.

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

Non-Recurring Fair Value Measurements

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

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2022

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 11 – Commitments and Contingencies

Drilling and Completion Commitments

As of September 30, 2022, we had a two year contract for one drilling rig and contracts for two drilling rigs with terms less than one year.

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 September 30, 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 the field gathering and volume capacity support 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 September 30, 2022 and 2021, we recorded expense of $11.1 million and $9.2 million, respectively, and $31.9 million and $26.3 million during the nine months ended September 30, 2022 and 2021, respectively for these contractual obligations.

Excluding the application of credits earned during the 12-month period ended September 30, 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: $3.5 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 September 30, 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 an additional 70,000 barrels of tank capacity at the CDP on a month-to-month basis, which can be terminated by either party with 45 days’ notice to the counterparty. Costs associated with this monthly agreement are in the form of a monthly fixed rate short-term lease and are charged as incurred on a monthly basis to GPT in our condensed consolidated statements of operations.

Other Agreements

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

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

We also have agreements that provide us with services to process our wet gas production into NGL products and dry, or residue, gas. Several agreements covering the majority of our wet gas production extend beyond three years, including one agreement that extends into 2029.

Legal, Environmental Compliance and Other

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. As of September 30, 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 September 30, 2022 and December 31, 2021, we had AROs of approximately $8.7 million and $8.4 million attributable to the plugging of abandoned wells, respectively. Additionally, we had $1.5 million and $2.3 million of environmental remediation liabilities recorded as part of the Lonestar Acquisition as of September 30, 2022 and December 31, 2021, respectively. The majority of the work related to the environmental remediation liabilities will be completed during the fourth quarter of 2022.

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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Shareholders' Equity

9 Months Ended

Sep. 30, 2022

Equity [Abstract]

Shareholders' Equity

Note 12 – Shareholders’ Equity

Capital Stock

Prior to the Lonestar Acquisition, the Company’s authorized capital stock consisted of 115,000,000 shares including (i) 110,000,000 shares of common stock, par value $0.01 per share and (ii) 5,000,000 shares of Series A Preferred Stock, par value $0.01 per share.

On October 6, 2021, in connection with the consummation of the Lonestar Acquisition, the Company effected a recapitalization, pursuant to which (i) the Company’s common stock was renamed and reclassified as Class A Common Stock, (ii) the authorized number of shares of capital stock of the Company was increased to 145,000,000 shares, (iii) 30,000,000 shares of Class B Common Stock was authorized, (iv) all 225,489.98 outstanding shares of the Series A Preferred Stock were exchanged for 22,548,998 newly issued shares of Class B Common Stock, and (v) the designation of the Series A Preferred Stock was cancelled.

As of September 30, 2022, the Company had two classes of common stock: Class A Common Stock and Class B Common Stock. The holders of record of Class A Common Stock and Class B Common Stock vote together as a single class on all matters on which holders of Class A Common Stock and Class B Common Stock are entitled to vote; except that certain directors are elected by holders of a majority of the shares of Class B Common Stock voting as a separate class.

The holders of Class A Common Stock have no preemptive rights to purchase shares of Class A Common Stock. Shares of Class A Common Stock are not subject to any redemption or sinking fund provisions and are not convertible into any of the Company’s other securities. In the event of the Company’s voluntary or involuntary liquidation, dissolution or winding up, holders of Class A Common Stock will share equally in the assets remaining after it pays its creditors and preferred shareholders. Holders of Class A Common Stock are entitled to receive dividends when and if declared by the Board of Directors.

Shares of Class B Common Stock are non-economic interests in the Company, and no dividends can be declared or paid on the Class B Common Stock. The holders of Class B Common Stock have no preemptive rights to purchase shares of Class B Common Stock. Shares of Class B common stock are not subject to any redemption or sinking fund provisions. In the event of the Company’s voluntary or involuntary liquidation, dissolution or winding up, after payment or provision for payment of its debts and other liabilities, the holders of Class B Common Stock will be entitled to receive, out of its assets or proceeds thereof available for distribution to our shareholders, before any distribution of such assets or proceeds is made to or set aside for the holders of Class A Common Stock and any other of the Company’s stock ranking junior to the Class B Common Stock as to such distribution, payment in full in an amount equal to $0.01 per share of Class B Common Stock. With the exception of the aforementioned distribution, the holders of shares of Class B Common Stock will not be entitled to receive any of the Company’s assets in the event of its voluntary or involuntary liquidation, dissolution or winding up.

The Company’s Class B Common Stock is not convertible into any of the Company’s other securities. However, if a holder exchanges one common unit of the Partnership, for one share of the Company’s Class A Common Stock, it must also surrender to the Company a share of its Class B Common Stock for each common unit exchanged.

As of September 30, 2022, the Company had (i) 110,000,000 authorized shares of Class A Common Stock and 19,422,156 shares of Class A Common Stock issued and outstanding, (ii) 30,000,000 authorized shares of Class B Common Stock and 22,548,998 shares of Class B Common Stock issued and outstanding, and (iii) 5,000,000 authorized shares of preferred stock, par value $0.01 per share, and no shares of preferred stock were issued or outstanding.

Dividends

On July 7, 2022, the Company’s Board of Directors declared a cash dividend of $0.075 per share of Class A Common Stock. The dividend was paid on August 4, 2022 to holders of record of Class A Common Stock as of the close of business on July 25, 2022. In connection with any dividend, Ranger’s operating subsidiary will also make a corresponding distribution to its common unitholders. During the third quarter of 2022, the dividend to the holders of our Class A Common Stock and distribution to common unitholders totaled $3.2 million in the aggregate. The Company’s Credit Facility and the Indenture have restrictive covenants that limit its ability to pay dividends. See Note 15 for details on dividends declared subsequent to September 30, 2022.

Share Repurchase Program

On April 13, 2022, our Board of Directors approved a share repurchase program that authorized the Company to repurchase up to $100 million of its outstanding Class A Common Stock. The share repurchase authorization was effective immediately and was valid through March 31, 2023. On July 7, 2022, the Board of Directors authorized an increase in the share repurchase program from $100 million to $140 million and extended the term of the program through June 30, 2023.

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 continue 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, 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. On August 16, 2022, the Inflation Reduction Act was signed into law and imposes a 1% excise tax on the repurchase of stock by publicly traded U.S. corporations. The excise tax is effective for stock repurchases after December 31, 2022. We are currently evaluating the impacts, if any, of this provision to our results of operations and cash flows.

During the three and nine months ended September 30, 2022, we repurchased 1,074,960 and 1,755,836 shares of our Class A Common Stock at a total cost of $35.0 million and $60.0 million at average purchase prices of $32.58 and $34.19, respectively. The share repurchases were recorded to Class A common stock and Paid-in capital on our condensed consolidated balance sheets. As of September 30, 2022, the remaining authorized repurchase amount under the share repurchase program was $80.0 million.

Change in Ownership of Consolidated Subsidiaries

As discussed above and in Note 13, in the three and nine months ended September 30, 2022, we repurchased shares of our Class A Common Stock and issued shares of our Class A Common Stock related to the vesting of employees’ share-based compensation resulting in a change in the proportionate share of Common Units held by the Company relative to Juniper. As such, we recognized an adjustment to the carrying amount of noncontrolling interest and a corresponding adjustment to Class A Common Shareholders’ equity of $7.1 million and $13.6 million for the three and nine months ended September 30, 2022 to reflect the revised ownership percentage of total equity, respectively.

The following table summarizes changes in the ownership interest in consolidated subsidiaries during the period:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Net income attributable to common shareholders	$	106,236	$	17,387	$	167,435	$	6,860
Transfers from the noncontrolling interest, net 1	7,121		N/A		13,619		N/A
Change from net income attributable to common shareholders and net transfers to Noncontrolling interest	$	113,357	$	17,387	$	181,054	$	6,860

_____________________________________________

1     The three and nine months ended September 30, 2022 includes a net transfer of $7.1 million and $13.6 million, respectively, from Noncontrolling interest for share repurchases and common stock issuances related to employees’ share-based compensation with a corresponding adjustment to Paid-in capital. This equity adjustment had no impact on earnings other than a resulting increase to the noncontrolling interest proportionate share of net income and a corresponding decrease to the proportionate share of net income attributable to common shareholders.

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Share-Based Compensation and Other Benefit Plans

9 Months Ended

Sep. 30, 2022

Share-Based Payment Arrangement [Abstract]

Share-Based Compensation and Other Benefit Plans

Note 13 – Share-Based Compensation and Other Benefit Plans

Share-Based Compensation

We reserved 4,424,600 shares of Class A Common Stock for issuance under the Ranger Oil Management Incentive Plan (the “Plan”) for share-based compensation awards. A total of 811,573 time-vested restricted stock units (“RSUs”) and 664,414 performance-based restricted stock units (“PRSUs”) have been granted to employees and directors through September 30, 2022.

We recognized expense attributable to the RSUs and PRSUs of $1.3 million and $4.3 million for the three and nine months ended September 30, 2022, respectively. During the three months ended September 30, 2021, we recognized $1.0 million of expense attributable to the RSUs and PRSUs and during the nine months ended September 30, 2021, we recognized $4.2 million of expense attributable to the RSUs and PRSUs, including approximately $1.9 million as a result of a change-in-control event associated with the Juniper Transactions. 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 nine months ended September 30, 2022 with respect to awarded RSUs:

	Time-Vested Restricted Stock Units	Weighted-Average Grant Date Fair Value
Balance at January 1, 2022	230,517	$	9.20
Granted	49,314	$	35.07
Vested	(111,479)	$	10.02
Forfeited	(16,101)	$	12.12
Balance at September 30, 2022	152,251	$	17.50

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 September 30, 2022, we had $2.0 million of unrecognized compensation cost attributable to RSUs. We expect that cost to be recognized over a weighted-average period of 1.89 years.

Performance-Based Restricted Stock Units

The table below summarizes activity for the nine months ended September 30, 2022 with respect to awarded PRSUs:

	Performance Restricted Stock Units	Weighted-Average Grant Date Fair Value
Balance at January 1, 2022	345,069	$	16.20
Granted	180,217	$	47.77
Vested	(2,688)	$	18.24
Forfeited	(11,516)	$	23.31
Balance at September 30, 2022	511,082	$	27.16

Compensation expense for PRSUs with a market condition is being charged to expense on a straight-line basis for the 2022 and 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 2022 and 2021 PRSU grants contain performance measures of which 50% are based on the Company’s return on average capital employed (“ROCE”) and 50% are based on the Company’s absolute total shareholder return and total shareholder return (“TSR”) relative to a defined peer group over the three-year performance period. The 2022 and 2021 PRSUs cliff vest from 0% to 200% of the original grant at the end of a three-year performance period based on satisfaction of the respective underlying conditions.

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 and 2022 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 2022, 2021, 2020 and 2019 are presented as follows:

	2022		2021 1		2020 1		2019
Expected volatility	134.98% to 138.75%		131.74% to 134.74%		101.32% to 117.71%		49.9	%
Dividend yield	0.0	%	0.0	%	0.0	%	0.0	%
Risk-free interest rate	2.59	%	0.22% to 0.29%		0.18% to 0.51%		1.66	%
Performance period	2022-2024		2021-2023		2020-2022		2020-2022

_______________________

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

As of September 30, 2022, we had $9.2 million of unrecognized compensation cost attributable to PRSUs. We expect that cost to be recognized over a weighted-average period of 1.93 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 expense attributable to the 401(k) Plan of $0.1 million and $0.5 million for the three and nine months ended September 30, 2022, respectively, and $0.2 million and $0.5 million for the three and nine months ended September 30, 2021, respectively. 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 nine months ended September 30, 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

9 Months Ended

Sep. 30, 2022

Earnings Per Share [Abstract]

Earnings Per Share

Note 14 – Earnings Per Share

Basic net earnings (loss) per share is calculated by dividing the net income (loss) available to 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 and nine months ended September 30, 2022 and Series A Preferred Stock, par value $0.01 per share (“Series A Preferred Stock”) as applicable to the three and nine months ended September 30, 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 due to the elimination of the Noncontrolling interest assuming exchange of the Common Units (and shares of Class B Common Stock as applicable to the three and nine months ended September 30, 2022 and Series A Preferred Stock as applicable to the three and nine months ended September 30, 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 September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Numerator:
Net income	$	227,585	$	43,063	$	354,964	$	30,638
Net income attributable to Noncontrolling interest	(121,349)		(25,676)		(187,529)		(23,778)
Net income attributable to common shareholders for Basic EPS	106,236		17,387		167,435		6,860
Adjustment for assumed conversions and elimination of Noncontrolling interest net income	785		25,676		1,154		23,778
Net income attributable to common shareholders for Diluted EPS	$	107,021	$	43,063	$	168,589	$	30,638
Denominator:
Weighted average shares outstanding used in Basic EPS	19,741		15,319		20,573		15,298
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, 2	—		—		—		—
RSUs and PRSUs	600		394		582		371
Weighted average shares outstanding used in Diluted EPS 2	20,341		15,713		21,155		15,669

_______________________

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 and nine months ended September 30, 2022, approximately 22.5 million potentially dilutive Common Units (and the associated 22.5 million Class B Common Stock) had the effect of being anti-dilutive and were excluded from the calculation of earnings per share. For the three and nine months ended September 30, 2021, approximately 22.5 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).

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Subsequent Events

9 Months Ended

Sep. 30, 2022

Subsequent Events [Abstract]

Subsequent Events

Note 15 – Subsequent Events

Dividends

On November 2, 2022, the Company’s Board of Directors declared a cash dividend of $0.075 per share of Class A Common Stock, payable on November 28, 2022 to holders of record of Class A Common Stock as of the close of business on November 16, 2022.

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Basis of Presentation and Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2022

Accounting Policies [Abstract]

Basis of Presentation

Basis of PresentationOur unaudited condensed consolidated financial statements include the accounts of Ranger Oil and all of our subsidiaries as of the relevant dates. Intercompany balances and transactions have been eliminated. A substantial noncontrolling interest in our subsidiaries is provided for in our condensed consolidated statements of operations and comprehensive income 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 (“2021 Annual Report”). Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

Principles of Consolidation

Principles of Consolidation

In January 2021, Ranger Oil completed a reorganization into an Up-C structure with JSTX and Rocky Creek. Under the Up-C structure, Juniper owns all of the shares of the Company’s Class B Common Stock which are non-economic voting only shares of the Company. Juniper’s economic interest in the Company is held through its ownership of limited partner interests (the “Common Units”) in the Partnership. Pursuant to the amended and restated limited partnership agreement of the Partnership (the “Partnership Agreement”), the Company’s ownership of Common Units in the Partnership at all times equals the number of shares of the Company’s Class A Common Stock then outstanding, and Juniper’s ownership of Common Units in the Partnership at all times equals the number of shares of Class B Common Stock then outstanding. The Partnership was formed for the purpose of executing the Company’s reorganization with Juniper into an Up-C structure. The Partnership, through its subsidiaries, owns, operates, and manages oil and gas properties in Texas and manages the Company’s outstanding debt and derivative instruments. The Company’s wholly-owned subsidiary, ROCC Energy Holdings GP LLC (formerly, PV Energy Holdings GP, LLC, the “GP”), is the general partner of the Partnership. Subsidiaries of the Partnership own and operate all our oil and gas assets. Ranger Oil and the Partnership are holding companies with no other operations, material cash flows, or material assets or liabilities other than the equity interests in their subsidiaries.

The Common Units are redeemable (concurrently with the cancellation of an equivalent number of shares of Class B Common Stock) by Juniper at any time on a one-for-one basis in exchange for shares of Class A Common Stock or, if the Partnership elects, cash based on the 5-day average volume-weighted closing price for the Class A Common Stock immediately prior to the redemption. In determining whether to make a cash election, the Company would consider the interests of the holders of the Class A Common Stock, the Company’s financial condition, results of operations, earnings, projections, liquidity and capital requirements, management’s assessment of the intrinsic value of the Class A Common Stock, the trading price of the Class A Common Stock, legal requirements, covenant compliance, restrictions in the Company’s debt agreements and other factors it deems relevant. The Partnership is considered a variable interest entity for which the Company is the primary beneficiary. The Company has benefits in the Partnership through the Common Units, and it has power over the activities most significant to the Partnership’s economic performance through its 100% controlling interest in the GP (which, accordingly, is acting as an agent on behalf of the Company). This conclusion was based on a qualitative analysis that considered the Partnership’s governance structure and the GP’s control over operations of the Partnership. The GP manages the business and affairs of the Partnership, including key Partnership decision-making, and the limited partners do not possess any substantive participating or kick-out rights that would allow Juniper to block or participate in certain operational and financial decisions that most significantly impact the Partnership’s economic performance or that would remove the GP. As such, because the Company has both power and benefits in the Partnership, the Company determined it is the primary beneficiary of the Partnership and consolidates the Partnership in the Company’s consolidated financial statements. The Company reflects a noncontrolling interest in the consolidated financial statements based on the proportion of Common Units owned by Juniper relative to the total number of Common Units outstanding. The noncontrolling interest is presented as a component of equity in the accompanying condensed consolidated financial statements and represents the ownership interest held by Juniper in the Partnership.

Noncontrolling Interest

Noncontrolling Interest

The noncontrolling interest percentage may be affected by the issuance of shares of Class A Common Stock, repurchases or cancellation of Class A Common Stock, the exchange of Class B Common Stock and the redemption of Common Units (and concurrent cancellation of Class B Common Stock), among other things. The percentage is based on the proportionate number of Common Units held by Juniper relative to the total Common Units outstanding. As of September 30, 2022, the Company owned 19,422,156 Common Units, representing a 46.3% limited partner interest in the Partnership, and Juniper owned 22,548,998 Common Units, representing the remaining 53.7% limited partner interest. As of December 31, 2021, the Company owned 21,090,259 Common Units, representing a 48.3% limited partner interest in the Partnership, and Juniper owned 22,548,998 Common Units, representing the remaining 51.7% limited partner interest. During the three and nine months ended September 30, 2022, changes in the ownership interests were the result of share repurchases and issuances of Class A Common Stock in connection with the vesting of employees’ share-based compensation. See Note 12 for information regarding share repurchases and Note 13 for vesting of share-based compensation.

When the Company’s relative ownership interest in the Partnership changes, adjustments to Noncontrolling interest and Paid-in capital, tax effected, will occur. Because these changes in the ownership interest in the Partnership do not result in a change of control, the transactions are accounted for as equity transactions under Accounting Standards Codification Topic 810, Consolidation, which requires that any differences between the carrying value of the Company’s basis in the Partnership and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. Additionally, based on the Partnership Agreement, there are no substantive profit sharing arrangements that would cause distributions to be other than pro rata. Therefore, profits and losses are attributed to the common shareholders and noncontrolling interest pro rata based on ownership interests in the Partnership.

Cash, Cash Equivalents and Restricted Cash

Cash, Cash Equivalents and Restricted Cash

Cash and cash equivalents includes cash and highly liquid investments with original maturities of three months or less from the date of purchase. Restricted cash represents cash that is not readily available for general purpose cash needs. As of September 30, 2022 and December 31, 2021, the Company had no cash equivalents or restricted cash.

Of the $446.8 million in total cash, cash equivalents and restricted cash presented on the condensed consolidated statement of cash flows as of September 30, 2021, the Company had cash of $35.3 million, restricted cash – current of $15.4 million and restricted cash – non-current of $396.1 million. The restricted cash related to the net proceeds received from the offering of senior unsecured notes and certain additional funds that were held in escrow and subsequently released upon the acquisition of Lonestar Resources US Inc., a Delaware corporation (“Lonestar”). See Note 3 for additional information on this acquisition and Note 7 for additional information on the senior unsecured notes.

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.

Fair Value Measurements

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

•Commodity derivatives: We determine the fair values of our commodity derivative instruments using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatilities, time value and non-performance risk. For the current market prices, we use third-party quoted forward prices, as applicable, for NYMEX WTI, Magellan East Houston (“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 determined the fair values of our interest rate swaps using an income approach valuation technique which discounts future cash flows back to a single present value. We estimated the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these was a Level 2 input. All interest rate swaps matured in May 2022, and as of September 30, 2022, we had not entered into any new interest rate derivative instruments.

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

Revenue

Crude oil. We sell our crude oil production to our customers at either the wellhead or a contractually agreed-upon delivery point, including certain regional central delivery point terminals or pipeline inter-connections. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality, location differentials and, if applicable, deductions for intermediate transportation. Costs incurred by us for gathering and transporting the products to an agreed-upon delivery point are recognized as a component of gathering, processing and transportation expense (“GPT”) in our condensed consolidated statements of operations.

NGLs. We have natural gas processing contracts in place with certain midstream processing vendors. We deliver “wet” natural gas to our midstream processing vendors at the inlet of their processing facilities through gathering lines, certain of which we own and others which are owned by gathering service providers. Subsequent to processing, NGLs are delivered or transported to a third-party customer. Depending upon the nature of the contractual arrangements with the midstream processing vendors regarding the marketing of the NGL products, we recognize revenue for NGL products on either a gross or net basis. For those contracts where we have determined that we are the principal, and the ultimate third party is our customer, we recognize revenue on a gross basis, with associated processing costs presented as GPT expenses. For those contracts where we have determined that we are the agent and the midstream processing vendor is our customer, we recognize NGL product revenues on a net basis with processing costs presented as a reduction of revenue.

Natural gas. Subsequent to the processing of “wet” natural gas and the separation of NGL products, the “dry” or residue gas is purchased by the processor or delivered to us at the tailgate of the midstream processing vendors’ facilities and sold to a third-party customer. We recognize revenue when control transfers to the customer considering factors associated with custody, title, risk of loss and other contractual provisions as appropriate. Pricing is based on a market index with adjustments for product quality and location differentials, as applicable. Costs incurred by us for gathering and transportation from the wellhead through the processing facilities are recognized as a component of GPT in our condensed consolidated statements of operations.

We record revenue in the month that our oil and gas production is delivered to our customers. However, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production sold. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized.

We apply a practical expedient which provides for an exemption from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Under our commodity product sales contracts, we bill our customers and recognize revenue when our performance obligations have been satisfied. At that time, we have determined that payment is unconditional. Accordingly, our commodity sales contracts do not create contract assets or liabilities.

Oil and Gas Properties Policy

At the end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated after-tax discounted future net revenues from proved properties adjusted for costs excluded from amortization (the “Ceiling Test”). The Ceiling Test utilizes commodity prices based on a trailing 12-month average based on the closing prices on the first day of each month.

Share-Based Payment Arrangement

Compensation expense for RSUs is recognized on a straight-line basis over the applicable vesting period, which is generally over a three-year period.Compensation expense for PRSUs with a performance condition is recognized 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.

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 and nine months ended September 30, 2022 and Series A Preferred Stock, par value $0.01 per share (“Series A Preferred Stock”) as applicable to the three and nine months ended September 30, 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 due to the elimination of the Noncontrolling interest assuming exchange of the Common Units (and shares of Class B Common Stock as applicable to the three and nine months ended September 30, 2022 and Series A Preferred Stock as applicable to the three and nine months ended September 30, 2021) held by the Noncontrolling interest.

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Acquisitions and Dispositions (Tables)

9 Months Ended

Sep. 30, 2022

Business Combination and Asset Acquisition [Abstract]

Schedule of Pro Forma Information

The following unaudited pro forma condensed financial data for the three months and nine months ended September 30, 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 September 30, 2021		Nine Months Ended September 30, 2021
Total revenues	$	200,995	$	500,087
Net income (loss) attributable to common shareholders	$	12,531	$	(19,174)

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Revenue Recognition (Tables)

9 Months Ended

Sep. 30, 2022

Receivables [Abstract]

Schedule of Accounts Receivable

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

	September 30, 2022		December 31, 2021
Customers	$	123,493	$	96,195
Joint interest partners	22,964		21,755
Derivative settlements from counterparties 1	1,619		1,037
Other	99		18
Total	148,175		119,005
Less: Allowance for credit losses	(352)		(411)
Accounts receivable, net of allowance for credit losses	$	147,823	$	118,594

_______________________1     See Note 5 for information regarding our derivative instruments.

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Commodity Derivative Positions

The following table sets forth our commodity derivative positions, presented on a net basis by period of maturity, as of September 30, 2022:

	4Q2022		1Q2023		2Q2023		3Q2023		4Q2023		1Q2024		2Q2024
NYMEX WTI Crude Swaps
Average Volume Per Day (bbl)	3,000		2,500		2,400		2,807		2,657		462		462
Weighted Average Swap Price ($/bbl)	$	69.20	$	54.40	$	54.26	$	54.92	$	54.93	$	58.75	$	58.75
NYMEX WTI Crude Collars
Average Volume Per Day (bbl)	20,245		12,917		11,126		8,152		4,891
Weighted Average Purchased Put Price ($/bbl)	$	64.56	$	63.23	$	61.48	$	72.00	$	70.00
Weighted Average Sold Call Price ($/bbl)	$	88.78	$	79.67	$	74.31	$	89.91	$	86.04
NYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (bbl)	3,804
Weighted Average Swap Price ($/bbl)	$	1.751
NYMEX HH Swaps
Average Volume Per Day (MMBtu)	12,500		10,000		7,500
Weighted Average Swap Price ($/MMBtu)	$	3.793	$	3.620	$	3.690
NYMEX HH Collars
Average Volume Per Day (MMBtu)	14,511		14,617		11,538		11,413		11,413		11,538		11,538
Weighted Average Purchased Put Price ($/MMBtu)	$	2.854	$	6.561	$	2.500	$	2.500	$	2.500	$	2.500	$	2.328
Weighted Average Sold Call Price ($/MMBtu)	$	3.791	$	12.334	$	2.682	$	2.682	$	2.682	$	3.650	$	3.000
OPIS Mt. Belv Ethane Swaps
Average Volume per Day (gal)	27,717				98,901		34,239		34,239		34,615
Weighted Average Fixed Price ($/gal)	$	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.

Schedule of Impact of Derivative Activities on Condensed Consolidated Statements of Income and Cash Flows

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Interest Rate Swap gains (losses) recognized in the condensed consolidated statements of operations	$	—	$	(84)	$	64	$	(48)
Commodity gains (losses) recognized in the condensed consolidated statements of operations	63,756		(21,000)		(149,137)		(119,631)
	$	63,756	$	(21,084)	$	(149,073)	$	(119,679)
Interest rate cash settlements recognized in the condensed consolidated statements of cash flows	$	—	$	(973)	$	(1,415)	$	(2,851)
Commodity cash settlements and premiums paid recognized in the condensed consolidated statements of cash flows	(55,302)		(21,265)		(157,809)		(43,190)
	$	(55,302)	$	(22,238)	$	(159,224)	$	(46,041)

Schedule of Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets

The following table summarizes the fair values of our derivative instruments, which we elect to present on a gross basis, as well as the locations of these instruments on our condensed consolidated balance sheets as of the dates presented:

		Fair Values
		September 30, 2022				December 31, 2021
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Interest rate contracts	Derivative assets/liabilities – current	$	—	$	—	$	—	$	1,480
Commodity contracts	Derivative assets/liabilities – current	30,725		75,327		11,478		48,892
Interest rate contracts	Derivative assets/liabilities – non-current	—		—		—		—
Commodity contracts	Derivative assets/liabilities – non-current	6,176		12,748		2,092		23,815
		$	36,901	$	88,075	$	13,570	$	74,187

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Property and Equipment, Net (Tables)

9 Months Ended

Sep. 30, 2022

Property, Plant and Equipment [Abstract]

Schedule of Property and Equipment

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

	September 30, 2022		December 31, 2021
Oil and gas properties (full cost accounting method):
Proved	$	2,828,400	$	2,327,686
Unproved	55,429		57,900
Total oil and gas properties	2,883,829		2,385,586
Other property and equipment 1	32,156		31,055
Total properties and equipment	2,915,985		2,416,641
Accumulated depreciation, depletion, amortization and impairments	(1,204,618)		(1,033,293)
Total property and equipment, net	$	1,711,367	$	1,383,348

_______________________

1     Excludes the corporate office building and related other assets acquired in connection with the Lonestar Acquisition that were classified as Assets held for sale on the condensed consolidated balance sheets as of December 31, 2021. We closed on the sale of the corporate office building in July 2022. See Note 3 for additional information. As of September 30, 2022, we had $1.2 million remaining other assets classified as Assets held for sale excluded from above.

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2022

Debt Disclosure [Abstract]

Schedule of Long-term Debt Instruments

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

	September 30, 2022		December 31, 2021
Credit Facility	$	215,000	$	208,000
9.25% Senior Notes due 2026	400,000		400,000
Mortgage debt 1	—		8,438
Other 2	284		2,516
Total	615,284		618,954
Less: Unamortized discount 3	(3,227)		(3,720)
Less: Unamortized deferred issuance costs 3, 4	(8,559)		(9,853)
Total, net	603,498		605,381
Less: Current portion	(41)		(4,129)
Long-term debt	$	603,457	$	601,252

_______________________

1     The mortgage debt related to the corporate office building and related other assets acquired in connection with the Lonestar Acquisition for which assets were held as collateral for such debt. As of December 31, 2021, these assets met the held for sale criteria and were classified as Assets held for sale on the condensed consolidated balance sheets. In July 2022, the mortgage debt was fully repaid in connection with the sale of the corporate office building. See Note 3 for additional information on the sale.

2     Other debt of $2.2 million was extinguished during the nine months ended September 30, 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)

9 Months Ended

Sep. 30, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Components of Selected Balance Sheet Accounts

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

	September 30, 2022		December 31, 2021
Prepaid and other current assets:
Inventories 1	$	10,504	$	10,305
Prepaid expenses 2	2,545		10,693
	$	13,049	$	20,998
Other assets:
Deferred issuance costs of the Credit Facility, net of amortization	$	3,603	$	3,308
Right-of-use assets – operating leases	1,083		1,671
Other	—		38
	$	4,686	$	5,017
Accounts payable and accrued liabilities:
Trade accounts payable	$	31,135	$	32,452
Drilling and other lease operating costs	81,225		35,045
Revenue and royalties payable	110,867		95,521
Production, ad valorem and other taxes	15,949		7,905
Derivative settlements to counterparties	5,991		6,117
Compensation and benefits	6,848		13,942
Interest	5,341		15,321
Environmental remediation liability 3	1,519		2,287
Current operating lease obligations	876		914
Other	4,613		4,877
	$	264,364	$	214,381
Other non-current liabilities:
Asset retirement obligations	$	8,691	$	8,413
Non-current operating lease obligations	332		975
Postretirement benefit plan obligations	907		970
	$	9,930	$	10,358

_______________________

1    Includes tubular inventory and well materials of $9.9 million and $9.5 million and crude oil volumes in storage of $0.6 million and $0.8 million as of September 30, 2022 and December 31, 2021, respectively.

2 The balances as of September 30, 2022 and December 31, 2021 include $0.8 million and $9.6 million, respectively, for the prepayment of drilling and completion materials and services.

3 The balance as of September 30, 2022 and December 31, 2021 represents estimated costs associated with remediation activities for certain wells and tanks acquired as part of the Lonestar Acquisition; the remediation will be substantially complete in the fourth quarter of 2022.

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2022

Fair Value Disclosures [Abstract]

Schedule of Assets and Liabilities Measured at Fair Value on Recurring Basis

The following tables summarize the valuation of those assets and (liabilities) as of the dates presented:

	As of September 30, 2022
	Level 1		Level 2		Level 3		Total
Financial assets:
Commodity derivative assets – current	$	—	$	30,725	$	—	$	30,725
Commodity derivative assets – non-current	—		6,176		—		6,176
Total financial assets	$	—	$	36,901	$	—	$	36,901
Financial liabilities:
Interest rate swap liabilities – current	$	—	$	—	$	—	$	—
Commodity derivative liabilities – current	—		(75,327)		—		(75,327)
Commodity derivative liabilities – non-current	—		(12,748)		—		(12,748)
Total financial liabilities	$	—	$	(88,075)	$	—	$	(88,075)

	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)

9 Months Ended

Sep. 30, 2022

Commitments and Contingencies Disclosure [Abstract]

Supply Commitment

The following table provides details on these contractual arrangements as of September 30, 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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Shareholders' Equity (Tables)

9 Months Ended

Sep. 30, 2022

Equity [Abstract]

Schedule of Change in Ownership Interest

The following table summarizes changes in the ownership interest in consolidated subsidiaries during the period:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Net income attributable to common shareholders	$	106,236	$	17,387	$	167,435	$	6,860
Transfers from the noncontrolling interest, net 1	7,121		N/A		13,619		N/A
Change from net income attributable to common shareholders and net transfers to Noncontrolling interest	$	113,357	$	17,387	$	181,054	$	6,860

_____________________________________________

1     The three and nine months ended September 30, 2022 includes a net transfer of $7.1 million and $13.6 million, respectively, from Noncontrolling interest for share repurchases and common stock issuances related to employees’ share-based compensation with a corresponding adjustment to Paid-in capital. This equity adjustment had no impact on earnings other than a resulting increase to the noncontrolling interest proportionate share of net income and a corresponding decrease to the proportionate share of net income attributable to common shareholders.

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Share-Based Compensation and Other Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2022

Share-Based Payment Arrangement [Abstract]

Schedule of Restricted Stock Unit Activity

The table below summarizes activity for the nine months ended September 30, 2022 with respect to awarded RSUs:

	Time-Vested Restricted Stock Units	Weighted-Average Grant Date Fair Value
Balance at January 1, 2022	230,517	$	9.20
Granted	49,314	$	35.07
Vested	(111,479)	$	10.02
Forfeited	(16,101)	$	12.12
Balance at September 30, 2022	152,251	$	17.50

The table below summarizes activity for the nine months ended September 30, 2022 with respect to awarded PRSUs:

	Performance Restricted Stock Units	Weighted-Average Grant Date Fair Value
Balance at January 1, 2022	345,069	$	16.20
Granted	180,217	$	47.77
Vested	(2,688)	$	18.24
Forfeited	(11,516)	$	23.31
Balance at September 30, 2022	511,082	$	27.16

Schedule of Valuation Assumptions

The ranges for the assumptions used in the Monte Carlo model for the PRSUs granted during 2022, 2021, 2020 and 2019 are presented as follows:

	2022		2021 1		2020 1		2019
Expected volatility	134.98% to 138.75%		131.74% to 134.74%		101.32% to 117.71%		49.9	%
Dividend yield	0.0	%	0.0	%	0.0	%	0.0	%
Risk-free interest rate	2.59	%	0.22% to 0.29%		0.18% to 0.51%		1.66	%
Performance period	2022-2024		2021-2023		2020-2022		2020-2022

_______________________

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

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2022

Earnings Per Share [Abstract]

Schedule of Components of Calculation of Basic and Diluted Earnings Per Share

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Numerator:
Net income	$	227,585	$	43,063	$	354,964	$	30,638
Net income attributable to Noncontrolling interest	(121,349)		(25,676)		(187,529)		(23,778)
Net income attributable to common shareholders for Basic EPS	106,236		17,387		167,435		6,860
Adjustment for assumed conversions and elimination of Noncontrolling interest net income	785		25,676		1,154		23,778
Net income attributable to common shareholders for Diluted EPS	$	107,021	$	43,063	$	168,589	$	30,638
Denominator:
Weighted average shares outstanding used in Basic EPS	19,741		15,319		20,573		15,298
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, 2	—		—		—		—
RSUs and PRSUs	600		394		582		371
Weighted average shares outstanding used in Diluted EPS 2	20,341		15,713		21,155		15,669

_______________________

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 and nine months ended September 30, 2022, approximately 22.5 million potentially dilutive Common Units (and the associated 22.5 million Class B Common Stock) had the effect of being anti-dilutive and were excluded from the calculation of earnings per share. For the three and nine months ended September 30, 2021, approximately 22.5 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).

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Organization and Description of Business (Details) $ / shares in Units, $ in Millions		9 Months Ended
	Jan. 15, 2021 USD ($)	Sep. 30, 2022 segment $ / shares	Dec. 31, 2021 $ / shares	Oct. 31, 2021 $ / shares	Oct. 05, 2021 $ / shares
Juniper Transaction Table [Line Items]
Number of reportable segments | segment		1
Number of operating segments | segment		1
Common stock, par value (in dollars per share) | $ / shares					$ 0.01
Common Class A
Juniper Transaction Table [Line Items]
Common stock, par value (in dollars per share) | $ / shares		$ 0.01	$ 0.01	$ 0.01
Juniper Transaction
Juniper Transaction Table [Line Items]
Proceeds from contributed capital | $	$ 150

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Basis of Presentation and Significant Accounting Policies (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2022 USD ($) shares	Dec. 31, 2021 USD ($) shares	Sep. 30, 2021 USD ($)	Dec. 31, 2020 USD ($)
Noncontrolling Interest [Line Items]
Common unit conversion ratio	1
Cash, cash equivalents and restricted cash	$ 20,344	$ 23,681	$ 446,769	$ 13,020
Cash			35,300
Restricted cash, current			15,400
Restricted cash, non current			$ 396,100
Ranger Oil Corporation
Noncontrolling Interest [Line Items]
Ownership percentage	46.30%	48.30%
Ranger Oil Corporation | GP LLC
Noncontrolling Interest [Line Items]
Ownership percentage	100.00%
Ranger Oil Corporation | Common Units
Noncontrolling Interest [Line Items]
Investment owned (in shares) | shares	19,422,156	21,090,259
Juniper Transaction
Noncontrolling Interest [Line Items]
Ownership percentage by noncontrolling owners	53.70%	51.70%
Juniper Transaction | Common Units
Noncontrolling Interest [Line Items]
Investment owned (in shares) | shares	22,548,998	22,548,998

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Acquisitions and Dispositions - Narrative (Details) $ / shares in Units, $ in Millions			3 Months Ended
	Jul. 22, 2022 USD ($)	Oct. 05, 2021 USD ($) $ / shares	Jun. 30, 2022 USD ($)	Sep. 30, 2022 USD ($)
Business Acquisition [Line Items]
Gross proceeds from sale of property	$ 11.0
Costs from sale of property	0.8
Mortgage debt and accrued interest from sale of property	8.4
Proceeds from sale of property, net	$ 1.8
Lonestar
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				$ 2.0
Eagle Ford Shale
Business Acquisition [Line Items]
Adjusted purchase price			$ 129.8

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Acquisitions and Dispositions - Schedule of Pro Forma Information (Details) - Lonestar - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2021
Business Acquisition [Line Items]
Total revenues	$ 200,995	$ 500,087
Net income (loss) attributable to common shareholders	$ 12,531	$ (19,174)

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Revenue Recognition (Details) - USD ($) $ in Thousands	Sep. 30, 2022	Dec. 31, 2021
Receivables [Abstract]
Customers	$ 123,493	$ 96,195
Joint interest partners	22,964	21,755
Derivative settlements from counterparties	1,619	1,037
Other	99	18
Total	148,175	119,005
Less: Allowance for credit losses	(352)	(411)
Accounts receivable, net of allowance for credit losses	$ 147,823	$ 118,594

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Derivative Instruments - Commodity Derivative Positions (Details)	Sep. 30, 2022 bbl $ / bbl
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 | Fourth Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	20,245
Derivative, Average Floor Price	64.56
Derivative, Average Cap Price	88.78
Crude oil | 2-Way Collars | First Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	12,917
Derivative, Average Floor Price	63.23
Derivative, Average Cap Price	79.67
Crude oil | 2-Way Collars | Second Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	11,126
Derivative, Average Floor Price	61.48
Derivative, Average Cap Price	74.31
Crude oil | 2-Way Collars | Third Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	8,152
Derivative, Average Floor Price	72.00
Derivative, Average Cap Price	89.91
Crude oil | 2-Way Collars | Fourth Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	4,891
Derivative, Average Floor Price	70.00
Derivative, Average Cap Price	86.04
Crude oil | 2-Way Collars | First Quarter 2024
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl
Derivative, Average Floor Price
Derivative, Average Cap Price
Crude oil | CMA Roll Basis Swap | Fourth Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	3,804
Derivative, CMA Roll Basis Swap, Price	1.751
Crude oil | CMA Roll Basis Swap | First Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl
Derivative, CMA Roll Basis Swap, Price
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 | Swap | Third Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl
Derivative, Swap Type, Average Fixed Price
Natural Gas | 2-Way Collars | Fourth Quarter 2022
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	14,511
Derivative, Average Floor Price	2.854
Derivative, Average Cap Price	3.791
Natural Gas | 2-Way Collars | First Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl	14,617
Derivative, Average Floor Price	6.561
Derivative, Average Cap Price	12.334
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 | 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 | First Quarter 2023
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl
Derivative, Swap Type, Average Fixed Price
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
Natural gas liquids | Swap | Second Quarter 2024
Derivative Instruments Related to Oil and Gas Production [Line Items]
Derivative, Nonmonetary Notional Amount | bbl
Derivative, Swap Type, Average Fixed Price

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Derivative Instruments - Narrative (Details) $ in Thousands	Sep. 30, 2022 USD ($) customer	May 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative liabilities	$ 88,075		$ 74,187
Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative, notional amount		$ 300,000
Derivative, average fixed interest rate	1.36%
Commodity contracts
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative liabilities	$ 51,200
Number of derivative counterparties | customer	7

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Derivative Instruments - Impact of Derivative Activities on Condensed Consolidated Statements of Income and Cash Flows (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Interest Rate Swap gains (losses) recognized in the condensed consolidated statements of operations	$ 0	$ (84)	$ 64	$ (48)
Commodity gains (losses) recognized in the condensed consolidated statements of operations	63,756	(21,000)	(149,137)	(119,631)
Derivative gains (losses)	63,756	(21,084)	(149,073)	(119,679)
Interest rate cash settlements recognized in the condensed consolidated statements of cash flows	0	(973)	(1,415)	(2,851)
Commodity cash settlements and premiums paid recognized in the condensed consolidated statements of cash flows	(55,302)	(21,265)	(157,809)	(43,190)
Cash settlements and premiums paid, net	$ (55,302)	$ (22,238)	$ (159,224)	$ (46,041)

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Derivative Instruments - Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Sep. 30, 2022	Dec. 31, 2021
Derivatives, Fair Value [Line Items]
Derivative assets	$ 30,725	$ 11,478
Derivative liabilities	75,327	50,372
Derivative assets	6,176	2,092
Derivative liabilities	12,748	23,815
Derivative assets	36,901	13,570
Derivative liabilities	88,075	74,187
Interest Rate Swap
Derivatives, Fair Value [Line Items]
Derivative assets	0	0
Derivative liabilities	0	1,480
Derivative assets	0	0
Derivative liabilities	0	0
Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative assets	30,725	11,478
Derivative liabilities	75,327	48,892
Derivative assets	6,176	2,092
Derivative liabilities	12,748	$ 23,815
Derivative liabilities	$ 51,200

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Property and Equipment, Net - Summary of Property and Equipment (Details) - USD ($) $ in Thousands	Sep. 30, 2022	Dec. 31, 2021
Oil and gas properties (full cost accounting method):
Proved	$ 2,828,400	$ 2,327,686
Unproved	55,429	57,900
Total oil and gas properties	2,883,829	2,385,586
Other property and equipment	32,156	31,055
Total properties and equipment	2,915,985	2,416,641
Accumulated depreciation, depletion, amortization and impairments	(1,204,618)	(1,033,293)
Total property and equipment, net	1,711,367	$ 1,383,348
Assets held for sale	$ 1,200

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Property and Equipment, Net - Narrative (Details)	3 Months Ended					6 Months Ended		9 Months Ended
	Sep. 30, 2022 USD ($) $ / bbl	Sep. 30, 2022 USD ($) $ / bbl $ / bbl	Sep. 30, 2022 USD ($) $ / Mcf $ / bbl	Sep. 30, 2021 USD ($) $ / bbl	Mar. 31, 2021 USD ($)	Jun. 30, 2022 $ / bbl	Jun. 30, 2022 $ / Mcf	Sep. 30, 2022 USD ($) $ / bbl	Dec. 31, 2021 USD ($)	Sep. 30, 2021 USD ($) $ / bbl
Property, Plant and Equipment [Line Items]
Unproved oil and gas property excluded	$ 55,400,000	$ 55,400,000	$ 55,400,000					$ 55,400,000	$ 57,900,000
Undeveloped leasehold costs transferred								8,700,000		$ 13,800,000
Capitalized costs, proved properties	$ 4,000,000	$ 4,000,000	$ 4,000,000	$ 2,800,000				4,000,000		2,800,000
Interest costs capitalized								$ (3,300,000)		$ (2,600,000)
Amortization expense per physical unit of production | $ / bbl	15.84	15.84	15.84	12.96				15.84		12.96
Impairments of oil and gas properties	$ 0			$ 0				$ 0		$ 1,811,000
West Texas Intermediate
Property, Plant and Equipment [Line Items]
Oil price per barrel (in dollars per barrel)		77	6			120	9
Impairments of oil and gas properties	$ 0				$ 1,800,000			$ 0	$ 0

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Long-Term Debt - Summary of Long-Term Debt (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2021	Aug. 10, 2021
Debt Instrument [Line Items]
Long-term debt, gross	$ 615,284		$ 615,284		$ 618,954
Less: Unamortized discount	(3,227)		(3,227)		(3,720)
Less: Unamortized deferred issuance costs	(8,559)		(8,559)		(9,853)
Total, net	603,498		603,498		605,381
Less: Current portion	(41)		(41)		(4,129)
Long-term debt, net	603,457		603,457		601,252
Gain (loss) on extinguishment of debt	0	$ 0	2,157	$ (1,231)
Line of Credit
Debt Instrument [Line Items]
Long-term debt, gross	215,000		215,000		208,000
Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross	400,000		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	0		0		8,438
Other
Debt Instrument [Line Items]
Long-term debt, gross	$ 284		284		$ 2,516
Gain (loss) on extinguishment of debt			$ 2,200

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Long-Term Debt - Narrative (Details) - USD ($)	9 Months Ended
	Sep. 30, 2022	Sep. 27, 2022	Sep. 26, 2022	Jun. 01, 2022	May 31, 2022	Sep. 30, 2021	Aug. 10, 2021
Debt Disclosure [Line Items]
Current ratio	1.00
Debt to EBITD ratio, maximum	3.50
Debt issuance costs, line of credit arrangements, gross	$ 800,000					$ 700,000
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	5.63%
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	500,000,000	$ 500,000,000	$ 400,000,000
Outstanding borrowings	215,000,000
Letters of credit outstanding	700,000
Remaining borrowing capacity	284,300,000
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	$ 950,000,000	$ 950,000,000		$ 875,000,000	$ 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		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income tax expense (benefit)	$ (2,100,000)	$ (500,000)	$ (3,200,000)	$ (400,000)
Change in deferred tax assets valuation allowance, percent			0.90%	1.30%
Net deferred tax liability	5,000,000		$ 5,000,000
Unrecognized tax benefits	$ 0		0		$ 0
Income tax examination, penalties and interest expense			$ 0	$ 0

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Supplemental Balance Sheet Detail (Details) - USD ($) $ in Thousands	Sep. 30, 2022	Dec. 31, 2021
Prepaid and other current assets:
Inventories	$ 10,504	$ 10,305
Prepaid expenses	2,545	10,693
Prepaid and other current assets	13,049	20,998
Other assets:
Deferred issuance costs of the Credit Facility, net of amortization	3,603	3,308
Right-of-use assets – operating leases	1,083	1,671
Other	0	38
Other assets	4,686	5,017
Accounts payable and accrued liabilities:
Trade accounts payable	31,135	32,452
Drilling and other lease operating costs	81,225	35,045
Revenue and royalties payable	110,867	95,521
Production, ad valorem and other taxes	15,949	7,905
Derivative settlements to counterparties	5,991	6,117
Compensation and benefits	6,848	13,942
Interest	5,341	15,321
Environmental remediation liability	1,519	2,287
Current operating lease obligations	876	914
Other	4,613	4,877
Accounts payable and accrued liabilities	264,364	214,381
Other non-current liabilities:
Asset retirement obligations	8,691	8,413
Non-current operating lease obligations	332	975
Postretirement benefit plan obligations	907	970
Other non-current liabilities	9,930	10,358
Tubular inventory and well materials	9,900	9,500
Capitalized costs - crude oil in storage	600	800
Drilling and completion prepayment	$ 800	$ 9,600

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Fair Value Measurements - Narrative (Details) - USD ($) $ in Thousands	Sep. 30, 2022	Dec. 31, 2021	Aug. 10, 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, gross	$ 615,284	$ 618,954
Long-term debt, fair value	548,700	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	Sep. 30, 2022	Dec. 31, 2021
Financial assets:
Commodity derivative assets – current	$ 30,725	$ 11,478
Commodity derivative assets – non-current	6,176	2,092
Derivative assets	36,901	13,570
Financial liabilities:
Derivative liabilities – current	(75,327)	(50,372)
Derivative liabilities, noncurrent	(12,748)	(23,815)
Derivative liabilities	(88,075)	(74,187)
Fair Value, Measurements, Recurring
Financial assets:
Derivative assets	36,901	13,570
Financial liabilities:
Derivative liabilities	(88,075)	(74,187)
Commodity contracts
Financial assets:
Commodity derivative assets – current	30,725	11,478
Commodity derivative assets – non-current	6,176	2,092
Financial liabilities:
Derivative liabilities – current	(75,327)	(48,892)
Derivative liabilities, noncurrent	(12,748)	(23,815)
Derivative liabilities	(51,200)
Commodity contracts | Fair Value, Measurements, Recurring
Financial assets:
Commodity derivative assets – current	30,725	11,478
Commodity derivative assets – non-current	6,176	2,092
Financial liabilities:
Derivative liabilities – current	(75,327)	(48,892)
Derivative liabilities, noncurrent	(12,748)	(23,815)
Interest Rate Swap
Financial assets:
Commodity derivative assets – current	0	0
Commodity derivative assets – non-current	0	0
Financial liabilities:
Derivative liabilities – current	0	(1,480)
Derivative liabilities, noncurrent	0	0
Interest Rate Swap | Fair Value, Measurements, Recurring
Financial liabilities:
Derivative liabilities – current	0	(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	36,901	13,570
Financial liabilities:
Derivative liabilities	(88,075)	(74,187)
Level 2 | Commodity contracts | Fair Value, Measurements, Recurring
Financial assets:
Commodity derivative assets – current	30,725	11,478
Commodity derivative assets – non-current	6,176	2,092
Financial liabilities:
Derivative liabilities – current	(75,327)	(48,892)
Derivative liabilities, noncurrent	(12,748)	(23,815)
Level 2 | Interest Rate Swap | Fair Value, Measurements, Recurring
Financial liabilities:
Derivative liabilities – current	0	(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		9 Months Ended
	Sep. 30, 2022 USD ($) rig	Sep. 30, 2021 USD ($)	Sep. 30, 2022 USD ($) rig bbl	Sep. 30, 2021 USD ($)	Dec. 31, 2021 USD ($)
Commitments and Contingencies Disclosure [Line Items]
Drilling rig, contract period			2 years
Unrecorded unconditional purchase obligation, change of amount as result of variable components (in dollars per barrel)	$ 90		$ 90
Unrecorded unconditional purchase obligation, purchases	11,100,000	$ 9,200,000	31,900,000	$ 26,300,000
Estimated litigation liability, current	100,000		100,000		$ 100,000
Asset retirement obligation	8,700,000		8,700,000		8,400,000
Environmental remediation liability	$ 1,519,000		$ 1,519,000		$ 2,287,000
Drilling Rig With Two Year Contract
Commitments and Contingencies Disclosure [Line Items]
Drilling rigs | rig	1		1
Drilling Rig With Contractual Term
Commitments and Contingencies Disclosure [Line Items]
Drilling rigs | rig	2		2
Crude Oil Gathering And Transportation Services
Commitments and Contingencies Disclosure [Line Items]
Purchase obligation, remainder of 2022	$ 3,500,000		$ 3,500,000
Purchase obligation, year 2023	13,900,000		13,900,000
Purchase obligation, year 2024	13,900,000		13,900,000
Purchase obligation, year 2025	13,900,000		13,900,000
Purchase obligation, year 2026	7,800,000		7,800,000
Purchase obligation, year 2027	3,800,000		3,800,000
Purchase obligation, year 2028	3,800,000		3,800,000
Purchase obligation, year 2029	3,800,000		3,800,000
Purchase obligation, year 2030	3,800,000		3,800,000
Purchase obligation, year 2031	$ 600,000		$ 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

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Commitments and Contingencies - Purchase Commitment, Excluding Long-term Commitment (Details)	9 Months Ended
	Sep. 30, 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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Shareholders' Equity - Narrative (Details)		3 Months Ended	9 Months Ended
	Oct. 06, 2021 shares	Sep. 30, 2022 USD ($) class $ / shares shares	Sep. 30, 2022 USD ($) class $ / shares shares	Jul. 07, 2022 USD ($)	Jun. 30, 2022 shares	Apr. 13, 2022 USD ($)	Mar. 31, 2022 shares	Dec. 31, 2021 $ / shares shares	Oct. 31, 2021 $ / shares	Oct. 05, 2021 $ / shares shares	Sep. 30, 2021 shares	Jun. 30, 2021 shares	Mar. 31, 2021 shares	Dec. 31, 2020 shares
Subsidiary, Sale of Stock [Line Items]
Capital stock, authorized (in shares)	145,000,000									115,000,000
Common stock, authorized (in shares)										110,000,000
Common stock, par value (in dollars per share) | $ / shares										$ 0.01
Preferred stock, shares authorized (in shares)		5,000,000	5,000,000
Preferred stock, par value (in dollars per share) | $ / shares		$ 0.01	$ 0.01
Preferred stock, shares outstanding (in shares)		0	0
Number of common stock classes | class		2	2
Preferred stock, issued (in shares)		0	0
Common stock dividend paid | $		$ 1,543,000
Treasury stock, acquired (in shares)		1,074,960	1,755,836
Treasury stock, acquired | $		$ 35,000,000	$ 60,000,000
Treasury stock, acquired, average cost per share (in dollars per share) | $ / shares		$ 32.58	$ 34.19
Remaining authorized repurchase amount | $		$ 80,000,000	$ 80,000,000
Limited Partner
Subsidiary, Sale of Stock [Line Items]
Transfers (to) from the noncontrolling interest, net | $		$ 7,121,000	$ 13,619,000
Common Stock
Subsidiary, Sale of Stock [Line Items]
Common stock, outstanding (in shares)											15,331,000	15,312,000	15,310,000	15,200,000
Preferred Class A
Subsidiary, Sale of Stock [Line Items]
Preferred stock, shares authorized (in shares)										5,000,000
Preferred stock, par value (in dollars per share) | $ / shares										$ 0.01
Preferred stock, shares outstanding (in shares)	225,489.98
Common Class B
Subsidiary, Sale of Stock [Line Items]
Common stock, authorized (in shares)	30,000,000	30,000,000	30,000,000					30,000,000
Common stock, par value (in dollars per share) | $ / shares		$ 0.01	$ 0.01					$ 0.01	$ 0.01
Common stock, par value, liquidation (in dollars per share) | $ / shares		$ 0.01	$ 0.01
Common stock, issued (in shares)		22,548,998	22,548,998					22,548,998
Common stock, outstanding (in shares)		22,548,998	22,548,998					22,548,998
Common Class B | Common Stock
Subsidiary, Sale of Stock [Line Items]
Stock issued during period (in shares)	22,548,998
Common stock, outstanding (in shares)		22,549,000	22,549,000		22,549,000		22,549,000	22,549,000
Common Class A
Subsidiary, Sale of Stock [Line Items]
Common stock, authorized (in shares)		110,000,000	110,000,000					110,000,000
Common stock, par value (in dollars per share) | $ / shares		$ 0.01	$ 0.01					$ 0.01	$ 0.01
Common stock, issued (in shares)		19,422,156	19,422,156					21,090,259
Common stock, outstanding (in shares)		19,422,156	19,422,156					21,090,259
Cash dividend declared (in dollars per share) | $ / shares		$ 0.075
Common stock dividend paid | $		$ 3,200,000
Stock repurchase program, authorized amount | $				$ 140,000,000		$ 100,000,000
Common Class A | Common Stock
Subsidiary, Sale of Stock [Line Items]
Common stock, outstanding (in shares)		19,422,000	19,422,000		20,483,000		21,146,000	21,090,000

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Shareholders' Equity - Schedule of Change in Ownership Interest (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Subsidiary, Sale of Stock [Line Items]
Net income attributable to common shareholders	$ 106,236	$ 17,387	$ 167,435	$ 6,860
Limited Partner
Subsidiary, Sale of Stock [Line Items]
Net income attributable to common shareholders	106,236	17,387	167,435	6,860
Transfers (to) from the noncontrolling interest, net	7,121		13,619
Change from net income attributable to common shareholders and net transfers to Noncontrolling interest	$ 113,357	$ 17,387	$ 181,054	$ 6,860

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Share-Based Compensation and Other Benefit Plans - Narrative (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based compensation	$ 1,300	$ 1,000	$ 4,327	$ 4,179
Defined contribution plan, cost	100	200	500	500
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	$ 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)	811,573		811,573
Award vesting period			3 years
Cost not yet recognized, amount	$ 2,000		$ 2,000
Cost not yet recognized, period for recognition			1 year 10 months 20 days
Performance Shares
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Number of shares authorized (in shares)	664,414		664,414
Award vesting period			3 years
Cost not yet recognized, amount	$ 9,200		$ 9,200
Cost not yet recognized, period for recognition			1 year 11 months 4 days
Performance Shares | Minimum
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Award vesting period			1 year
Shares expected to vest, percentage			0.00%
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		4,424,600

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Share-Based Compensation and Other Benefit Plans - Summary of Restricted Stock Unit Activity (Details)	9 Months Ended
	Sep. 30, 2022 $ / shares shares
Restricted Stock Units (RSUs)
Time-Vested Restricted Stock Units
Balance at beginning of period (in shares) | shares	230,517
Granted (in shares) | shares	49,314
Vested (in shares) | shares	(111,479)
Forfeited (in shares) | shares	(16,101)
Balance at end of period (in shares) | shares	152,251
Weighted-Average Grant Date Fair Value
Balance at beginning of period (in dollars per share) | $ / shares	$ 9.20
Granted (in dollars per share) | $ / shares	35.07
Vested (in dollars per share) | $ / shares	10.02
Forfeited (in shares) | $ / shares	12.12
Balance at end of period (in shares) | $ / shares	$ 17.50
Performance Shares
Time-Vested Restricted Stock Units
Balance at beginning of period (in shares) | shares	345,069
Granted (in shares) | shares	180,217
Vested (in shares) | shares	(2,688)
Forfeited (in shares) | shares	(11,516)
Balance at end of period (in shares) | shares	511,082
Weighted-Average Grant Date Fair Value
Balance at beginning of period (in dollars per share) | $ / shares	$ 16.20
Granted (in dollars per share) | $ / shares	47.77
Vested (in dollars per share) | $ / shares	18.24
Forfeited (in shares) | $ / shares	23.31
Balance at end of period (in shares) | $ / shares	$ 27.16

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Share-Based Compensation and Other Benefit Plans - Schedule of Valuation Assumptions (Details) - Performance Shares	9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2019
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expected volatility				49.90%
Dividend yield	0.00%	0.00%	0.00%	0.00%
Risk-free interest rate	2.59%			1.66%
Risk-free interest rate, minimum		0.22%	0.18%
Risk-free interest rate, maximum		0.29%	0.51%
Minimum
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expected volatility	134.98%	131.74%	101.32%
Maximum
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Expected volatility	138.75%	134.74%	117.71%

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Earnings Per Share - Narrative (Details) - $ / shares	Sep. 30, 2022	Dec. 31, 2021	Oct. 31, 2021	Oct. 05, 2021
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Common stock, par value (in dollars per share)				$ 0.01
Preferred stock, par value (in dollars per share)	$ 0.01
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	$ 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						9 Months Ended
	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Sep. 30, 2022	Sep. 30, 2021
Numerator:
Net income	$ 227,585	$ 148,040	$ (20,661)	$ 43,063	$ 7,596	$ (20,021)	$ 354,964	$ 30,638
Net income attributable to Noncontrolling interest	(121,349)			(25,676)			(187,529)	(23,778)
Net income attributable to common shareholders for Basic EPS	106,236			17,387			167,435	6,860
Adjustment for assumed conversions and elimination of Noncontrolling interest net income	785			25,676			1,154	23,778
Net income attributable to common shareholders for Diluted EPS	$ 107,021			$ 43,063			$ 168,589	$ 30,638
Denominator:
Weighted-average shares – basic (in shares)	19,741			15,319			20,573	15,298
Effect of dilutive securities:
Common Units and Series A Preferred Stock that are exchangeable for common shares (in shares)	0			0			0	0
RSUs and PRSUs (in shares)	600			394			582	371
Weighted average shares outstanding used in Diluted EPS (in shares)	20,341			15,713			21,155	15,669
Antidilutive securities excluded from computation of earnings per share (in shares)				22,500				22,500
Common Units
Effect of dilutive securities:
Antidilutive securities excluded from computation of earnings per share (in shares)	22,500			22,500			22,500	22,500
Common Class B
Effect of dilutive securities:
Antidilutive securities excluded from computation of earnings per share (in shares)	22,500						22,500
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) - Common Class A - $ / shares		3 Months Ended
	Nov. 02, 2022	Sep. 30, 2022
Subsequent Event [Line Items]
Cash dividend declared (in dollars per share)		$ 0.075
Subsequent Event
Subsequent Event [Line Items]
Cash dividend declared (in dollars per share)	$ 0.075