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, 20212022
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
rocc-20220930_g1.jpg
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, SUITEPark Ten Place, Suite 500
HOUSTON,Houston, TX 77084
(Address of principal executive offices) (Zip Code)
(713) 722-6500
(Registrant’s telephone number, including area code)
Penn Virginia Corporation
(Former names or former address, if changed since last report)
Securities registered pursuant to Section 12(b) of the ActAct:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Class A Common Stock, $0.01 Par ValueROCCThe 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 (“Exchange Act”) 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 Fileraccelerated filerAccelerated Filerfiler
Non-accelerated FilerfilerSmaller Reporting Companyreporting company
Emerging Growth Companygrowth 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 29, 2021,28, 2022, there were 43,637,25141,669,837 shares of common stock outstanding, including 21,088,25319,120,839 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, 20212022
 Table of Contents
Part I - Financial Information
Item Page
1.Financial Statements - unaudited
Condensed Consolidated Statements of Operations
Condensed Consolidated Statements of Comprehensive Income (Loss)
Condensed Consolidated Balance Sheets
Condensed Consolidated Statements of Cash Flows
Condensed Consolidated Statements of Equity
Notes to Condensed Consolidated Financial Statements:
1. Nature of Operations
 2. Basis of Presentation
3. Juniper Transactions
4. Revenue Recognition
5. Derivative Instruments
 6. Property and Equipment
 7. Long-Term Debt
8. Income Taxes
 9. Supplemental Balance Sheet Detail
 10. Fair Value Measurements
 11. Commitments and Contingencies
 12. Share-Based Compensation and Other Benefit Plans
13. Earnings per Share
14. Subsequent Events
Forward-Looking Statements
2.Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview and Executive Summary
Results of Operations
Liquidity and Capital Resources
Off Balance Sheet Arrangements
Critical Accounting Estimates
3.Quantitative and Qualitative Disclosures About Market Risk
4.Controls and Procedures
Part II - Other Information
1.Legal Proceedings
1A.Risk Factors
5.Other Information
6.Exhibits
Signatures
Page



Part I. FINANCIAL INFORMATION
Item 1. Financial Statements
RANGER OIL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS unauditedUNAUDITED
(in thousands, except per share data) 
Three Months Ended September 30,Nine Months Ended September 30,Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020 2022202120222021
Revenues and otherRevenues and otherRevenues and other
Crude oilCrude oil$127,995 $63,227 $326,222 $190,732 Crude oil$262,537 $127,995 $762,858 $326,222 
Natural gas liquidsNatural gas liquids7,165 2,824 15,115 6,295 Natural gas liquids18,669 7,165 54,227 15,115 
Natural gasNatural gas4,973 2,563 10,893 7,273 Natural gas22,899 4,973 56,063 10,893 
Other operating income, netOther operating income, net928 797 2,085 1,972 Other operating income, net985 928 2,888 2,085 
Total revenues and otherTotal revenues and other141,061 69,411 354,315 206,272 Total revenues and other305,090 141,061 876,036 354,315 
Operating expensesOperating expensesOperating expenses
Lease operatingLease operating10,647 8,275 29,200 27,901 Lease operating24,123 10,647 61,133 29,200 
Gathering, processing and transportationGathering, processing and transportation5,688 5,760 15,535 16,797 Gathering, processing and transportation9,794 5,688 27,472 15,535 
Production and ad valorem taxesProduction and ad valorem taxes7,534 4,368 19,768 13,152 Production and ad valorem taxes16,698 7,534 46,612 19,768 
General and administrativeGeneral and administrative10,932 8,585 31,094 23,801 General and administrative9,829 10,932 30,243 31,094 
Depreciation, depletion and amortizationDepreciation, depletion and amortization30,975 37,038 83,654 114,891 Depreciation, depletion and amortization66,204 30,975 171,387 83,654 
Impairments of oil and gas propertiesImpairments of oil and gas properties— 235,989 1,811 271,498 Impairments of oil and gas properties— — — 1,811 
Total operating expensesTotal operating expenses65,776 300,015 181,062 468,040 Total operating expenses126,648 65,776 336,847 181,062 
Operating income (loss)75,285 (230,604)173,253 (261,768)
Operating incomeOperating income178,442 75,285 539,189 173,253 
Other income (expense)Other income (expense)Other income (expense)
Interest expense, net of amounts capitalizedInterest expense, net of amounts capitalized(10,582)(7,497)(21,282)(24,213)Interest expense, net of amounts capitalized(13,160)(10,582)(34,895)(21,282)
Loss on extinguishment of debt— — (1,231)— 
Derivatives(21,084)(6,891)(119,679)109,879 
Gain (loss) on extinguishment of debtGain (loss) on extinguishment of debt— — 2,157 (1,231)
Derivative gains (losses)Derivative gains (losses)63,756 (21,084)(149,073)(119,679)
Other, netOther, net(7)21 (13)(42)Other, net599 (7)757 (13)
Income (loss) before income taxes43,612 (244,971)31,048 (176,144)
Income tax (expense) benefit(549)1,558 (410)1,110 
Net income (loss)43,063 (243,413)30,638 (175,034)
Income before income taxesIncome before income taxes229,637 43,612 358,135 31,048 
Income tax expenseIncome tax expense(2,052)(549)(3,171)(410)
Net incomeNet income227,585 43,063 354,964 30,638 
Net income attributable to Noncontrolling interestNet income attributable to Noncontrolling interest(25,676)— (23,778)— Net income attributable to Noncontrolling interest(121,349)(25,676)(187,529)(23,778)
Net income (loss) attributable to common shareholders$17,387 $(243,413)$6,860 $(175,034)
Net income (loss) per share:
Net income attributable to common shareholdersNet income attributable to common shareholders$106,236 $17,387 $167,435 $6,860 
Net income per share attributable to common shareholders:Net income per share attributable to common shareholders:
BasicBasic$1.13 $(16.03)$0.45 $(11.54)Basic$5.38 $1.13 $8.14 $0.45 
DilutedDiluted$1.11 $(16.03)$0.44 $(11.54)Diluted$5.26 $1.11 $7.97 $0.44 
Weighted average shares outstanding – basicWeighted average shares outstanding – basic15,319 15,183 15,298 15,168 Weighted average shares outstanding – basic19,741 15,319 20,573 15,298 
Weighted average shares outstanding – dilutedWeighted average shares outstanding – diluted15,713 15,183 15,669 15,168 Weighted average shares outstanding – diluted20,341 15,713 21,155 15,669 

See accompanying notes to condensed consolidated financial statements.

3


RANGER OIL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) unauditedUNAUDITED
(in thousands) 
 
 Three Months Ended September 30,Nine Months Ended September 30,
 2021202020212020
Net income (loss)$43,063 $(243,413)$30,638 $(175,034)
Other comprehensive income (loss):
Change in pension and postretirement obligations, net of tax(2)(4)
 (2)(4)
Comprehensive income (loss)43,064 (243,415)30,642 (175,038)
Net income attributable to Noncontrolling interest(25,676)— (23,778)— 
Other comprehensive income attributable to Noncontrolling interest(1)— (4)— 
Comprehensive income (loss) attributable to common shareholders$17,387 $(243,415)$6,860 $(175,038)
 Three Months Ended September 30,Nine Months Ended September 30,
 2022202120222021
Net income$227,585 $43,063 $354,964 $30,638 
Other comprehensive income:
Change in pension and postretirement obligations, net of tax— — 
Comprehensive income227,585 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 unauditedUNAUDITED
(in thousands, except share data)
September 30,December 31,
20212020 September 30, 2022December 31, 2021
AssetsAssets  Assets  
Current assetsCurrent assets  Current assets  
Cash and cash equivalentsCash and cash equivalents$35,258 $13,020 Cash and cash equivalents$20,344 $23,681 
Restricted cash - current15,439 — 
Accounts receivable, net of allowance for credit lossesAccounts receivable, net of allowance for credit losses87,773 45,849 Accounts receivable, net of allowance for credit losses147,823 118,594 
Derivative assetsDerivative assets4,909 75,506 Derivative assets30,725 11,478 
Prepaid and other current assetsPrepaid and other current assets8,532 19,045 Prepaid and other current assets13,049 20,998 
Assets held for saleAssets held for sale1,186 11,400 
Total current assetsTotal current assets151,911 153,420 Total current assets213,127 186,151 
Property and equipment, net (full cost method)864,878 723,549 
Restricted cash - non-current396,072 — 
Property and equipment, netProperty and equipment, net1,711,367 1,383,348 
Derivative assetsDerivative assets2,152 25,449 Derivative assets6,176 2,092 
Other assetsOther assets4,304 4,908 Other assets4,686 5,017 
Total assetsTotal assets$1,419,317 $907,326 Total assets$1,935,356 $1,576,608 
Liabilities and Shareholders’ Equity  
Liabilities and EquityLiabilities and Equity  
Current liabilitiesCurrent liabilities  Current liabilities  
Accounts payable and accrued liabilitiesAccounts payable and accrued liabilities152,330 63,089 Accounts payable and accrued liabilities$264,364 $214,381 
Derivative liabilitiesDerivative liabilities63,089 85,106 Derivative liabilities75,327 50,372 
Current portion of long-term debtCurrent portion of long-term debt7,500 — Current portion of long-term debt41 4,129 
Total current liabilitiesTotal current liabilities222,919 148,195 Total current liabilities339,732 268,882 
Deferred income taxesDeferred income taxes837 — Deferred income taxes4,957 2,793 
Derivative liabilitiesDerivative liabilities21,416 28,434 Derivative liabilities12,748 23,815 
Other non-current liabilitiesOther non-current liabilities8,227 8,362 Other non-current liabilities9,930 10,358 
Long-term debt, netLong-term debt, net739,328 509,497 Long-term debt, net603,457 601,252 
Commitments and contingencies (Note 11)Commitments and contingencies (Note 11)Commitments and contingencies (Note 11)
EquityEquity  Equity  
Preferred stock of $0.01 par value – 5,000,000 shares authorized; 225,489.98 and none issued at September 30, 2021 and December 31, 2020, respectively— 
Common stock of $0.01 par value – 110,000,000 shares authorized; 15,330,598 and 15,200,435 shares issued as of September 30, 2021 and December 31, 2020, respectively153 152 
Preferred stock of $0.01 par value – 5,000,000 shares authorized; none issued as of September 30, 2022 and December 31, 2021Preferred 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, respectivelyClass 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, respectively194 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, 2021Class 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
Paid-in capitalPaid-in capital156,950 203,463 Paid-in capital230,777 273,329 
Retained earningsRetained earnings16,214 9,354 Retained earnings215,475 49,583 
Accumulated other comprehensive lossAccumulated other comprehensive loss(130)(131)Accumulated other comprehensive loss(111)(111)
Ranger Oil shareholders’ equityRanger Oil shareholders’ equity173,189 212,838 Ranger Oil shareholders’ equity446,337 323,532 
Noncontrolling interestNoncontrolling interest253,401 — Noncontrolling interest518,195 345,976 
Total equityTotal equity426,590 212,838 Total equity964,532 669,508 
Total liabilities and shareholders’ equity$1,419,317 $907,326 
Total liabilities and equityTotal 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 unauditedUNAUDITED
(in thousands)
Nine Months Ended September 30, Nine Months Ended September 30,
20212020 20222021
Cash flows from operating activitiesCash flows from operating activities  Cash flows from operating activities  
Net income (loss)$30,638 $(175,034)
Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
Loss on extinguishment of debt1,231 — 
Net incomeNet income$354,964 $30,638 
Adjustments to reconcile net income to net cash provided by operating activities:Adjustments to reconcile net income to net cash provided by operating activities: 
(Gain) loss on extinguishment of debt(Gain) loss on extinguishment of debt(2,157)1,231 
Depreciation, depletion and amortizationDepreciation, depletion and amortization83,654 114,891 Depreciation, depletion and amortization171,387 83,654 
Impairments of oil and gas propertiesImpairments of oil and gas properties1,811 271,498 Impairments of oil and gas properties— 1,811 
Derivative contracts:Derivative contracts:Derivative contracts:
Net (gains) losses119,679 (109,879)
Cash settlements and premiums received (paid), net(46,041)65,295 
Deferred income tax expense (benefit)130 (31)
Gain on sales of assets, net(7)(14)
Net lossesNet losses149,073 119,679 
Cash settlements and premiums paid, netCash settlements and premiums paid, net(159,224)(46,041)
Deferred income tax expenseDeferred income tax expense2,164 130 
Non-cash interest expenseNon-cash interest expense1,742 3,336 Non-cash interest expense2,441 1,742 
Share-based compensationShare-based compensation4,179 2,582 Share-based compensation4,327 4,179 
Other, netOther, net20 23 Other, net(180)13 
Changes in operating assets and liabilities, netChanges in operating assets and liabilities, net7,048 17,056 Changes in operating assets and liabilities, net(33,613)7,671 
Net cash provided by operating activitiesNet cash provided by operating activities204,084 189,723 Net cash provided by operating activities489,182 204,707 
Cash flows from investing activitiesCash flows from investing activities  Cash flows from investing activities  
Capital expendituresCapital expenditures(307,766)(146,638)
Acquisitions of oil and gas propertiesAcquisitions of oil and gas properties(129,784)— 
Capital expenditures(146,638)(139,010)
Proceeds from sales of assets, netProceeds from sales of assets, net157 83 Proceeds from sales of assets, net10,900 157 
Net cash used in investing activitiesNet cash used in investing activities(146,481)(138,927)Net cash used in investing activities(426,650)(146,481)
Cash flows from financing activitiesCash flows from financing activities  Cash flows from financing activities  
Proceeds from credit facility borrowingsProceeds from credit facility borrowings20,000 51,000 Proceeds from credit facility borrowings483,000 20,000 
Repayments of credit facility borrowingsRepayments of credit facility borrowings(121,500)(89,000)Repayments of credit facility borrowings(476,000)(121,500)
Repayments of second lien facility(56,890)— 
Repayments of second lien term loanRepayments of second lien term loan— (56,890)
Proceeds from 9.25% Senior Notes due 2026, net of discountProceeds from 9.25% Senior Notes due 2026, net of discount396,072 — Proceeds from 9.25% Senior Notes due 2026, net of discount— 396,072 
Repayments of acquired debtRepayments of acquired debt(8,513)— 
Payments for share repurchasesPayments for share repurchases(59,414)— 
Distributions to Noncontrolling interestDistributions to Noncontrolling interest(1,691)— 
Dividends paidDividends paid(1,492)— 
Proceeds from redeemable common unitsProceeds from redeemable common units151,160 — Proceeds from redeemable common units— 151,160 
Proceeds from redeemable preferred stockProceeds from redeemable preferred stock— Proceeds from redeemable preferred stock— 
Transaction costs paid on behalf of Noncontrolling interestTransaction costs paid on behalf of Noncontrolling interest(5,543)— Transaction costs paid on behalf of Noncontrolling interest— (5,543)
Issue costs paid for Noncontrolling interest securities(3,758)— 
Issuance costs paid for Noncontrolling interest securitiesIssuance costs paid for Noncontrolling interest securities— (3,758)
Withholding taxes for share-based compensationWithholding taxes for share-based compensation(954)(623)
Debt issuance costs paidDebt issuance costs paid(3,397)(78)Debt issuance costs paid(805)(3,397)
Net cash provided by (used in) financing activities376,146 (38,078)
Net increase in cash, cash equivalents and restricted cash433,749 12,718 
Net cash (used in) provided by financing activitiesNet cash (used in) provided by financing activities(65,869)375,523 
Net increase (decrease) in cash, cash equivalents and restricted cashNet increase (decrease) in cash, cash equivalents and restricted cash(3,337)433,749 
Cash, cash equivalents and restricted cash – beginning of periodCash, cash equivalents and restricted cash – beginning of period13,020 7,798 Cash, cash equivalents and restricted cash – beginning of period23,681 13,020 
Cash, cash equivalents and restricted cash – end of periodCash, cash equivalents and restricted cash – end of period$446,769 $20,516 Cash, cash equivalents and restricted cash – end of period$20,344 $446,769 
Supplemental disclosures:Supplemental disclosures:  Supplemental disclosures:  
Cash paid for:Cash paid for:  Cash paid for:  
Interest, net of amounts capitalizedInterest, net of amounts capitalized$14,298 $20,959 Interest, net of amounts capitalized$42,678 $14,298 
Income taxes, net of (refunds)$360 $(2,471)
Income taxes refunds, netIncome taxes refunds, net$— $360 
Non-cash investing and financing activities:Non-cash investing and financing activities:Non-cash investing and financing activities:
Changes in property and equipment related to capital contributionsChanges in property and equipment related to capital contributions$(38,561)$— Changes in property and equipment related to capital contributions$— $(38,561)
Changes in asset retirement obligation related to capital contributions$14 $— 
Changes in accrued liabilities related to capital contributions$146 $— 
Changes in accrued liabilities related to capital expendituresChanges in accrued liabilities related to capital expenditures$30,303 $(30,579)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)
Preferred StockCommon StockPaid-in CapitalRetained Earnings/(Accumulated Deficit)Accumulated Other Comprehensive LossNoncontrolling interestTotal Equity
Balance as of December 31, 2020$— $152 $203,463 $9,354 $(131)$— $212,838 
Net loss— — — (13,572)— (6,449)(20,021)
Issuance of preferred stock— — — — — 
Issuance of Noncontrolling interest— — (50,068)— — 229,620 179,552 
All other changes 1
— 1,769 — 1,772 
Balance as of March 31, 2021$$153 $155,164 $(4,218)$(130)$223,172 $374,143 
Net income— — — 3,045 — 4,551 7,596 
All other changes 1
— — 922 — 924 
Balance as of June 30, 2021$$153 $156,086 $(1,173)$(129)$227,724 $382,663 
Net income— — — 17,387 — 25,676 43,063 
All other changes 1
— — 864 — (1)864 
Balance as of September 30, 2021$$153 $156,950 $16,214 $(130)$253,401 $426,590 
Shares
Class A Common Shares OutstandingClass B Common Shares OutstandingClass A Common StockClass B Common StockPaid-in CapitalRetained EarningsAccumulated Other Comprehensive LossNoncontrolling interestTotal Equity
Balance as of December 31, 202121,090 22,549 $729 $$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, net56 — — — 478 — — — 478 
Balance as of March 31, 202221,146 22,549 $729 $$273,807 $39,598 $(111)$335,300 $649,325 
Net income— — — — — 71,184 — 76,856 148,040 
Repurchase of Class A Common Stock(681)— (7)— (25,052)— — — (25,059)
Change in ownership, net— — — — 6,498 — — (6,498)— 
Common stock issued related to share-based compensation and other, net18 — (517)— 2,362 — — — 1,845 
Balance as of June 30, 202220,483 22,549 $205 $$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, net14 — — — 1,052 — — — 1,052 
Balance as of September 30, 202219,422 22,549 $194 $$230,777 $215,475 $(111)$518,195 $964,532 
Shares
Preferred Shares OutstandingCommon Shares OutstandingPreferred StockCommon StockPaid-in CapitalRetained Earnings/(Accumulated Deficit)Accumulated Other Comprehensive LossNoncontrolling interestTotal Equity
Balance as of December 31, 2020— 15,200 $— $152 $203,463 $9,354 $(131)$— $212,838 
Net loss— — — — — (13,572)— (6,449)(20,021)
Issuance of preferred stock225,490 — — — — — — 
Issuance of Noncontrolling interest— — — — (50,068)— — 229,620 179,552 
Common stock issued related to share-based compensation and other, net— 110 — 1,769 — 1,772 
Balance as of March 31, 2021225,490 15,310 $$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— — — 922 — 924 
Balance as of June 30, 2021225,490 15,312 $$153 $156,086 $(1,173)$(129)$227,724 $382,663 
Net income— — — — — 17,387 — 25,676 43,063 
Common stock issued related to share-based compensation and other, net— 19 — — 864 — (1)864 
Balance as of September 30, 2021$225,490 $15,331 $$153 $156,950 $16,214 $(130)$253,401 $426,590 
_______________________
1     Includes equity-classified share-based compensation of $4.2 million duringIn October 2021, the nine months ended September 30, 2021. DuringCompany effected a recapitalization, pursuant to which, among other things, the nine months ended September 30, 2021, 122,911 and 7,252 shares ofCompany’s common stock were issued in connection with the vesting of certain time-vested restricted stock units (“RSUs”)was renamed and performance restricted stock units (“PRSUs”), net of shares withheld for income taxes.

Common StockPaid-in CapitalRetained EarningsAccumulated Other Comprehensive LossTotal Equity
Balance as of December 31, 2019$151 $200,666 $319,987 $(59)$520,745 
Net income— — 163,094 — 163,094 
Cumulative effect of change in accounting principle 1
— — (76)— (76)
All other changes 2
556 — (1)556 
Balance as of March 31, 2020$152 $201,222 $483,005 $(60)$684,319 
Net loss— — (94,715)— (94,715)
All other changes 2
— 936 — (1)935 
Balance as of June 30, 2020$152 $202,158 $388,290 $(61)$590,539 
Net income— — (243,413)— (243,413)
All other changes 2
— 608 — (2)606 
Balance as of September 30, 2020$152 $202,766 $144,877 $(63)$347,732 
_______________________
1     Attributable to the adoption of Accounting Standards Update 2016–13, Measurement of Credit Losses on Financial Instruments,reclassified as of January 1, 2020.
2 Includes equity-classified share-based compensation of $2.6 million during the nine months ended September 30, 2020. During the nine months ended September 30, 2020, 45,435 and 19,402 shares ofClass A common stock, were issuedpar 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 connection with the vesting of certain RSUs and PRSUs, net of shares withheldnotes to condensed consolidated financial statements for income taxes.





further details.
See accompanying notes to condensed consolidated financial statements.

7


RANGER OIL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS unauditedUNAUDITED
For the Quarterly Period Ended September 30, 20212022
(in thousands, except per share amounts or where otherwise indicated)

1.     Nature
Note 1 – Organization and Description of OperationsBusiness
Ranger Oil Corporation (together with its consolidated subsidiaries, unless the context otherwise requires, “Ranger,” “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 October 5,January 15, 2021, the Company acquired Lonestar Resources US Inc., a Delaware corporation (“Lonestar”consummated the transactions (collectively, the “Juniper Transactions”), as a result of which Lonestar contemplated by: (i) the Contribution Agreement, dated November 2, 2020, by and its subsidiaries became wholly-owned subsidiaries ofamong the Company, (the “Merger”). The Merger was effected pursuant toROCC Energy Holdings, L.P. (formerly PV Energy Holdings, L.P., the Agreement“Partnership”) and Plan of Merger (the “Merger Agreement”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 July 10, 2021,November 2, 2020, by and betweenamong Rocky Creek Resources, LLC, an affiliate of Juniper Capital (“Rocky Creek”), the Company and Lonestar. Following the completion of the Merger, the Company changed its name from Penn Virginia Corporation (“Penn Virginia”)Partnership pursuant to Ranger Oil Corporation,which Juniper contributed $150 million in cash and its Class A Common Stock (“Class A Common Stock”), par value of $0.01 per share, began trading on The Nasdaq Global Select Market (“Nasdaq”) under the symbol “ROCC” on October 18, 2021.

certain oil and gas assets in South Texas in exchange for equity. See Note 2 for further discussion.
2.    Note 2 – Basis of Presentation and Significant Accounting Policies
Basis of Presentation
Our unaudited condensed consolidated financial statements include the accounts of Ranger Oil and all of our subsidiaries as of the relevant dates. Intercompany balances and transactions have been eliminated. A substantial noncontrolling interest in our subsidiaries is provided for in our condensed consolidated statements of operations and comprehensive income (loss) as well asand our condensed consolidated balance sheets as of and for the period ended September 30, 2021 (see Note 3 for additional detail including the basis of presentation of the noncontrolling interest).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 consisting of normal recurring accruals, 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, 2020.2021 (“2021 Annual Report”). Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications did not have a material impact on prior period financial statements. As the Merger was completed after the quarterly period ended September 30, 2021, our unaudited condensed consolidated financial statements exclude Lonestar’s financial information and operating results for all periods presented.

3.    Juniper Transactions
On January 15, 2021 (the “Juniper Closing Date”), the Company consummated the transactions (collectively, the “Juniper Transactions”) contemplated by: (i) the Contribution Agreement, dated November 2, 2020 (the “Contribution Agreement”), by and among the Company, PV Energy Holdings, L.P. (the “Partnership”) and JSTX Holdings, LLC (“JSTX”), an affiliatePrinciples of Juniper Capital Advisors, L.P. (“Juniper Capital” and, together with JSTX and Rocky Creek, “Juniper”); and (ii) the Contribution Agreement, dated November 2, 2020 (the “Asset Agreement,” and, together with the Contribution Agreement, the “Juniper Transaction Agreements”), by and among Rocky Creek Resources, LLC, an affiliate of Juniper Capital (“Rocky Creek”), the Company and the Partnership.Consolidation
In connection with the consummation of the Juniper Transactions, the CompanyJanuary 2021, Ranger Oil completed a reorganization into an up-CUp-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 was intended to, among other things, result inare non-economic voting only shares of the affiliates of Juniper Capital having a votingCompany. Juniper’s economic interest in the Company that is commensurate with such holders’ economic interest in the Partnership, including (i) the conversionheld through its ownership of each of the Company’s corporate subsidiaries into limited liability companies which are disregarded for U.S. federal income tax purposes, including the conversion of Penn Virginia Holding Corp. into Penn Virginia Holdings, LLC, a Delaware limited liability company (“Holdings”), and (ii) the Company’s contribution of all of its equity interests in Holdings to the Partnership in exchange for 15,268,686 newly issued common units representing limited partner interests (the “Common Units”). 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


OnThe Common Units are redeemable (concurrently with the cancellation of an equivalent number of shares of Class B Common Stock) by Juniper Closing Date, (i) pursuant to the terms of the Contribution Agreement, JSTX contributed to the Partnership, asat any time on a capital contribution, $150 million in cashone-for-one basis in exchange for 17,142,857 newly issuedshares of Class A Common Units andStock 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 issued to JSTX 171,428.57 shares of Series A Preferred Stock, par value $0.01 per share,would consider the interests of the Company (“Seriesholders of the Class A Preferred Stock”) at a price equal toCommon Stock, the parCompany’s financial condition, results of operations, earnings, projections, liquidity and capital requirements, management’s assessment of the intrinsic value of the shares acquired, and (ii) pursuant toClass A Common Stock, the termstrading price of the Asset Agreement, including certain closing adjustments based on a September 1, 2020 effective date (the “Effective Date”), Rocky Creek contributed to our operating subsidiary certain oil and gas assetsClass A Common Stock, legal requirements, covenant compliance, restrictions in exchange for 5,405,252 newly issued Common Units and the Company issued to Rocky Creek 54,052.52 shares of Series A Preferred Stock (5,406,141 Common Units and 54,061.41 shares of Series A Preferred Stock after post-closing adjustments) at a price equal to the par value of the shares acquired, including 495,900 Common Units and 4,959 shares of Series A Preferred Stock placed in a restricted account to support post-closing indemnification claims, 50% of such amount of which was disbursed 180 days after the Juniper Closing Date and the remainder to be disbursed one year after the Juniper Closing Date. In connection with the contribution of the oil and gas assets under the Asset Agreement, we received $1.2 million of revenues attributable to production from the Rocky Creek assets for the period from December 1, 2020 through the Juniper Closing Date.
We incurred a total of $19.0 million of professional fees, including advisory, legal, consulting feesCompany’s debt agreements and other costs in connection with the Juniper Transactions. A total of $5.0 million were attributable to services and costs incurred and recognized in 2020 as general and administrative expenses (“G&A”). The remaining $14.0 million of costs were incurred in January 2021 or otherwise incurred contingent upon the closing of the Juniper Transactions, including $5.5 million of transaction costs incurred by Juniper that were required to be paid by the Company under the Juniper Transaction Agreements as well as $3.8 million of costs incurred by us related to the issuance of the Series A Preferred Stock and Common Units. Collectively, these amounts were classified as a reduction to the capital contribution on our condensed consolidated balance sheet. The remainder of $4.7 million, representing professional fees and other costs, was recognized as a component of G&A in the quarter ended March 31, 2021.factors it deems relevant.
In determining the appropriate accounting for the Partnership and Juniper’s interest, we considered the guidance in Accounting Standards Codification (“ASC”) 810, Consolidation. The Partnership is considered a variable interest entity for which the Company is the primary beneficiary as itbeneficiary. The Company has a controlling financial interestbenefits in the Partnership through the Common Units, and it has the power to directover the activities most significant to the Partnership’s economic performance through its 100% controlling interest in the GP (which, accordingly, is acting as well asan agent on behalf of the obligationCompany). 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 absorb lossesblock or participate in certain operational and receive benefitsfinancial decisions that are potentially significant.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 reflected as a consolidated subsidiarythe primary beneficiary of the Partnership and consolidates the Partnership in the condensedCompany’s consolidated financial statements. The ownershipCompany reflects a noncontrolling interest in the Partnershipconsolidated 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 (the “Noncontrolling interest”) is included in the condensed consolidated balance sheet as Partnership.
Noncontrolling Interest
The noncontrolling interest which is classified within permanent equity. The Noncontrolling interest is classified in permanent equity as it does not meet the definition of a liability under ASC 480, Distinguishing Liabilities from Equity and, among other considerations, the Common Units are optionally redeemablepercentage may be affected by the holder for a fixed numberissuance of shares (on a one-for-one basis) and there is no fixed or determinable date or fixed or determinable price for redemption; further, while the Common Units may be redeemed withof Class A Common Stock, repurchases or cash,cancellation of Class A Common Stock, the methodexchange of settlement is solely at the discretion of the Company, with the Company having the ability to settle the redemption in shares. Additionally, while the holders of the Series A Preferred Stock (now Class B Common Stock as described below), who also ownand the redemption of Common Units could cause the Noncontrolling interest to be redeemed through an event that is not solely within the control(and concurrent cancellation of the Company such as a change-in-control, through their majority voting rights, all holders of equally and more subordinated equity interests in the Company would be entitled to receive the same form of consideration upon such event.
Class B Common Stock), among other things. The Noncontrolling interest percentage is based on the proportionate amount of the number of Common Units held by Juniper relative to the total Common Units outstanding which is also equivalent tooutstanding. As of September 30, 2022, the voting powerCompany 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 associatedowned 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 Series A Preferred Stock (now Class B Common Stock as described below) held by Juniper. Thevesting 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 was initially measured onand Paid-in capital, tax effected, will occur. Because these changes in the Juniper Closing Dateownership 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 sum of (i) total Shareholders’ equity immediately prior to the closingcarrying value of the Juniper Transactions, (ii)Company’s basis in the fair value of Juniper’s and Rocky Creek’s contributions provided in exchange for Common Units and Series A Preferred Stock (net of the Juniper transaction costs and securities issuance costs paid by the Company and including the cash received directly by the Company for a portion of the Rocky Creek revenues as discussed above and asset retirement obligations (“AROs”) associated with the contributed properties); and (iii) a deferred income tax adjustment attributable to the Juniper Transactions, the total of which was then multiplied by the Noncontrolling interest percentage. The difference between the calculated Noncontrolling interestPartnership and the fair value of the consideration received was recorded as a reductionare recognized directly in equity and attributed to paid-in capital.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.
On October 6, 2021, the Company, JSTX and Rocky Creek entered into a Contribution and Exchange Agreement, whereby all outstanding shares of the Series A Preferred Stock were exchanged for newly issued shares of Class B Common Stock (“Class B Common Stock”), at a ratio of one share of Class B Common Stock for each 1/100th of a share of Series A Preferred Stock and the designation of the Series A Preferred Stock was cancelled. See Note 14 for additional information.
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 following table reconcilesrestricted cash related to the initial investmentnet 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 Juniperthe 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 carryingCompany’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 Noncontrolling interestrespective fair values as of the Juniper Closing Date (after post-closing adjustments):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.
Cash contribution$150,000 
Issue costs paid for Noncontrolling interest securities(3,758)
Transaction costs paid on behalf of Noncontrolling interest(5,543)
Fair value of Rocky Creek oil and gas properties contributed38,561 
Revenues received attributable to contributed properties1,160 
Suspense revenues attributable to the contributed properties(146)
Asset retirement obligations of the contributed properties(14)
Fair value of capital contributions180,260 
Income tax adjustment attributable to the Juniper Transactions(708)
Total shareholders’ equity prior to the Juniper Closing Date205,558 
$385,110 
Juniper voting power through Series A Preferred Stock59.6 %
Noncontrolling interest as of the Juniper Closing Date$229,620 
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, 2021Nine Months Ended September 30, 2021
Total revenues$200,995 $500,087 
Net income (loss) attributable to common shareholders$12,531 $(19,174)
4.Note 4 – Revenue Recognition
Revenue from Contracts with Customers
Crude oil.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,gathering, processing and transportation expense (“GPT”) in our condensed consolidated statements of operations.
NGLs.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 otherwise transported to a third-party customer. Currently,Depending upon the nature of the contractual arrangements with the midstream processing vendors regarding the marketing of the NGL products, we recognize revenue for theseNGL 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. Accordingly,customer, we recognize theseNGL 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 we market the productsold to our customers, most of whom are interstate pipelines.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.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.


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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,December 31,
20212020 September 30, 2022December 31, 2021
CustomersCustomers$76,909 $39,672 Customers$123,493 $96,195 
Joint interest partnersJoint interest partners10,102 3,079 Joint interest partners22,964 21,755 
Derivative settlements from counterparties1,000 3,287 
Derivative settlements from counterparties 1
Derivative settlements from counterparties 1
1,619 1,037 
OtherOtherOther99 18 
Total Total88,019 46,046 Total148,175 119,005 
Less: Allowance for credit lossesLess: Allowance for credit losses(246)(197)Less: Allowance for credit losses(352)(411)
Accounts receivable, net of allowance for credit losses
Accounts receivable, net of allowance for credit losses
$87,773 $45,849 Accounts receivable, net of allowance for credit losses$147,823 $118,594 
_______________________
Major Customers1     See Note 5 for information regarding our derivative instruments.
For the nine months ended September 30, 2021, 3 customers accounted for $185.5 million, or approximately 53%, of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2021, were $69.3 million, $71.0 million and $45.2 million, or 20%, 20% and 13% of the consolidated total, respectively. For the nine months ended September 30, 2020, 3 customers accounted for $113.4 million, or approximately 56%, of our consolidated product revenues. As of September 30, 2021 and December 31, 2020, $27.0 million and $24.1 million, or approximately 35% and 61%, respectively, of our consolidated accounts receivable from customers was related to the 3 customers referenced above. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers.
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5.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. 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.
Our derivative instruments are not formally designated as hedges for accounting purposes. While the use of derivative instruments limits the risk of adverse commodity price and interest rate movements, such use may also limit the beneficial impact of future product revenues and interest expense from favorable commodity price and interest rate movements. From time to time, we may enter into incremental derivative contracts in order to increase the notional volume of production we are hedging, restructure existing derivative contracts or enter into other derivative contracts resulting in modification to the terms of existing contracts. In accordance with our internal policies, we do not utilize derivative instruments for speculative purposes.

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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, 2021:2022:
4Q20211Q20222Q20223Q20224Q20221Q20232Q20233Q20234Q20231Q20242Q20244Q20221Q20232Q20233Q20234Q20231Q20242Q2024
NYMEX WTI Crude SwapsNYMEX WTI Crude SwapsNYMEX WTI Crude Swaps
Average Volume Per Day (bbl)Average Volume Per Day (bbl)815 457 457462308Average Volume Per Day (bbl)3,000 2,500 2,400 2,807 2,657 462 462 
Weighted Average Swap Price ($/bbl)Weighted Average Swap Price ($/bbl)$45.54 $58.75 $58.75$58.75$58.75Weighted Average Swap Price ($/bbl)$69.20 $54.40 $54.26 $54.92 $54.93 $58.75 $58.75 
NYMEX WTI Crude CollarsNYMEX WTI Crude CollarsNYMEX WTI Crude Collars
Average Volume Per Day (bbl)Average Volume Per Day (bbl)16,304 13,750 7,830 6,114 4,484 2,917 2,885 Average Volume Per Day (bbl)20,245 12,917 11,126 8,152 4,891 
Weighted Average Purchased Put Price ($/bbl)Weighted Average Purchased Put Price ($/bbl)$51.40 $53.94 $47.37 $44.00 $40.00 $40.00 $40.00 Weighted Average Purchased Put Price ($/bbl)$64.56 $63.23 $61.48 $72.00 $70.00 
Weighted Average Sold Call Price ($/bbl)Weighted Average Sold Call Price ($/bbl)$62.23 $66.25 $60.87 $58.36 $52.47 $50.00 $50.00 Weighted Average Sold Call Price ($/bbl)$88.78 $79.67 $74.31 $89.91 $86.04 
NYMEX WTI Purchased Puts
Average Volume Per Day (bbl)3,261 
Weighted Average Purchased Put Price ($/bbl)$55.00 
NYMEX WTI Crude CMA Roll Basis SwapsNYMEX WTI Crude CMA Roll Basis SwapsNYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (bbl)Average Volume Per Day (bbl)17,935 6,667 6,593 Average Volume Per Day (bbl)3,804 
Weighted Average Swap Price ($/bbl)Weighted Average Swap Price ($/bbl)$0.168 $0.625 $0.625 Weighted Average Swap Price ($/bbl)$1.751 
NYMEX HH SwapsNYMEX HH SwapsNYMEX HH Swaps
Average Volume Per Day (MMBtu)Average Volume Per Day (MMBtu)6,739 Average Volume Per Day (MMBtu)12,500 10,000 7,500 
Weighted Average Swap Price ($/MMbtu)$3.540 
Weighted Average Swap Price ($/MMBtu)Weighted Average Swap Price ($/MMBtu)$3.793 $3.620 $3.690 
NYMEX HH CollarsNYMEX HH CollarsNYMEX HH Collars
Average Volume Per Day (MMBtu)Average Volume Per Day (MMBtu)9,783 3,333 13,187 13,043 13,043 11,538 11,413 11,413 11,538 11,538 Average Volume Per Day (MMBtu)14,511 14,617 11,538 11,413 11,413 11,538 11,538 
Weighted Average Purchased Put Price ($/MMBtu)Weighted Average Purchased Put Price ($/MMBtu)$2.607 $4.150 $2.500 $2.500 $2.500 $2.500 $2.500 $2.500 $2.500 $2.328 Weighted Average Purchased Put Price ($/MMBtu)$2.854 $6.561 $2.500 $2.500 $2.500 $2.500 $2.328 
Weighted Average Sold Call Price($/MMBtu)$3.117 $5.750 $3.220 $3.220 $3.220 $2.682 $2.682 $2.682 $3.650 $3.000 
NYMEX HH Sold Puts
Average Volume Per Day (MMBtu)6,522 
Weighted Average Sold Put Price ($/MMBtu)$2.000 
OPIS Mt Belv Ethane Swaps
Weighted Average Sold Call Price ($/MMBtu)Weighted Average Sold Call Price ($/MMBtu)$3.791 $12.334 $2.682 $2.682 $2.682 $3.650 $3.000 
OPIS Mt. Belv Ethane SwapsOPIS Mt. Belv Ethane Swaps
Average Volume per Day (gal)Average Volume per Day (gal)28,022 27,717 27,717 98,901 34,239 34,239 34,615 Average Volume per Day (gal)27,717 98,901 34,239 34,239 34,615 
Weighted Average Fixed Price ($/gal)Weighted Average Fixed Price ($/gal)$0.2500 $0.2500 $0.2500 $0.2288 $0.2275 $0.2275 $0.2275 Weighted Average Fixed Price ($/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 MtMt. Belv refers to Oil Price Information Service Mt. Belvieu that serves as the benchmark for ethane which represents a commodity proxy for NGLs.

Interest Rate Derivatives
As of September 30, 2021,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 totalstotaled $300 million, with us paying a weighted average fixed rate of 1.36% on the notional amount, and the counterparties paying a variable rate equal to LIBOR through May 2022.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. The effects of derivative gains and (losses) and cash settlements are reported as adjustmentsAdjustments to reconcile net income (loss) to net cash provided by operating activities. These itemsactivities include derivative losses and cash settlements that are recorded within the Derivative contracts section ofreported under Net losses and Cash settlements and premiums paid, net, on our condensed consolidated statements of cash flows, under Net (gains) losses and Cash settlements and premiums received (paid), net.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,Three Months Ended September 30,Nine Months Ended September 30,
2021202020212020 2022202120222021
Interest Rate Swap gains (losses) recognized in the condensed consolidated statements of operationsInterest Rate Swap gains (losses) recognized in the condensed consolidated statements of operations$(84)$32 $(48)$(7,527)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 operationsCommodity gains (losses) recognized in the condensed consolidated statements of operations(21,000)(6,923)(119,631)117,406 Commodity gains (losses) recognized in the condensed consolidated statements of operations63,756 (21,000)(149,137)(119,631)
$(21,084)$(6,891)$(119,679)$109,879 $63,756 $(21,084)$(149,073)$(119,679)
Interest rate cash settlements recognized in the condensed consolidated statements of cash flowsInterest rate cash settlements recognized in the condensed consolidated statements of cash flows$(973)$(919)$(2,851)$(1,287)Interest rate cash settlements recognized in the condensed consolidated statements of cash flows$— $(973)$(1,415)$(2,851)
Commodity cash settlements and premiums received (paid) recognized in the condensed consolidated statements of cash flows(21,265)7,337 (43,190)66,582 
Commodity cash settlements and premiums paid recognized in the condensed consolidated statements of cash flowsCommodity cash settlements and premiums paid recognized in the condensed consolidated statements of cash flows(55,302)(21,265)(157,809)(43,190)
$(22,238)$6,418 $(46,041)$65,295 $(55,302)$(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, 2021December 31, 2020  September 30, 2022December 31, 2021
 DerivativeDerivativeDerivativeDerivative  DerivativeDerivativeDerivativeDerivative
TypeTypeBalance Sheet LocationAssetsLiabilitiesAssetsLiabilitiesTypeBalance Sheet LocationAssetsLiabilitiesAssetsLiabilities
Interest rate contractsInterest rate contractsDerivative assets/liabilities – current$— $2,496 $— $3,655 Interest rate contractsDerivative assets/liabilities – current$— $— $— $1,480 
Commodity contractsCommodity contractsDerivative assets/liabilities – current4,909 60,593 75,506 81,451 Commodity contractsDerivative assets/liabilities – current30,725 75,327 11,478 48,892 
Interest rate contractsInterest rate contractsDerivative assets/liabilities – non-current— — — 1,645 Interest rate contractsDerivative assets/liabilities – non-current— — — — 
Commodity contractsCommodity contractsDerivative assets/liabilities – non-current2,152 21,416 25,449 26,789 Commodity contractsDerivative assets/liabilities – non-current6,176 12,748 2,092 23,815 
 $7,061 $84,505 $100,955 $113,540   $36,901 $88,075 $13,570 $74,187 
As of September 30, 2021,2022, we reported net commodity derivative liabilities of $74.9 million and net Interest Rate Swap liabilities of $2.5$51.2 million. The contracts associated with these positions are with 9seven counterparties for commodity derivatives, and 4 counterparties for Interest Rate Swaps, all of which are investment grade financial institutions and are participants in our revolving credit facility (the “Credit Facility”). This concentration may impact our overall credit risk in that these counterparties may be similarly affected by changes in economic or other conditions. Non-performance risk is incorporated by utilizing discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is in a liability position.
The agreements underlying our derivative instruments include provisions for the netting of settlements with the counterparties for contracts of similar type. We have neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. Furthermore, our derivative contracts are not subject to margin calls or similar accelerations. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.
See Note 10 for information regarding the fair value of our derivative instruments.

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6.Note 6 – Property and Equipment, Net
The following table summarizes our property and equipment as of the dates presented: 
September 30,December 31, September 30, 2022December 31, 2021
20212020
Oil and gas properties:  
Oil and gas properties (full cost accounting method):Oil and gas properties (full cost accounting method):  
ProvedProved$1,762,268 $1,545,910 Proved$2,828,400 $2,327,686 
UnprovedUnproved59,560 49,935 Unproved55,429 57,900 
Total oil and gas propertiesTotal oil and gas properties1,821,828 1,595,845 Total oil and gas properties2,883,829 2,385,586 
Other property and equipment28,265 27,746 
Other property and equipment 1
Other property and equipment 1
32,156 31,055 
Total properties and equipmentTotal properties and equipment1,850,093 1,623,591 Total properties and equipment2,915,985 2,416,641 
Accumulated depreciation, depletion, amortization and impairmentsAccumulated depreciation, depletion, amortization and impairments(985,215)(900,042)Accumulated depreciation, depletion, amortization and impairments(1,204,618)(1,033,293)
Total property and equipment, net Total property and equipment, net$864,878 $723,549 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 $59.6$55.4 million and $49.9$57.9 million have been excluded from amortization as of September 30, 20212022 and December 31, 2020,2021, respectively. An additional $1.2We transferred $8.7 million and $13.8 million of unproved leasehold costs, including capitalized interest, associated with wells in-progress for which we had not previously recognized any proved undeveloped reserves, were excluded from amortization as of December 31, 2020. We transferred $13.8 million and $4.5 million of undeveloped leasehold costs associated with acreage unlikely to be drilled or associated with proved undeveloped reserves, including capitalized interest,expiring acreage, from unproved properties to the full cost pool during the nine months ended September 30, 20212022 and 2020,2021, respectively. We capitalized internal costs of $2.8$4.0 million and $1.3$2.8 million and interest of $2.6$3.3 million and $2.1$2.6 million during the nine months ended September 30, 20212022 and 2020,2021, respectively, in accordance with our accounting policies. Average depreciation, depletion and amortization per barrel of oil equivalent of proved oil and gas properties was $12.96$15.84 and $16.63$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 2020,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”). DuringThe 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 Company recorded zerodecline in commodity prices as a result of COVID-19 and a $1.8 millionmacroeconomic factors as discussed above, resulting in an impairment of its oil and gas properties, respectively. During the three and nine months ended September 30, 2020, the Company recorded impairments of itsour oil and gas properties of $236.0$1.8 million and $271.5 million, respectively.during the three months ended March 31, 2021. No further impairments were recorded during the remainder of 2021.
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7.Note 7 – Long-Term Debt
The following table summarizes our debt obligations as of the dates presented:
September 30, 2021December 31, 2020September 30, 2022December 31, 2021
Credit FacilityCredit Facility$212,900 $314,400 Credit Facility$215,000 $208,000 
Second Lien Facility143,110 200,000 
9.25% Senior Notes due 20269.25% Senior Notes due 2026400,000 — 9.25% Senior Notes due 2026400,000 400,000 
Mortgage debt 1
Mortgage debt 1
— 8,438 
Other 2
Other 2
284 2,516 
TotalTotal756,010 514,400 Total615,284 618,954 
Less: Unamortized discount 1
(4,855)(1,604)
Less: Unamortized deferred issuance costs 1, 2
(4,327)(3,299)
Less: Unamortized discount 3
Less: Unamortized discount 3
(3,227)(3,720)
Less: Unamortized deferred issuance costs 3, 4
Less: Unamortized deferred issuance costs 3, 4
(8,559)(9,853)
Total, netTotal, net$746,828 $509,497 Total, net603,498 605,381 
Less: Current portionLess: Current portion(7,500)— Less: Current portion(41)(4,129)
Long-term debtLong-term debt$739,328 $509,497 Long-term debt$603,457 $601,252 
_______________________
1     DiscountThe mortgage debt related to the corporate office building and issuance costsrelated 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 Second Lien Facility are being amortized overcorporate office building. See Note 3 for additional information on the termsale.
2     Other debt of $2.2 million was extinguished during the underlying loan using the effective-interest method.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 will beare being amortized over its respective term beginning inusing the fourth quarter of 2021 concurrent with the related proceeds being released from escrow and closing of the Lonestar acquisition.effective-interest method.
24     Excludes issuance costs ofassociated with the Credit Facility, which representrepresents 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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Credit Facility
As of September 30, 2021,2022, the Credit Facility had a $1.0 billion revolving commitment and a $375$950 million borrowing base includingwith 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; however,base less outstanding borrowings under the Credit Facility were limited to a maximumadvances and letters of $350 million as of September 30, 2021.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 generally 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. Prior
In June 2022, we entered into the Agreement and Amendment No. 12 to the EleventhCredit Agreement (the “Twelfth Amendment”). The Twelfth Amendment, (as defined below),in addition to other changes described therein, amended the Credit Facility was scheduled to, mature in May 2024. We had $0.4 million in letters of credit outstanding as of September 30, 2021 and December 31, 2020. During the nine months ended September 30, 2021, we incurred and capitalized approximately $0.7 million of issue costs associated with amendments to the Credit Facility. During the nine months ended September 30, 2020, we incurred and capitalized approximately $0.1 million of issue costs and wrote-off $0.9 million of previously capitalized issue costs due to a reduction ofeffective on June 1, 2022, (1) increase the borrowing base duringfrom $725 million to $875 million, with aggregate elected commitments remaining at $400 million and (2) replaced LIBOR with the first half of 2020.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 is guaranteed by all ofto (1) increase the subsidiaries ofborrowing base from $875 million to $950 million and (2) increase the borrower (the “Guarantor Subsidiaries”), except for Boland Building, LLC, effective upon the Eleventh Amendment, which holds real estate assets that are associated with Lonestar’s legacy mortgage obligations. The guaranteesaggregate elected commitment amounts under the Credit Facility are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. The obligations under the Credit Facility are secured by a first priority lien on substantially all of our subsidiaries’ assets.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 through 2021,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, 2021,2022, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 3.09%5.63%. Unused commitment fees are charged at a rate of 0.50%.
As of September 30, 2021, the
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The Credit Facility requiredrequires 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 and (3) a maximum first lien leverage ratio (consolidated secured 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 2.50 to 1.00.
The Credit Facility also contains other customary affirmative and negative covenants including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends, and transactions with affiliates and other customary covenants. In addition,well as of September 30, 2021, the Credit Facility contained certain anti-cash hoarding provisions.
The Credit Facility contains 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, 2021,2022, we were in compliance with all of thedebt covenants under the Credit FacilityFacility.
We had $215.0 million in effect at such time.
In August 2021, we entered into the Master Assignment, Agreementoutstanding borrowings and Amendment No. 11 to Credit Agreement (the “Eleventh Amendment”). The Eleventh Amendment,$0.7 million in addition to other changes described therein, amendedoutstanding letters of credit under the Credit Facility to, effective on the closingas of the Merger and satisfaction of other conditions set forth therein, (1) increase the borrowing base to $600 million, with aggregate elected commitments of $400 million, (2) remove certain availability restrictions, (3) remove minimum hedging requirements, (4) remove the first lien leverage ratio covenant, (5) remove the Partnership and PV Energy Holdings GP, LLC as guarantors, and (6) extend the maturity date to the date that is the four year anniversary of the date such amendment became effective, or October 6, 2025.
Second Lien Facility
We entered into the $200 million Second Lien Facility in September 2017 to fund a significant acquisition as well as related fees and expenses. In January 2021, the amendment dated November 2, 2020 (the “Second Lien Amendment”) became effective at which time we made a $50.0 million prepayment as well as a $1.3 million principal payment to a single participant
15


lender to liquidate their interest30, 2022. Factoring in the Second Lien Facility. The Second Lien Amendment provided for (i) the extensionoutstanding letters of the maturity datecredit, we had $284.3 million of the Second Lien Facility to September 29, 2024, (ii) an increase to the margin applicable to advancesavailability under the Second LienCredit Facility (iii) the impositionas of certain limitations on capital expenditures, acquisitions and investments if the Asset Coverage Ratio (as defined therein) at the end of any fiscal quarter is less than 1.25 to 1.00, (iv) the requirement for maximum and, in certain circumstances as described therein, minimum hedging arrangements, (v) beginning in 2021, a requirement to make quarterly amortization payments equal to $1.875 million and (vi) a provision for the replacement of the LIBOR interest rate upon its expiration.September 30, 2022. During the nine months ended September 30, 2022 and 2021, we incurred and capitalized $1.4approximately $0.8 million and $0.7 million of issue costs in connectionassociated with the Second Lien Amendment and wrote off $1.2 million of previously capitalized issue costs and original issue discount allocableamendments to the aforementioned prepayments as a loss on the extinguishment of debt.
The outstanding borrowings under the Second LienCredit Facility, bore interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin of 7.25% or (b) a Eurodollar rate, including LIBOR through 2021, with a floor of 1.00%, plus an applicable margin of 8.25%; provided that the applicable margin would increase to 8.25% and 9.25%, respectively, during any quarter in which the quarterly amortization payment was not made. As of September 30, 2021, the actual interest rate of outstanding borrowings under the Second Lien Facility was 9.25%. Interest on reference rate borrowings was payable quarterly in arrears and computed on the basis of a year of 365/366 days, and interest on Eurodollar borrowings was payable every one or three months (including in three month intervals if we select a six-month interest period), at our election and computed on the basis of a 360-day year.
The Second Lien Facility was collateralized by substantially all of our operating subsidiaries’ assets with lien priority subordinated to the liens securing the Credit Facility. The obligations under the Second Lien Facility were guaranteed by all of Holdings’ subsidiaries.
The Second Lien Facility had no financial covenants, but contained affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), limitations on capital expenditures, investments, the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends and transactions with affiliates and other customary covenants.
As of September 30, 2021, we were in compliance with all of the covenants under the Second Lien Facility.
On October 5, 2021, Holdings repaid all of its outstanding obligations under the Second Lien Facility, and terminated the Second Lien Facility. In accordance with the Second Lien Facility, we incurred a prepayment premium of 102% as a result of repayment.respectively.
9.25% Senior Notes due 2026
On August 10, 2021, our indirect, wholly-owned subsidiary Penn Virginia Escrow LLC (the “Escrow Issuer”) completed an offering of $400 million aggregate principal amount of senior unsecured notes due 2026 (the “9.25% Senior Notes due 2026”) that bear interest at 9.25% and were sold at 99.018% of par. The proceeds of the offering, net of discount, and other funds were initially deposited in an escrow account pending satisfaction of certain conditions, including the consummation of the Merger on or prior to November 26, 2021. As of September 30, 2021, these funds remained in escrow.
Of the $446.8 million total cash, cash equivalents and restricted cash presented on the condensed consolidated statement of cash flows as of September 30, 2021, $396.1 million is classified as Restricted cash - non-current within long-term assets based on the long-term nature ofObligations under the 9.25% Senior Notes due 2026. 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 remaining $15.4indenture 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 is classified as Restricted cash - current as this portion represents accrued interest and an amount equivalentexpense 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 original issue discount. Thevaluation allowance against our net proceeds fromdeferred tax assets resulting in an effective tax rate of 0.9%, which is fully attributable to the offering, along with cash on hand, were usedState of Texas. Our net deferred income tax liability balance of $5.0 million as of September 30, 2022 is also fully attributable to repay all outstanding amounts under the Second Lien Facility plus certain long-term debtState of Lonestar upon consummation of the Merger. See Note 14 for additional information.

8.    Income TaxesTexas 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. In connection with the Juniper Transactions, we recorded an adjustment of $0.7 million to Paid-in capital (see Note 3) attributable to certain state deferred income tax effects associated with the change in legal entity structure. Our net deferred income tax liability balance of $0.8 million as of September 30, 2021 is also fully attributable to the State of Texas and primarily related to property.
We recognized a federal and state income tax benefit of $1.6 million and $1.1 million for the three and nine months ended September 30, 2020, respectively. The federal and state tax expense was offset by an adjustment to the valuation allowance
16


against our net deferred tax assets resulting in an effective tax rate of 0.6% which was fully attributable to the State of Texas. The provision also reflected a reclassification of $1.2 million from deferred tax assets to current income taxes receivable for certain refundable alternative minimum tax credit carryforwards that were later received in June 2020.
We had no liability for unrecognized tax benefits as of September 30, 20212022 and December 31, 2020.2021. There were no interest and penalty charges recognized during the three and nine months ended September 30, 20212022 and 2020.2021. Tax years from 20152017 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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9.Note 9 – Supplemental Balance Sheet Detail
The following table summarizes components of selected balance sheet accounts as of the dates presented:
September 30,December 31,
20212020 September 30, 2022December 31, 2021
Prepaid and other current assets:Prepaid and other current assets:  Prepaid and other current assets:  
Inventories 1
Inventories 1
$6,015 $4,274 
Inventories 1
$10,504 $10,305 
Prepaid expenses 2
Prepaid expenses 2
2,517 14,771 
Prepaid expenses 2
2,545 10,693 
$8,532 $19,045  $13,049 $20,998 
Other assets:Other assets:  Other assets:  
Deferred issuance costs of the Credit Facility, net of amortizationDeferred issuance costs of the Credit Facility, net of amortization$2,422 $2,349 Deferred issuance costs of the Credit Facility, net of amortization$3,603 $3,308 
Right-of-use assets – operating leasesRight-of-use assets – operating leases1,882 2,432 Right-of-use assets – operating leases1,083 1,671 
OtherOther— 127 Other— 38 
$4,304 $4,908  $4,686 $5,017 
Accounts payable and accrued liabilities:Accounts payable and accrued liabilities:  Accounts payable and accrued liabilities:  
Trade accounts payableTrade accounts payable$34,323 $7,055 Trade accounts payable$31,135 $32,452 
Drilling and other lease operating costsDrilling and other lease operating costs32,726 16,088 Drilling and other lease operating costs81,225 35,045 
Royalties55,398 26,615 
Revenue and royalties payableRevenue and royalties payable110,867 95,521 
Production, ad valorem and other taxesProduction, ad valorem and other taxes8,682 3,094 Production, ad valorem and other taxes15,949 7,905 
Derivative settlements to counterpartiesDerivative settlements to counterparties6,813 321 Derivative settlements to counterparties5,991 6,117 
Compensation5,714 4,222 
Compensation and benefitsCompensation and benefits6,848 13,942 
InterestInterest5,745 504 Interest5,341 15,321 
Environmental remediation liability 3
Environmental remediation liability 3
1,519 2,287 
Current operating lease obligationsCurrent operating lease obligations937 936 Current operating lease obligations876 914 
Other 3
1,992 4,254 
OtherOther4,613 4,877 
$152,330 $63,089  $264,364 $214,381 
Other non-current liabilities:Other non-current liabilities:  Other non-current liabilities:  
Asset retirement obligationsAsset retirement obligations$5,972 $5,461 Asset retirement obligations$8,691 $8,413 
Non-current operating lease obligationsNon-current operating lease obligations1,161 1,752 Non-current operating lease obligations332 975 
Postretirement benefit plan obligationsPostretirement benefit plan obligations1,094 1,149 Postretirement benefit plan obligations907 970 
$9,930 $10,358 
$8,227 $8,362 
_______________________
1    Includes tubular inventory and well materials of $5.7$9.9 million and $3.9$9.5 million and crude oil volumes in storage of $0.3$0.6 million and $0.4$0.8 million as of September 30, 20212022 and December 31, 2020,2021, respectively.
2 The balances as of September 30, 20212022 and December 31, 20202021 include $1.0$0.8 million and $13.6$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, 2020 includes $3.5 million2021 represents estimated costs associated with remediation activities for certain wells and tanks acquired as part of accrued costs attributable to Juniper Transaction expenses.
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the Lonestar Acquisition; the remediation will be substantially complete in the fourth quarter of 2022.
10.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, and restricted cash, accounts receivable, and accounts payable approximate fair value due to their short-term maturities. As of September 30, 20212022 and December 31, 2020,2021, 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 $756.0$619.0 million and $762.0 million, respectively. As of December 31, 2020, the estimated fair value of total debt (before amortization of issuance costs) approximated the carrying value of $514.4$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, 2021 As of September 30, 2022
Fair ValueFair Value Measurement ClassificationLevel 1Level 2Level 3Total
DescriptionMeasurementLevel 1Level 2Level 3
Assets:    
Financial assets:Financial assets:   
Commodity derivative assets – currentCommodity derivative assets – current$4,909 $— $4,909 $— Commodity derivative assets – current$— $30,725 $— $30,725 
Commodity derivative assets – non-currentCommodity derivative assets – non-current$2,152 $— $2,152 $— Commodity derivative assets – non-current— 6,176 — 6,176 
Liabilities:    
Total financial assetsTotal financial assets$— $36,901 $— $36,901 
Financial liabilities:Financial liabilities:   
Interest rate swap liabilities – currentInterest rate swap liabilities – current$(2,496)$— $(2,496)$— Interest rate swap liabilities – current$— $— $— $— 
Interest rate swap liabilities – non-current$— $— $— $— 
Commodity derivative liabilities – currentCommodity derivative liabilities – current$(60,593)$— $(60,593)$— Commodity derivative liabilities – current— (75,327)— (75,327)
Commodity derivative liabilities – non-currentCommodity derivative liabilities – non-current$(21,416)$— $(21,416)$— Commodity derivative liabilities – non-current— (12,748)— (12,748)
Total financial liabilitiesTotal financial liabilities$— $(88,075)$— $(88,075)
 As of December 31, 2020
 Fair ValueFair Value Measurement Classification
DescriptionMeasurementLevel 1Level 2Level 3
Assets:    
Commodity derivative assets – current$75,506 $— $75,506 $— 
Commodity derivative assets – non-current$25,449 $— $25,449 $— 
Liabilities:    
Interest rate swap liabilities – current$(3,655)$— $(3,655)$— 
Interest rate swap liabilities – non-current$(1,645)$— $(1,645)$— 
Commodity derivative liabilities – current$(81,451)$— $(81,451)$— 
Commodity derivative liabilities – non-current$(26,789)$— $(26,789)$— 

 As of December 31, 2021
Level 1Level 2Level 3Total
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, MEHMagellan East Houston (“MEH”) crude oil, NYMEX HH natural gas and OPIS MtMt. Belv Ethane natural gas liquids closing prices as of the end of the reporting periods. Each of these is a Level 2 input.
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Interest rate swaps: We determinedetermined 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 estimateestimated the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these iswas 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
In addition to the fair value measurements applied with respect to assets contributed in the Juniper Transactions, theThe most significant non-recurring fair value measurements utilized in the preparation of our condensed consolidated financial statements are those attributable to the initial determination of AROs associated with the ongoing development of new oil and gas properties and certain share-based compensation awards.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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11.Note 11 – Commitments and Contingencies
Drilling and Completion Commitments
As of September 30, 2021,2022, we had contractual commitments on a pad-to-pad basistwo year contract for one drilling rig and contracts for two drilling rigs.rigs with terms less than one year.
Gathering and Intermediate Transportation Commitments
We have long-term agreements that provide us with Nuevo G&T and Nuevo Dos Marketing, LLC (“Nuevo Marketing” and together with Nuevo G&T, collectively “Nuevo”) to providefield gathering and intermediate pipeline transportation services for a substantial portionmajority of our crude oil and condensate production in as well asLavaca 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:
Nuevo is obligated to gather and transport our crude oil and condensate from within a dedicated area in the Eagle Ford via a gathering system and intermediate takeaway pipeline connecting to a downstream interstate pipeline operated by a third party through 2041. We have a minimum volume commitment (“MVC”)
Description of contractual arrangementExpiration
of Contractual Arrangement
Minimum Volume
Commitment (MVC)
(bbl/d)
Expiration of Minimum Volume Commitment (MVC)
Field gathering agreementFebruary 20418,000February 2031
Intermediate pipeline transportation servicesFebruary 20268,000February 2026
Volume capacity supportApril 20268,000April 2026
Each of 8,000 gross barrels of oil per day to Nuevo through 2031 under the gathering agreement. We are obligatedthese arrangements also contain an obligation to deliver the first 20,000 gross barrels of oil per day produced from Gonzales, Lavaca Fayette and DeWittFayette 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 a marketing agreement, we have a commitment to sell 8,000 barrels per day of crude oil (gross) to Nuevo, or to any third party, utilizing Nuevo Marketing’sthe field gathering and volume capacity on a downstream interstate pipeline through 2026.
Under each of the agreements with Nuevo,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 existing credits that we have earned during the preceding 12-month period ended September 30, 20212022 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 2021,2022, approximately $13.9 million per year for 20222023 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 a component of the crude oil gathering agreement referenced above,September 30, 2022, we havehad 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. We have also contractedIn addition, we had access for access to up to an additional 70,000 barrels of tank capacity at the CDP on a month-to-month basis, which can be terminated by either party with 45-days’45 days’ notice to the counterparty. We have also contracted for crude oil storage capacity for up to 90,000 barrels with a downstream interstate pipeline at a facility in DeWitt County, Texas, on a month-to-month basis which can be terminated by either party with 45-days’ notice to the counterparty. Finally, we have an agreement with a marketing affiliate of the aforementioned downstream interstate pipeline to utilize up to 62,000 barrels of capacity within their system on a firm basis and an additional 120,000 barrels, if available, on a flexible basis. Costs associated with these agreementsthis monthly agreement are in the form of a monthly fixed rate short-term leaseslease and are charged as incurred on a monthly basis to GPT in our condensed consolidated statements of operations.
Legal, Environmental ComplianceOther Agreements
We have a long-term dedication of certain specific leases under a crude purchase and Other Claimsthroughput 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. We had AROs of approximately $6.0 million and $5.5 million attributable to the plugging of abandoned wells as of September 30, 2021 and December 31, 2020, respectively. As of September 30, 20212022 and December 31, 2020,2021, 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.

21


12.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,
2022202120222021
Net income attributable to common shareholders$106,236 $17,387 $167,435 $6,860 
Transfers from the noncontrolling interest, net 1
7,121 N/A13,619 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, 2022includes 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 a total of 4,424,600 shares of Class A Common Stock for issuance under the Penn Virginia CorporationRanger Oil Management Incentive Plan (the “Plan”) for share-based compensation awards. A total of 760,220 RSUs811,573 time-vested restricted stock units (“RSUs”) and 484,197 PRSUs664,414 performance-based restricted stock units (“PRSUs”) have been granted to employees and directors through September 30, 2021. As2022.
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, a total of 239,524 RSUs and 345,069 PRSUs are unvested and outstanding.
Wewe recognized $4.2 million, including approximately $1.9 million as a result of the change-in-control event associated with the Juniper Transactions, and $0.8$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, 2021 and 2020, respectively.2022 with respect to awarded RSUs:
The table below presents the number of RSUs granted, the average grant-date fair value and the number of shares vested for the following periods:
Time-Vested
Restricted Stock
Units
Weighted-Average
Grant Date
Fair Value
Balance at January 1, 2022230,517 $9.20 
Granted49,314 $35.07 
Vested(111,479)$10.02 
Forfeited(16,101)$12.12 
Balance at September 30, 2022152,251 $17.50 
Nine Months Ended September 30,
20212020
RSUs granted118,223 281,382 
Average grant-date fair value$13.84$4.49
Issued upon vesting, net of shares withheld for income taxes122,911 45,435 
Compensation expense for RSUs is being charged to expenserecognized on a straight-line basis over the applicable vesting period, which is generally over a rangethree-year period. As of less than oneSeptember 30, 2022, we had $2.0 million of unrecognized compensation cost attributable to threeRSUs. We expect that cost to be recognized over a weighted-average period of 1.89 years.
Performance-Based Restricted Stock Units
The table below presents the number of PRSUs granted and the number of shares vestedsummarizes activity for the following periods:nine months ended September 30, 2022 with respect to awarded PRSUs:
Nine Months Ended September 30,
20212020
PRSUs granted 1
225,206 145,399 
Monte Carlo grant-date fair value 2
$17.74 to $33.31$2.40 to $16.02
Average grant-date fair value 3
$13.63not applicable
Issued upon vesting, net of shares withheld for income taxes7,252 19,402 
___________________
1    The 2021 PRSU grants exclude one executive officers’ inducement award originally granted in August 2020 that was amended in April 2021 to conform vesting conditions to other PRSU awards granted in 2021.
2    Represents the Monte Carlo grant-date fair value of 2021 and 2020 PRSU grants based on the Company’s TSR performance (as defined below).
3    Represents the average grant-date fair value of 2021 PRSU grants (none granted prior to 2021) based on the Company’s ROCE performance (as defined below).
Performance Restricted Stock
Units
Weighted-Average
Grant Date
Fair Value
Balance at January 1, 2022345,069 $16.20 
Granted180,217 $47.77 
Vested(2,688)$18.24 
Forfeited(11,516)$23.31 
Balance at September 30, 2022511,082 $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 50% on the Company’s return on average capital employed (“ROCE”) relative to a defined peer group and 50% are based on the Company’s absolute total shareholder return and total shareholder return (“TSR”) relative to a defined peer group.group over the three-year performance period. The 2022 and 2021 PRSUs cliff vest from zero0% to 200 percent200% of the original grant at the end of a three-year performance period based on satisfaction of the respective underlying conditions.


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Vesting of PRSUs granted in 2020 and 2019 range from zero0% to 200 percent200% of the original grant based on the performance of our common stock (TSR-based)TSR relative to a defined peer group. Due togroup 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 PRSUand 2022 grants the grant-date fair value is derived by using a Monte Carlo model. The ranges for the assumptions used in the Monte Carlo model for thesethe PRSUs granted during 2022, 2021, 2020 and 2019 are presented as follows:
2021 1
2020 1
20192022
2021 1
2020 1
2019
Expected volatilityExpected volatility131.74% to 134.74%101.32% to 117.71%49.9 %Expected volatility134.98% to 138.75%131.74% to 134.74%101.32% to 117.71%49.9 %
Dividend yieldDividend yield0.0 %0.0 %0.0 %Dividend yield0.0 %0.0 %0.0 %0.0 %
Risk-free interest rateRisk-free interest rate0.22% to 0.29%0.18% to 0.51%1.66 %Risk-free interest rate2.59 %0.22% to 0.29%0.18% to 0.51%1.66 %
Performance periodPerformance period2021-20232020-20222020-2022Performance period2022-20242021-20232020-20222020-2022
__________________________________________
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.
PRSUs withAs 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 market condition do not allow for the reversalweighted-average period of previously recognized expense, even if the market condition is not achieved and no shares ultimately vest.
We recognize share-based compensation expense as a component of G&A expenses in our condensed consolidated statements of operations.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 $0.2 million and $0.5 million of expense attributable to the 401(k) Plan of $0.1 million and $0.5 million for the three and nine months ended September 30, 2021, respectively. We recognized $0.12022, respectively, and $0.2 million and $0.5 million of expense attributable to the 401(k) Plan for the three and nine months ended September 30, 2020,2021, 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, 20212022 and 2020.2021. 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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13.Note 14 – Earnings perPer Share
Basic net earnings (loss) per share is calculated by dividing the net income (loss) available to common shareholders, excluding net income or loss attributable to Noncontrolling interest, as applicable to the nine months ended September 30, 2021 (see Note 3), 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(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 Juniper as athe Noncontrolling interest in the Partnership are exchanged for common shares, as applicable to the nine months ended September 30, 2021 (see Note 3).shares. Accordingly, our reported net income (loss) attributable to common shareholders is adjusted due to reflect the reallocationelimination of the net income (loss) attributable to the Noncontrolling interest assuming exchange of the Common Units (and shares of Class B Common Stock as applicable to the three 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. See Note 14 for additional information related to our recapitalization of common stock and Series A Preferred Stock.
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,
 2021202020212020
Net income (loss)$43,063 $(243,413)$30,638 $(175,034)
Net income attributable to Noncontrolling interest(25,676)— (23,778)— 
Net income (loss) attributable to common shareholders (basic)17,387 (243,413)6,860 (175,034)
Reallocation of Noncontrolling interest net income25,676 — 23,778 — 
Net income (loss) attributable to common shareholders (diluted)$43,063 $(243,413)$30,638 $(175,034)
Weighted-average shares – basic15,319 15,183 15,298 15,168 
Effect of dilutive securities:
Common Units and Series A Preferred Stock that are exchangeable for common shares— — — — 
RSUs and PRSUs394 — 371 — 
Weighted-average shares – diluted 1
15,713 15,183 15,669 15,168 
 Three Months Ended September 30,Nine Months Ended September 30,
 2022202120222021
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 EPS106,236 17,387 167,435 6,860 
Adjustment for assumed conversions and elimination of Noncontrolling interest net income785 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 EPS19,741 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 PRSUs600 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), had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per share. For the three and nine months ended September 30, 2020, approximately 0.2 million and 0.1 million potentially dilutive securities, represented by RSUs and PRSUs, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per share.
22



.
14.Note 15 – Subsequent Events
Acquisition of Lonestar ResourcesDividends
On July 10, 2021, we entered into the Merger Agreement with Lonestar under which we would acquire Lonestar in the Merger. On October 5, 2021, our shareholders voted to approve the Merger and it was consummated the same day. In accordance with the terms of the Merger Agreement, Lonestar shareholders received 0.51 shares of Penn Virginia common stock for each share of Lonestar common stock held immediately prior to the effective time of the Merger. Based on the closing price of Penn Virginia common stock on October 5, 2021 of $30.19, and in connection with the Merger, the total value of Penn Virginia common stock issued to holders of Lonestar common stock, warrants and restricted stock units as applicable, was approximately $173.6 million.
The transaction will be 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 will be recorded at their respective fair values as of the date of completion of the Merger and added to Ranger Oil’s. The preliminary purchase price assessment remains an ongoing process and is subject to change for up to one year subsequent to the closing date of the Merger. Determining the fair value of the assets and liabilities of Lonestar requires judgment and certain assumptions to be made, the most significant of these being related to the valuation of Lonestar’s oil and gas properties.
Penn Virginia shareholders as of immediately prior to the consummation of the Merger own approximately 87% of the combined company, with affiliates of Juniper Capital owning 52% of the combined company, and former Lonestar shareholders own approximately 13% of the combined company.
Release of Escrowed Funds and Debt Repayments
In connection with the consummation of the Merger, the net proceeds from the offering of the 9.25% Senior Notes due 2026 and certain additional funds totaling $411.5 million were released from escrow on October 5, 2021. Obligations under the 9.25% Senior Notes due 2026 were assumed by Holdings, as borrower, and are guaranteed by the subsidiaries of Holdings that guarantee the Credit Facility.
The net proceeds from the 9.25% Senior Notes due 2026 were used to repay and discharge $249.8 million of Lonestar’s long-term debt including accrued interest and related expenses, and the remainder, along with cash on hand, of $146.2 million was used to repay the Second Lien Facility including a prepayment premium and accrued interest and related expenses.
Increased Borrowing Base of Credit Facility
Upon closing of the Merger and subject to the terms of Amendment No. 11 entered into in August 2021, our borrowing base under the Credit Facility increased to $600 million with aggregate elected commitments of $400 million.
See Note 7 for additional information on our debt.
Derivatives
Immediately following the Merger, we paid approximately $50 million to restructure certain of Lonestar’s derivatives, which was funded by borrowings under our Credit Facility. We have reset the majority of the swaps to reflect current market pricing.
Recapitalization ofNovember 2, 2022, the Company’s Common Stock
On October 6, 2021, the Company effectedBoard of Directors declared a recapitalization (the “Recapitalization”), pursuant to which (i) the Company’s common stock was renamed and reclassified ascash dividend of $0.075 per share of Class A Common Stock, (ii) the authorized numberpayable on November 28, 2022 to holders of sharesrecord of capital stockClass A Common Stock as of the Company was increased to 145,000,000 shares, (iii) 30,000,000 sharesclose of Class B common stock, par value of $0.01 per share, a new class of capital stock of the Company, was authorized, (iv) all outstanding shares of the Series A Preferred Stock were exchanged for newly issued shares of Class B Common Stock, and (v) the designation of the Series A Preferred Stock was cancelled.

business on November 16, 2022.
2325


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 transaction and integration-related issues;
risks related to the recently completed transactions with Juniper and its affiliates, including the risk that the benefits of the transactions may not be fully realized or may take longer to realize than expected, and that management attention will be diverted to transaction-related issues;
risks related to other completed acquisitions, including our ability to realize their expected benefits;
the decline in, sustained market uncertainty of,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 continued impact of world health events, including the COVID-19 pandemic, including reduced demand for oil and natural gas, economic slowdown, governmental actions, stay-at-home orders and interruptions to our operations or our customers operations;
risks related to and the impact of actual or anticipated other world health events;
risks related to acquisitions and dispositions, including our ability to realize their expected benefits;
•     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 and depressed 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 and exploratory drilling and well 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;
26


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;conditions, such as political tensions or war;
24


•     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 the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2021, and in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2020.
The effects of2021 and our Quarterly Reports on Form 10-Q for the COVID-19 pandemic may give rise to risks that are currently unknown or amplify the risks associated with many of these factors.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.

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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 statisticsamounts for the prior period have been reclassified to conform to the current period presentation. References to “quarters” represent the three months ended September 30, 20212022 or 2020,2021, 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
Acquisition of Lonestar ResourcesShare Repurchase Program
On October 5, 2021,April 13, 2022, our Board of Directors approved a share repurchase program, under which the Company acquired Lonestar Resources US Inc., a Delaware corporation (“Lonestar”), as a resultwas authorized to repurchase up to $100 million of which Lonestar and its subsidiaries became wholly-owned subsidiaries of Ranger Oil (the “Merger”). Lonestar’s oil and gas properties are located in the Eagle Ford Shale in South Texas.
In accordance with the terms of the Merger, Lonestar shareholders received 0.51 shares of Penn Virginia Corporation (“Penn Virginia”) common stock for each share of Lonestar common stock held immediately prior to the effective time of the Merger. Based on the closing price of Penn Virginia common stock on October 5, 2021 of $30.19, the total value of Penn Virginia common stock issued to holders of Lonestar common stock, warrants and restricted stock units as applicable, was approximately $173.6 million.
Following the completion of the Merger, the Company changed its name from Penn Virginia to Ranger Oil Corporation, and its Class A common stock (“outstanding Class A Common Stock”) began trading onStock through March 31, 2023. On July 7, 2022, the Nasdaq underBoard of Directors authorized an increase in the ticker symbol “ROCC” on October 18, 2021. Asshare repurchase program from $100 million to $140 million and extended the Merger was completed afterterm of the quarterly periodprogram through June 30, 2023.
During the three and nine months ended September 30, 2021,2022, we repurchased 1,074,960 and 1,755,836 shares of our results exclude Lonestar’s financial informationClass A Common Stock at a total cost of $35.0 million and operating results$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 all periods presented and discussed herein.a total cost of $12.5 million.
See Note 1412 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information.
Financing Updates
9.25% Senior Notes due 2026Dividends
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 10, 2021, our indirect, wholly-owned subsidiary Penn Virginia Escrow LLC (the “Escrow Issuer”) completed an offering4, 2022 to holders of $400 million aggregate principal amountrecord of senior unsecured notes due 2026 (the “9.25% Senior Notes due 2026”). These notes bear interest at 9.25% and were sold at 99.018% of par.
Debt Repayments
In connection with the consummationClass A Common Stock as of the Merger,close of business on July 25, 2022. Additionally, on November 2, 2022, the net proceeds from the offeringCompany’s Board of $400 million aggregate principal amountDirectors declared a cash dividend of 9.25% Senior Notes due 2026 and certain additional funds totaling $411.5 million were released from escrow$0.075 per share of Class A Common Stock payable on October 5, 2021. Obligations under the 9.25% Senior Notes due 2026 were assumed by Holdings, as borrower, and are guaranteed by the subsidiariesNovember 28, 2022 to holders of Holdings that guarantee our credit agreement (the “Credit Facility”).
The net proceeds from the 9.25% Senior Notes due 2026 were used to repay and discharge $249.8 millionrecord of Lonestar’s long-term debt including accrued interest and related expenses, and the remainder, along with cash on hand, of $146.2 million was used to repay the Second Lien Credit Agreement, datedClass A Common Stock as of September 29, 2017 (the “Second Lien Facility”) including a prepayment premiumthe close of business on November 16, 2022.
Recent Acquisitions
During the second and accrued interestthird quarters of 2022, we closed on several acquisitions of oil and related expenses.
Increased Borrowing Basegas producing properties in the Eagle Ford Shale, comprised of Credit Facility
Upon closing of the Merger, our borrowing base under the Credit Facility increasedadditional working interests in Ranger-operated wells and adjacent producing assets and undeveloped acreage for aggregate cash consideration totaling $129.8 million, subject to $600 million with aggregate elected commitments of $400 million.customary post-closing adjustments.
See Note 7 and Note 143 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information on our debt.acquisitions.
Hedging UpdateIncreased Borrowing Base of Credit Facility
26


Immediately followingOn September 27, 2022, the Merger, we paid approximately $50aggregate elected commitment amounts under the Credit Facility increased from $400 million to restructure certain of Lonestar’s derivatives, which was funded by borrowings under$500 million and our Credit Facility. We have reset the majority of the swapsborrowing base increased from $875 million to reflect current market pricing.

27


Recapitalization of the Company’s Common Stock
On October 6, 2021, the Company effected a recapitalization (the “Recapitalization”), pursuant to which (i) the Company’s common stock was renamed and reclassified as Class A common stock, (ii) the authorized number of shares of capital stock of the Company was increased to 145,000,000 shares, (iii) 30,000,000 shares of Class B common stock, par value of $0.01 per share (“Class B Common Stock”), a new class of capital stock of the Company, was authorized, (iv) all outstanding shares of the Series A Preferred Stock were exchanged for newly issued shares of Class B Common Stock, and (v) the designation of the Series A Preferred Stock was cancelled.$950 million.
See Note 147 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information.
Strategic Investment by Juniper
In January 2021, we consummated the Juniper Transactions whereby affiliates of Juniper contributed $150 million in cash and certain oil and gas assets in Lavaca and Fayette Counties in Texas to us in exchange for equity that entitles Juniper to both vote and share in any dividendinformation on the same basis as 22,548,998 shares of common stock (after post-closing adjustments). For additional information regarding the Juniper Transactions, see Note 3 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements.”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 the novel coronavirus (“COVID-19”) continues to createCOVID-19 created uncertainty for global economic activity. Over the past 18 months,Beginning in March 2020, the slowdown in global economic activity attributable to COVID-19 resulted in a dramatic decline in the demand for energy, beginning in March 2020, which directly impacted our industry and the Company. Most recently, however,Beginning in early 2021, increased mobility, deployment of vaccines and other factors hashave resulted in increased oil demand and commodity prices.
In addition, there remains a
28


A high level of uncertainty remains regarding the volatility of energy supply and demand as thedemand. The Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, collectively “OPEC+”) reached an agreementhas 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 2021and 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 increase productioncontribute 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 this past quarter. In early October 2021, OPEC+ reconfirmed$120 per bbl and over $9 per Mcf, respectively, due to oil supply shortage concerns. During the agreementthird quarter of 2022, WTI crude oil and natural gas prices dropped to boost output duringlows under $77 per bbl and $6 per Mcf, respectively. Higher commodity prices, along with the fourth quarter 2021. Higher energy pricesglobal supply chain issues and other factors, have increased inflation, which has led or may add to inflationary pressures, which could lead to increased service costs of services and a slowdowncertain 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 economic recovery.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. In 2021, we sell allAll of our crude oil volumes are sold under Magellan East Houston (“MEH”) pricing, whereaswhich historically our crude oil volumes sold were largely priced using either Light Louisiana Sweet (“LLS”), or MEH grade differentials. While both LLS and MEH have historicallyhas been at a premium to NYMEX WTI, LLS has hadWTI.
Similar to crude prices, natural gas prices have increased substantially and remain volatile as a more favorable differential than MEH.
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 Henry Hub (“NYMEX HH”)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“Results of Operations Realized DifferentialsDifferentials” that follows.
In addition to the volatility of commodity prices, we are subject to inflationary and other factors that could resulthave resulted in higher costs for products, materials and services that we utilize in both our capital projects and with respect to our operating expenses. Where possible, we have taken certain actionsWe 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.

28


costs but we have continued to experience higher costs and this may be exacerbated in the future.
Capital Expenditures, Development Progress and Production
We currently operateAs of September 30, 2022, we operated two drilling rigs and during the three and nine months ended September 30, 2021,2022, we incurred capital expenditures of approximately $60.0$362.6 million, and $182.8 million, respectively, substantially all of which $356.9 million was directed to drilling and completion projects. During the third quarter 2021,2022, a total of 1013 gross (9.2(12.4 net) wells were drilled, completed and turned in line. to sales.
As of October 29, 2021, we turned an additional two gross (1.9 net) wells in line and three gross (2.2 net) wells were completing and seven gross (6.2 net) wells were in progress.
Following the Lonestar acquisition on October 5, 2021,28, 2022, we had approximately 174,600183,800 gross (142,600(160,600 net) acres in the Eagle Ford, net of expirations, of which approximately 93%95% is held by production.
Total sales volume for the third quarter 20212022 was 2,3443,921 thousand barrels of oil equivalent (“Mboe”), or 25,48342,624 barrels of oil equivalent (“boe”) per day, with approximately 80%72%, or 1,8792,822 thousand barrels of oil (“Mbbls”Mbbl”), of sales volume from crude oil, 11%15% from NGLs and 9%13% from natural gas.




29


Commodity Hedging Program
As of October 29, 2021,28, 2022, we have hedged a portion of our estimated future crude oil, NGL and natural gas production from October 1, 20212022 through the first quarterhalf of 2024. The following table summarizes our net hedge positionsposition for the periods presented:
4Q211Q222Q223Q224Q221Q232Q233Q234Q231Q242Q244Q20221Q20232Q20233Q20234Q20231Q20242Q2024
NYMEX WTI Crude SwapsNYMEX WTI Crude SwapsNYMEX WTI Crude Swaps
Average Volume Per Day (bbl)Average Volume Per Day (bbl)6,215 3,250 3,000 3,000 3,000 2,500 2,400 2,807 2,657 462 308 Average Volume Per Day (bbl)4,630 2,500 2,400 2,807 2,657 462 462 
Weighted Average Swap Price ($/bbl)Weighted Average Swap Price ($/bbl)$72.76 $75.16 $74.12 $73.01 $69.20 $54.40 $54.26 $54.92 $54.93 $58.75 $58.75 Weighted Average Swap Price ($/bbl)$74.91 $54.40 $54.26 $54.92 $54.93 $58.75 $58.75 
NYMEX WTI Collars
NYMEX WTI Crude CollarsNYMEX WTI Crude Collars
Average Volume Per Day (bbl)Average Volume Per Day (bbl)16,304 15,417 12,775 7,745 6,114 2,917 2,885 Average Volume Per Day (bbl)21,875 17,083 11,126 8,152 4,891 
Weighted Average Purchased Put Price ($/bbl)Weighted Average Purchased Put Price ($/bbl)$51.40 $55.14 $52.90 $47.37 $45.33 $40.00 $40.00 Weighted Average Purchased Put Price ($/bbl)$66.09 $66.10 $61.48 $72.00 $70.00 
Weighted Average Sold Call Price ($/bbl)Weighted Average Sold Call Price ($/bbl)$62.23 $68.26 $71.14 $64.60 $60.87 $50.00 $50.00 Weighted Average Sold Call Price ($/bbl)$89.05 $82.08 $74.31 $89.91 $86.04 
NYMEX WTI Purchased Puts
Average Volume Per Day (bbl)3,261 
Weighted Average Purchased Put Price ($/bbl)$55.00 
NYMEX WTI Crude CMA Roll Basis SwapsNYMEX WTI Crude CMA Roll Basis SwapsNYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (bbl)Average Volume Per Day (bbl)11,957 10,000 9,890 3,261 3,261 Average Volume Per Day (bbl)3,804 
Weighted Average Swap Price ($/bbl)Weighted Average Swap Price ($/bbl)$0.17 $0.79 $0.79 $1.12 $1.12 Weighted Average Swap Price ($/bbl)$1.751 
NYMEX HH SwapsNYMEX HH SwapsNYMEX HH Swaps
Average Volume Per Day (MMBtu)Average Volume Per Day (MMBtu)20,700 17,500 12,500 12,500 12,500 10,000 7,500 Average Volume Per Day (MMBtu)12,500 10,000 7,500 
Weighted Average Swap Price ($/MMBtu)Weighted Average Swap Price ($/MMBtu)$3.530 $3.857 $3.342 $3.360 $3.408 $3.346 $3.325 Weighted Average Swap Price ($/MMBtu)$3.793 $3.620 $3.690 
NYMEX HH CollarsNYMEX HH CollarsNYMEX HH Collars
Average Volume Per Day (MMBtu)Average Volume Per Day (MMBtu)9,783 3,333 13,187 13,043 13,043 11,538 11,413 11,413 11,538 11,538 Average Volume Per Day (MMBtu)14,511 14,617 11,538 11,413 11,413 11,538 11,538 
Weighted Average Purchased Put Price($/MMBtu)$2.607 $4.150 $2.500 $2.500 $2.500 $2.500 $2.500 $2.500 $2.500 $2.328 
Weighted Average Purchased Put Price ($/MMBtu)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)Weighted Average Sold Call Price ($/MMBtu)$3.117 $5.750 $3.220 $3.220 $3.220 $2.682 $2.682 $2.682 $3.650 $3.000 Weighted Average Sold Call Price ($/MMBtu)$3.791 $12.334 $2.682 $2.682 $2.682 $3.650 $3.000 
NYMEX HH Sold Puts
Average Volume Per Day (MMBtu)6,522 
Weighted Average Sold Put Price ($/MMBtu)$2.000 
OPIS Mt Belv Ethane Swaps
OPIS Mt. Belv Ethane SwapsOPIS Mt. Belv Ethane Swaps
Average Volume per Day (gal)Average Volume per Day (gal)28,022 27,717 27,717 98,901 34,239 34,239 34,615 Average Volume per Day (gal)27,717 98,901 34,239 34,239 34,615 
Weighted Average Fixed Price ($/gal)Weighted Average Fixed Price ($/gal)$0.2500 $0.2500 $0.2500 $0.2288 $0.2275 $0.2275 $0.2275 Weighted Average Fixed Price ($/gal)$0.2500 $0.2288 $0.2275 $0.2275 $0.2275 



30



Results of Operations
The following table sets forth certain historical summary operating and financial statistics for the periods presented: 
Three Months EndedNine Months Ended
September 30,June 30,September 30,September 30,Three Months EndedNine Months Ended September 30,
20212021202020212020 September 30, 2022June 30, 2022September 30, 202120222021
Total sales volume (Mboe) 1
Total sales volume (Mboe) 1
2,344 2,261 2,235 6,453 6,909 
Total sales volume (Mboe) 1
3,921 3,502 2,344 10,821 6,453 
Average daily sales volume (boe/d) 1
Average daily sales volume (boe/d) 1
25,483 24,844 24,295 23,638 25,214 
Average daily sales volume (boe/d) 1
42,624 38,479 25,483 39,636 23,638 
Crude oil sales volume (Mbbl) 1
Crude oil sales volume (Mbbl) 1
1,879 1,831 1,691 5,179 5,291 
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
Crude oil sold as a percent of total 1
80 %81 %76 %80 %77 %
Crude oil sold as a percent of total 1
72 %71 %80 %72 %80 %
Product revenuesProduct revenues$140,133 $123,789 $68,614 $352,230 $204,300 Product revenues$304,105 $313,444 $140,133 $873,148 $352,230 
Crude oil revenuesCrude oil revenues$127,995 $116,314 $63,227 $326,222 $190,732 Crude oil revenues$262,537 $273,589 $127,995 $762,858 $326,222 
Crude oil revenues as a percent of totalCrude oil revenues as a percent of total91 %94 %92 %93 %93 %Crude oil revenues as a percent of total86 %87 %91 %87 %93 %
Realized prices:Realized prices:Realized prices:
Crude oil ($/bbl)Crude oil ($/bbl)$68.10 $63.54 $37.39 $62.99 $36.05 Crude oil ($/bbl)$93.03 $109.34 $68.10 $98.40 $62.99 
NGLs ($/bbl)NGLs ($/bbl)$27.24 $18.31 $9.20 $21.21 $6.86 NGLs ($/bbl)$31.97 $36.77 $27.24 $33.96 $21.21 
Natural gas ($/Mcf)Natural gas ($/Mcf)$4.11 $2.70 $1.80 $3.23 $1.73 Natural gas ($/Mcf)$7.41 $7.19 $4.11 $6.35 $3.23 
Aggregate ($/boe)Aggregate ($/boe)$59.77 $54.75 $30.70 $54.58 $29.57 Aggregate ($/boe)$77.55 $89.51 $59.77 $80.69 $54.58 
Realized prices, including effects of derivatives, net 2
Realized prices, including effects of derivatives, net 2
Realized prices, including effects of derivatives, net 2
Crude oil ($/bbl)Crude oil ($/bbl)$57.15 $52.70 $48.28 $52.08 $51.05 Crude oil ($/bbl)$83.14 $84.43 $57.15 $80.69 $52.08 
NGLs ($/bbl)NGLs ($/bbl)$25.77 $17.87 $9.20 $20.52 $6.86 NGLs ($/bbl)$30.67 $35.10 $25.77 $32.95 $20.52 
Natural gas ($/Mcf)Natural gas ($/Mcf)$3.44 $2.71 $1.88 $3.01 $1.86 Natural gas ($/Mcf)$4.26 $4.08 $3.44 $4.10 $3.01 
Aggregate ($/boe)Aggregate ($/boe)$50.49 $45.93 $38.99 $45.63 $41.14 Aggregate ($/boe)$67.76 $68.87 $50.49 $66.02 $45.63 
Production and lifting costs:Production and lifting costs:Production and lifting costs:
Lease operating ($/boe)Lease operating ($/boe)$4.54 $4.30 $3.70 $4.52 $4.04 Lease operating ($/boe)$6.15 $5.40 $4.54 $5.65 $4.52 
Gathering, processing and transportation ($/boe)Gathering, processing and transportation ($/boe)$2.43 $2.29 $2.58 $2.41 $2.43 Gathering, processing and transportation ($/boe)$2.50 $2.47 $2.43 $2.54 $2.41 
Production and ad valorem taxes ($/boe)Production and ad valorem taxes ($/boe)$3.21 $2.97 $1.95 $3.06 $1.90 Production and ad valorem taxes ($/boe)$4.26 $4.79 $3.21 $4.31 $3.06 
General and administrative ($/boe) 3
General and administrative ($/boe) 3
$4.66 $3.09 $3.84 $4.82 $3.45 
General and administrative ($/boe) 3
$2.51 $3.04 $4.66 $2.79 $4.82 
Depreciation, depletion and amortization ($/boe)Depreciation, depletion and amortization ($/boe)$13.21 $12.74 $16.57 $12.96 $16.63 Depreciation, depletion and amortization ($/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”Derivatives that follows).
3    Includes combined amounts of $1.56, $0.43$0.48, $0.71 and $1.20$1.55 per boe for the three months ended September 30, 20212022, June 30, 20212022 and September 30, 2020 and $1.82 and $0.65 per boe for the nine months ended September 30, 2021, and 2020, respectively, attributable to share-based compensation and significantcertain special charges, related to organizational restructuring andcomprised of acquisition, divestitureintegration 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.
31



Sequential Quarterly Analysis
The following summarizes our key operating and financial highlights for the three months ended September 30, 2021,2022, with comparison to the three months ended June 30, 2021.2022. The year-over-year highlights for the quarterly periods ended September 30, 20212022 and 20202021 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 marginally to 25,48342,624 boe per day from 24,84438,479 boe per day with 9.212.4 net wells turned in lineto sales for boththe third quarter 2021 and2022 compared to 12.3 net wells turned to sales for the second quarter 2021.2022. Total sales volume increased 4%12% to 2,3443,921 Mboe from 2,261 Mboe.3,502 Mboe primarily due to the recent acquisitions that closed in the third quarter of 2022.
Product revenues increased 13%decreased 3% to $140.1$304.1 million from $123.8$313.4 million as a result of 7%13% lower aggregate realized prices offset by 12% higher crudetotal sales volumes. Crude oil revenues were 4% lower due to 15% lower realized prices, or $8.6$46.0 million, coupled with slightlyoffset by 13% higher crude oil sales volume, or $3.1$35.0 million. NGL revenues were higher1% lower due to 49% higher13% lower realized prices, or $2.3$2.8 million, as well as 10%substantially offset by 14% higher total sales volume, or $0.4$2.7 million. Natural gas revenues were 61%9% higher as a result of 52%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 $16.3$33.9 million from $14.9$27.5 million primarily due to the effects of 12% higher sales volume and increased on a per unit basis to $6.97$8.65 per boe from $6.59$7.87 per boe primarily due primarily to the effects of slightly higher sales volume of 4%.increased workover activity.
Production and ad valorem taxes increaseddecreased on an absolute and per unit basis to $7.5$16.7 million and $3.21$4.26 per boe from $6.7$16.8 million and $2.97$4.79 per boe, respectively, due to the overall effects of 9% higher13% lower aggregate realized product pricing, partially offset by lower estimated ad valorem tax assessments.pricing.
General and administrative (“G&A”) expenses increaseddecreased on an absolute and per unit basis to $10.9$9.8 million and $4.66$2.51 per boe from $7.0$10.6 million and $3.09$3.04 per boe, respectively, primarily due to $2.7a $0.7 million of acquisition and integration costsdecrease in compensation cost associated with the Lonestar acquisition as well as higher employee share-based compensation costs.granted during second quarter 2022.
Depreciation, depletion and amortization (“DD&A”) increased to $31.0 millionon an absolute and increased on a per unit basis to $13.21$66.2 million and $16.88 per boe during the third quarter 20212022 as compared to $28.8$54.3 million and $12.74$15.50 per boe during the second quarter 20212022 due primarily to lower total proved reserves, partially offset by lowerhigher future development cost assumptions.

costs driven by inflation.

32


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: 
Total Sales Volume 1
Average Daily Sales Volume 1
2021 vs. 20202021 vs. 2020
Three Months Ended September 30,FavorableThree Months Ended September 30,Favorable
 20212020(Unfavorable)20212020(Unfavorable)
Crude oil (Mbbl and bbl/d)1,879 1,691 188 20,429 18,383 2,046 
NGLs (Mbbl and bbl/d)263 307 (44)2,860 3,338 (478)
Natural gas (MMcf and MMcf/d)1,211 1,421 (210)13 15 (2)
Total (Mboe and boe/d)2,344 2,235 109 25,483 24,295 1,188 
2021 vs. 20202021 vs. 2020
Nine Months Ended September 30,FavorableNine Months Ended September 30,Favorable
 20212020(Unfavorable)20212020(Unfavorable)
Crude oil (Mbbl and bbl/d)5,179 5,291 (112)18,972 19,309 (337)
NGLs (Mbbl and bbl/d)713 917 (204)2,611 3,347 (736)
Natural gas (MMcf and MMcf/d)3,367 4,206 (839)12 15 (3)
Total (Mboe and boe/d)6,453 6,909 (456)23,638 25,214 (1,576)
Three Months Ended September 30,Nine Months Ended September 30,
Total Sales Volume 1
20222021Change% Change20222021Change% 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
20222021Change% Change20222021Change% 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 were relatively flatincreased 67% and 68% during the third quarter 2021 as compared to the corresponding quarterthree and nine month periods in 2020 with 9.2 net wells turned in line in the current quarter 2021 period as compared to 4.8 net wells in the corresponding quarter in 2020. Total sales volume decreased 7% during the nine months ended September 30, 20212022, respectively, when compared to the corresponding periodperiods in 20202021 as a result of the temporary suspensionLonestar Acquisition that closed in fourth quarter of 2021, recent acquisitions that closed in the second and third quarters of 2022 and increased drilling program due to the global economic downturn associated with COVID-19 in 2020 as our overall production levels remained depressed in early 2021.activity.
Approximately 80%72% of total sales volume during the three and nine month periods in 20212022 was attributable to crude oil when compared to approximately 76%80% during the corresponding periods in 2020.2021. The increasedecrease in the crude oil composition of total sales volume is due primarily to drillinghigher gas content of the wells acquired in the oilier northern and eastern portions of our acreage holdings and focus on development plans with emphasis in such portions.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:
Total Product RevenuesProduct Revenues per Unit of Volume
2021 vs. 20202021 vs. 2020
Three Months Ended September 30,FavorableThree Months Ended September 30,Favorable
 20212020(Unfavorable)20212020(Unfavorable)
($ per unit of volume)
Crude oil$127,995 $63,227 $64,768 $68.10 $37.39 $30.71 
NGLs7,165 2,824 4,341 $27.24 $9.20 $18.04 
Natural gas4,973 2,563 2,410 $4.11 $1.80 $2.31 
Total$140,133 $68,614 $71,519 $59.77 $30.70 $29.07 
2021 vs. 20202021 vs. 2020
Nine Months Ended September 30,FavorableNine Months Ended September 30,Favorable
 20212020(Unfavorable)20212020(Unfavorable)
($ per unit of volume)
Crude oil$326,222 $190,732 $135,490 $62.99 $36.05 $26.94 
NGLs15,115 6,295 8,820 $21.21 $6.86 $14.35 
Natural gas10,893 7,273 3,620 $3.23 $1.73 $1.50 
Total$352,230 $204,300 $147,930 $54.58 $29.57 $25.01 

Three Months Ended September 30,Nine Months Ended September 30,
Total Product Revenues20222021Change% Change20222021Change% Change
Crude oil$262,537 $127,995 $134,542 105 %$762,858 $326,222 $436,636 134 %
NGLs18,669 7,165 11,504 161 %54,227 15,115 39,112 259 %
Natural gas22,899 4,973 17,926 360 %56,063 10,893 45,170 415 %
Total$304,105 $140,133 $163,972 117 %$873,148 $352,230 $520,918 148 %
Realized PricesThree Months Ended September 30,Nine Months Ended September 30,
($ per unit of volume)20222021Change% Change20222021Change% 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 %

33


The following table provides an analysis of the changes in our revenues for the periods presented:
Three Months Ended September 30, 2021 vs. 2020Nine Months Ended September 30, 2021 vs. 2020Three Months Ended September 30, 2022 vs. 2021Nine Months Ended September 30, 2022 vs. 2021
Revenue Variance Due toRevenue Variance Due toRevenue Variance Due toRevenue Variance Due to
VolumePriceTotalVolumePriceTotalVolumePriceTotalVolumePriceTotal
Crude oilCrude oil$7,038 $57,730 $64,768 $(4,014)$139,504 $135,490 Crude oil$64,198 $70,344 $134,542 $162,076 $274,560 $436,636 
NGLsNGLs(405)4,746 4,341 (1,403)10,223 8,820 NGLs8,740 2,764 11,504 18,747 20,365 39,112 
Natural gasNatural gas(379)2,789 2,410 (1,450)5,070 3,620 Natural gas7,719 10,207 17,926 17,667 27,503 45,170 
$6,254 $65,265 $71,519 $(6,867)$154,797 $147,930 $80,657 $83,315 $163,972 $198,490 $322,428 $520,918 
Our product revenues during the three and nine month periods in 20212022 increased compared to the corresponding periods in 20202021 due primarily to significantly higher prices stemming from macroeconomic factors and volatility in the global commodity markets as a result of continued economic recovery, followingas well as supply concerns resulting from the easing of COVID-19 restrictions as compared to the prior year thatRussia-Ukraine war. These factors resulted in increasesan increase to the NYMEX WTI benchmark price of 70%30% and 51% for the three and nine month periods in 2022, respectively, as well ascompared to the corresponding periods in 2021. Also contributing to the higher product revenues was an increase in volumes across all commodities as discussed above, with an overall increase in Mboe of 11% in crude oil volume in the three month period, partially offset by lower NGL67% and natural gas volume. Total crude oil revenues remain over 90% of our total product revenues during both the68% for three and nine month periods in 2021 and 2020.2022, respectively.
Realized Differentials
The following table reconciles our realized price differentials from average NYMEX-quoted prices for WTI crude oil and HH natural gas for the periods presented:
2021 vs. 20202021 vs. 2020Three Months Ended September 30,Nine Months Ended September 30,
Three Months Ended September 30,FavorableNine Months Ended September 30,Favorable20222021Change% Change20222021Change% Change
Average WTI prices ($/bbl)Average WTI prices ($/bbl)$91.43 $70.52 $20.91 30 %$98.25 $65.04 $33.21 51 %
Realized differential to WTIRealized differential to WTI1.60 (2.42)4.02 166 %0.15 (2.05)2.20 107 %
Realized crude oil prices ($/bbl)Realized crude oil prices ($/bbl)$93.03 $68.10 $24.93 37 %$98.40 $62.99 $35.41 56 %
20212020(Unfavorable)20212020(Unfavorable)
Realized crude oil prices ($/bbl)$68.10 $37.39 $30.71 $62.99 $36.05 $26.94 
Average WTI prices70.52 41.40 29.12 65.04 38.37 26.67 
Realized differential to WTI$(2.42)$(4.01)$1.59 $(2.05)$(2.32)$0.27 
Realized natural gas prices ($/Mcf)$4.11 $1.80 $2.31 $3.23 $1.73 $1.50 
Average HH prices ($/MMBtu)Average HH prices ($/MMBtu)4.27 1.95 2.32 3.52 1.82 1.70 Average HH prices ($/MMBtu)$7.96 $4.27 $3.69 86 %$6.66 $3.52 $3.14 89 %
Realized differential to HHRealized differential to HH$(0.16)$(0.15)$(0.01)$(0.29)$(0.09)$(0.20)Realized differential to HH(0.55)(0.16)(0.39)(244)%(0.31)(0.29)(0.02)(7)%
Realized natural gas prices ($/Mcf)Realized natural gas prices ($/Mcf)$7.41 $4.11 $3.30 80 %$6.35 $3.23 $3.12 97 %
Beginning in March 2020, the adverse impact of COVID-19 and instability in the global energy markets effectively eliminated our premium margin to the NYMEX WTI index price for crude oil. Average NYMEX WTI crude oil prices have rebounded as stabilization continued, with crude oil averaging approximately $70 per bbl for the third quarter 2021. Our differential to NYMEX WTI for the three and nine month periodperiods 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 2020 is primarily2021 due to the change during 2020 from selling our production volumes based on LLS and MEH pricing to selling fully based on MEH pricing. While both LLS and MEH have historically been at a premium to NYMEX WTI, MEH is less of a premium than LLS. Beginning in March 2020, average NYMEX HH prices were also impacted by COVID-19 and the overall industry instability noted above, as well as by the colder than normal weather during first quarter 2021 that affected most of the Lower 48 states and caused significant natural gas supply and demand imbalances. Recently, demand has rebounded while supply is constrained, causing a significant increase in natural gas prices compared to the prior year as noted in the table above.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, natural gas liquidsNGLs 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, natural gas liquidsNGLs 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”).

34


The following table presents the calculation of our non-GAAP realized prices for crude oil, natural gas liquidsNGLs and natural gas, as adjusted for the effects of derivatives, net and reconciles to realized prices for crude oil, natural gas liquidsNGLs and natural gas determined in accordance with GAAP: 
2021 vs. 20202021 vs. 2020
Three Months Ended September 30,FavorableNine Months Ended September 30,Favorable
20212020(Unfavorable)20212020(Unfavorable)
Three Months Ended September 30,Nine Months Ended September 30,
20222021Change% Change20222021Change% Change
Realized crude oil prices ($/bbl)Realized crude oil prices ($/bbl)$68.10 $37.39 $30.71 $62.99 $36.05 $26.94 Realized crude oil prices ($/bbl)$93.03 $68.10 $24.93 37 %$98.40 $62.99 $35.41 56 %
Effects of derivatives, net ($/bbl)Effects of derivatives, net ($/bbl)(10.95)10.89 (21.84)(10.91)15.00 (25.91)Effects of derivatives, net ($/bbl)(9.89)(10.95)1.06 10 %(17.71)(10.91)(6.80)(62)%
Crude oil realized prices, including effects of derivatives, net ($/bbl)Crude oil realized prices, including effects of derivatives, net ($/bbl)$57.15 $48.28 $8.87 $52.08 $51.05 $1.03 Crude oil realized prices, including effects of derivatives, net ($/bbl)$83.14 $57.15 $25.99 45 %$80.69 $52.08 $28.61 55 %
Realized natural gas liquid prices ($/bbl)Realized natural gas liquid prices ($/bbl)$27.24 $9.20 $18.04 $21.21 $6.86 $14.35 Realized natural gas liquid prices ($/bbl)$31.97 $27.24 $4.73 17 %$33.96 $21.21 $12.75 60 %
Effects of derivatives, net ($/bbl)Effects of derivatives, net ($/bbl)(1.47)— (1.47)(0.69)— (0.69)Effects of derivatives, net ($/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 ($/bbl)Natural gas liquids realized prices, including effects of derivatives, net ($/bbl)$25.77 $9.20 $16.57 $20.52 $6.86 $13.66 Natural gas liquids realized prices, including effects of derivatives, net ($/bbl)$30.67 $25.77 $4.90 19 %$32.95 $20.52 $12.43 61 %
Realized natural gas prices ($/Mcf)Realized natural gas prices ($/Mcf)$4.11 $1.80 $2.31 $3.23 $1.73 $1.50 Realized natural gas prices ($/Mcf)$7.41 $4.11 $3.30 80 %$6.35 $3.23 $3.12 97 %
Effects of derivatives, net ($/Mcf)Effects of derivatives, net ($/Mcf)(0.67)0.08 (0.75)(0.22)0.13 (0.35)Effects of derivatives, net ($/Mcf)(3.15)(0.67)(2.48)NM(2.25)(0.22)(2.03)NM
Natural gas realized prices, including effects of derivatives, net ($/Mcf)Natural gas realized prices, including effects of derivatives, net ($/Mcf)$3.44 $1.88 $1.56 $3.01 $1.86 $1.15 Natural gas realized prices, including effects of derivatives, net ($/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 included innetted within this caption as a contra-revenue item.caption.
The following table sets forth the total Other revenues,operating income, net recognized for the periods presented:
2021 vs. 20202021 vs. 2020
Three Months Ended September 30,FavorableNine Months Ended September 30,Favorable
 20212020(Unfavorable)20212020(Unfavorable)
Other operating income, net$928 $797 $131 $2,085 $1,972 $113 
Three Months Ended September 30,Nine Months Ended September 30,
 20222021Change% Change20222021Change% Change
Other operating income, net$985 $928 $57 %$2,888 $2,085 $803 39 %
Our marketing fees slightlyfee income increased in the three and nine month periods in 20212022, as compared to the corresponding periods in 20202021 due primarily to the higher commodity-based pricing and we recovered certain suspended revenues attributable to prior years during the 2021 periods. The increase was partially offset by lower water disposal fees inpricing. Additionally, the nine month period due to lowerin 2022 included a gain on sales volumes.

35


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 andfor gas lift, chemicals, water disposal, repairs and maintenance, including down-hole repairs, field labor, pumping and well-tending, equipment rentals, utilities and supplies, among others.
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The following table sets forth our LOE for the periods presented:
2021 vs. 20202021 vs. 2020
Three Months Ended September 30,FavorableNine Months Ended September 30,FavorableThree Months Ended September 30,Nine Months Ended September 30,
20212020(Unfavorable)20212020(Unfavorable) 20222021Change% Change20222021Change% Change
Lease operatingLease operating$10,647 $8,275 $(2,372)$29,200 $27,901 $(1,299)Lease operating$24,123 $10,647 $13,476 127 %$61,133 $29,200 $31,933 109 %
Per unit ($/boe)Per unit ($/boe)$4.54 $3.70 $(0.84)$4.52 $4.04 $(0.48)Per unit ($/boe)$6.15 $4.54 $1.61 35 %$5.65 $4.52 $1.13 25 %
% change per unit(22.7)%(11.9)%
LOE increased on an absolute basis and per unit basis during the three and nine month periodperiods in 2021 when2022 as compared to the corresponding periodperiods in 20202021 due primarily to higher variable coststhe impact of the Lonestar Acquisition and greater utilization of gas lift and lower maintenance costs as substantial work was completedrecent acquisitions that closed in the prior year during shut-in periods partially offsetsecond and third quarters of 2022, increased workovers and higher fuel, service and equipment costs driven by the effects of higher sales volumes in the three month period in 2021 and higher water disposal costs in the three month period in 2020 attributable to protective measures from offset stimulation activities. LOE also increased on an absolute and per unit basis during the nine month period in 2021 when compared to the corresponding period in 2020. The increases were due primarily to a combination of higher variable costs, higher gas lift costs, partially offset by continued cost-containment efforts and the application of operational improvementsvolume coupled with inflationary pressures throughout 2021.2022.
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:
2021 vs. 20202021 vs. 2020
Three Months Ended September 30,FavorableNine Months Ended September 30,Favorable Three Months Ended September 30,Nine Months Ended September 30,
20212020(Unfavorable)20212020(Unfavorable)20222021Change% Change20222021Change% Change
GPTGPT$5,688 $5,760 $72 $15,535 $16,797 $1,262 GPT$9,794 $5,688 $4,106 72 %$27,472 $15,535 $11,937 77 %
Per unit ($/boe)Per unit ($/boe)$2.43 $2.58 $0.15 $2.41 $2.43 $0.02 Per unit ($/boe)$2.50 $2.43 $0.07 %$2.54 $2.41 $0.13 %
% change per unit5.8 %0.8 %
GPT expense was relatively flatincreased on an absolute basis during the three and nine month periodperiods in 20212022 as compared to the corresponding periodperiods in 2020. GPT expense decreased2021 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 an absolute basisNYMEX 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 periodperiods in 20212022, as compared to the corresponding periodperiods in 2020 due primarily to lower gas2021, we incurred higher gathering costs attributableassociated with these volumes which caused an increase during the three and nine month periods in 2022 as compared to 20% lower natural gas sales volumes, as well asthe 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, resulting in lower transportation costs. These favorable variances were partially offset by higher costs associated with short-term rental charges with multiple vendors to temporarily store a portionincluding the majority of our crude oil production.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 a published index prices.

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The following table sets forth our production and ad valorem taxes for the periods presented:
2021 vs. 20202021 vs. 2020
Three Months Ended September 30,FavorableNine Months Ended September 30,Favorable
20212020(Unfavorable)20212020(Unfavorable)Three Months Ended September 30,Nine Months Ended September 30,
20222021Change% Change20222021Change% Change
Production/severance taxesProduction/severance taxes$6,589 $3,074 $(3,515)$16,608 $8,692 $(7,916)Production/severance taxes$14,121 $6,589 $7,532114 %$40,195 $16,608 $23,587 142 %
Ad valorem taxesAd valorem taxes945 1,294 349 3,160 4,460 1,300 Ad valorem taxes2,577 945 1,632173 %6,417 3,160 3,257 103 %
$7,534 $4,368 $(3,166)$19,768 $13,152 $(6,616)$16,698 $7,534 $9,164122 %$46,612 $19,768 $26,844 136 %
Per unit ($/boe)Per unit ($/boe)$3.21 $1.95 $(1.26)$3.06 $1.90 $(1.16)Per unit ($/boe)$4.26 $3.21 $1.05 33 %$4.31 $3.06 $1.25 41 %
Production/severance tax rate as a percent of product revenuesProduction/severance tax rate as a percent of product revenues4.7 %4.5 %4.7 %4.3 %Production/severance tax rate as a percent of product revenues4.6 %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 2021 when2022 as compared to the corresponding periods in 20202021 due primarily to the increasesimpact 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 induring the three and nine month periods in 2021. Our accruals for ad valorem taxes are based on our most recent estimates for assessments which reflect lower property values in 2021.2022.
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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 significant special charges that are generally attributable to material 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:
2021 vs. 20202021 vs. 2020Three Months Ended September 30,Nine Months Ended September 30,
Three Months Ended September 30,FavorableNine Months Ended September 30,Favorable20222021Change% Change20222021Change% Change
20212020(Unfavorable)20212020(Unfavorable)
Primary G&A$7,281 $5,913 $(1,368)$19,341 $19,322 $(19)
Primary G&A expensesPrimary G&A expenses$7,954 $7,281 $673 %$23,217 $19,341 $3,876 20 %
Share-based compensationShare-based compensation971 775 (196)4,179 2,582 (1,597)Share-based compensation1,354 971 383 39 %4,327 4,179 148 %
Significant special charges:Significant special charges:Significant special charges:
Organizational restructuring, including severanceOrganizational restructuring, including severance— 1,372 1,372 239 1,372 1,133 Organizational restructuring, including severance— — — — %— 239 (239)(100)%
Acquisition/integration, divestiture and strategic transaction costs2,680 525 (2,155)7,335 525 (6,810)
Total G&A$10,932 $8,585 $(2,347)$31,094 $23,801 $(7,293)
Acquisition/integration and strategic transaction costsAcquisition/integration and strategic transaction costs521 2,680 (2,159)(81)%2,699 7,335 (4,636)(63)%
Total G&A expensesTotal G&A expenses$9,829 $10,932 $(1,103)(10)%$30,243 $31,094 $(851)(3)%
Per unit ($/boe)Per unit ($/boe)$4.66 $3.84 $(0.82)$4.82 $3.45 $(1.37)Per unit ($/boe)$2.51 $4.66 $(2.15)(46)%$2.79 $4.82 $(2.03)(42)%
Per unit ($/boe) excluding share-based compensation and other significant special charges identified above$3.11 $2.65 $(0.46)$3.00 $2.80 $(0.20)
Per unit ($/boe) excluding share-based compensation and other special charges identified abovePer 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 primarytotal G&A expenses increasedwere lower on an absolute and per unit basis during the three month and nine month periods in 20212022 when compared to the corresponding periods in 2020. The increase for the three month period in 2021 compared to 2020 is 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 incentiveshare-based compensation costs. Primarycost.
Our primary G&A was relatively flatexpenses increased on an absolute basis during the three and nine month periodperiods in 20212022 as compared to the corresponding periodperiods in 2020.2021 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 1213 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements.” As a result of the Juniper Transactions, which qualified as a change-in-control event, all of the RSUs granted before 2019 vested as of the Juniper Closing Date in accordance with their terms. This resulted inand 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.
Our total G&A expenses were higher on an absolute and per unit basis during the three and nine month periods in 2021 as compared to the corresponding periods in 2020 due to higher overall incentive compensation and severance costs as well as
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acquisition and integration related costs associated with the Merger and Juniper Transactions, partially offset by lower organizational restructuring.
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:
2021 vs. 20202021 vs. 2020
Three Months Ended September 30,FavorableNine Months Ended September 30,FavorableThree Months Ended September 30,Nine Months Ended September 30,
20212020(Unfavorable)20212020(Unfavorable)20222021Change% Change20222021Change% Change
DD&A expenseDD&A expense$30,975 $37,038 $6,063 $83,654 $114,891 $31,237 DD&A expense$66,204 $30,975 $35,229 114 %$171,387 $83,654 $87,733 105 %
DD&A rate ($/boe)DD&A rate ($/boe)$13.21 $16.57 $3.36 $12.96 $16.63 $3.67 DD&A rate ($/boe)$16.88 $13.21 $3.67 28 %$15.84 $12.96 $2.88 22 %
DD&A decreasedexpense increased on an absolute and a per unit basis during the three and nine month periods in 2021 when2022 as compared to the corresponding periods in 2020. Lower2021. Higher production volume provided for decreasesan increase of $7.6$20.8 million and lower$56.6 million and a higher DD&A ratesrate resulted in decreasesan increase of $23.7$14.4 million and $31.2 million, for the three and nine month periods in the first nine months of 2021.2022, respectively. The lowerhigher DD&A rate in 20212022 is primarily attributabledue to the effect of adding additional reserves in 2021 as well as the effect of the impairments recordedLonestar Acquisition and recent acquisitions that closed in the latter partsecond and third quarters of 2020 and2022, which contributed to an increase in our total proved reserves at a higher relative cost per boe as compared to the first quartercorresponding periods in 2021.
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Impairment of Oil and Gas Properties
We assess our oil and gas properties on a quarterly basis based on the results of a comparison of the unamortized cost of our oil and gas properties, net of deferred income taxes, to the sum of our estimated after-tax discounted future net revenues from proved properties adjusted for costs excluded from amortization (the “Ceiling Test”) in accordance with the full cost method of accounting for oil and gas properties.
2021 vs. 20202021 vs. 2020
Three Months Ended September 30,FavorableNine Months Ended September 30,Favorable
20212020(Unfavorable)20212020(Unfavorable)
Impairment of oil and gas properties$— $235,989 $235,989 $1,811 $271,498 $269,687 
We did not record an impairment of our oil and gas properties during the three month period in 2021, compared to an impairment of $236.0 million recorded in the corresponding period in 2020. During theand nine month periodperiods in 2021, we2022. We recorded an impairment of $1.8 million compared to the $271.5 million recorded in the nine month periodmonths ended September 30, 2021 as a result of capitalized costs of oil and gas properties exceeding the ceiling test in 2020. These impairments werethe 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 and Second Lien Facility derived from internationally-recognizedinternationally 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. Also included is the accretion of original issue discount (“OID”) on the Second Lien Facility and the amortization of issuance costs capitalized attributable to the Credit Facility and the Second Lien Facility. 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. Amortization of issuance costs and OID on the 9.25% Senior Notes due 2026 are excluded as of September 30, 2021 as the proceeds and accrued interest were held in escrow contingent upon the closing of the Lonestar acquisition which occurred subsequent to the period end.

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The following table summarizes the components of our interest expense for the periods presented:
2021 vs. 20202021 vs. 2020
Three Months Ended September 30,FavorableNine Months Ended September 30,FavorableThree Months Ended September 30,Nine Months Ended September 30,
20212020(Unfavorable)20212020(Unfavorable)20222021Change% Change20222021Change% Change
Interest on borrowings and related feesInterest on borrowings and related fees$10,936 $7,375 $(3,561)$22,101 $22,944 $843 Interest on borrowings and related fees$13,361 $10,936 $2,425 22 %$35,608 $22,101 $13,507 61 %
Accretion of original issue discountAccretion of original issue discount84 205 121 274 602 328 Accretion of original issue discount168 84 84 100 %493 274 219 80 %
Amortization of debt issuance costsAmortization of debt issuance costs479 594 115 1,468 2,734 1,266 Amortization of debt issuance costs705 479 226 47 %2,051 1,468 583 40 %
Capitalized interestCapitalized interest(917)(677)240 (2,561)(2,067)494 Capitalized interest(1,074)(917)(157)17 %(3,257)(2,561)(696)27 %
Total interest expense, net of capitalized interestTotal interest expense, net of capitalized interest$10,582 $7,497 $(3,085)$21,282 $24,213 $2,931 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 20212022 is substantiallyprimarily attributable to interest incurred in the amount of $5$9.2 million for the 9.25% Senior Notes due 2026. This is2026 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 decreasedincreased 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 Second Lien Facility$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 three and nine month periodsperiod in 20212022, driven by higher overall weighted-average interest rates in 2022 as compared to the corresponding periods in 2020 due primarily to the effect of lower outstanding balances during the three and nine month periods in 2021 and lower interest rates associated with the Credit Facility, resulting from lower applicable margins based on lower utilization levels. The weighted-average balances under the Credit Facility were lower in the three and nine month periods in 2021 by approximately $109 million and $125 million, respectively. The weighted-average interest rates during the same periods were lower by 47 basis points. The accretion of OID is entirely attributable to the Second Lien Facility and the amortization of debt issuance costs includes amounts attributable to both the Credit Facility and Second Lien Facility. We capitalized a larger portion of interest during the three and nine month periods in 2021 as we maintained a higher portion of unproved property as compared to the corresponding period in 2020 due primarily to the property contribution from the Juniper Transactions coupled with the impact of additional interest related to the 9.25% Senior Notes due 2026.2021.

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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:
2021 vs. 20202021 vs. 2020
Three Months Ended September 30,FavorableNine Months Ended September 30,FavorableThree Months Ended September 30,Nine Months Ended September 30,
20212020(Unfavorable)20212020(Unfavorable)20222021Change% Change20222021Change% Change
Commodity derivative gains (losses)Commodity derivative gains (losses)$(21,000)$(6,923)$(14,077)$(119,631)$117,406 $(237,037)Commodity derivative gains (losses)$63,756 $(21,000)$84,756 (404)%$(149,137)$(119,631)$(29,506)25 %
Interest rate swap gains (losses)Interest rate swap gains (losses)(84)32 (116)(48)(7,527)7,479 Interest rate swap gains (losses)— (84)84 (100)%64 (48)112 (233)%
Total
Total
$(21,084)$(6,891)$(14,193)$(119,679)$109,879 $(229,558)Total$63,756 $(21,084)$84,840 (402)%$(149,073)$(119,679)$(29,394)25 %
In the three and nine month periods in 2021,2022, commodity prices recovered to levels that were significantly higher on an average aggregate basis than those during the corresponding periods in 2020. Accordingly,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. The effect in the three and nine month periods in 2020 was in the opposite direction as the mark-to-market gains associated were attributable to the substantial collapse in pricespositions for the underlying commodities relative to our hedged positions. In the second quarter 2021, we began hedging a portion of our NGL production. 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, as compared to realized settlement receipts, net of $7.3 million and $66.6 million during the three and nine month periods in 2020, respectively. In 2020,Through May 2022, we began hedginghedged a portion of our exposure to variable interest rates associated with our Credit Facility and, Second Lien Facility. Forin the three and nine month periods in 2021, our Second Lien Term Loan. As of September 30, 2022, we paid $1.0 million and $2.9 million, respectively, of net settlements from ourdid not have any interest rate swaps. For the three and nine month periods in 2020, wederivatives. We paid $0.9 and $1.3$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.

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The following table summarizes our income taxes for the periods presented:
2021 vs. 20202021 vs. 2020Three Months Ended September 30,Nine Months Ended September 30,
Three Months Ended September 30,FavorableNine Months Ended September 30,Favorable 20222021Change% Change20222021Change% Change
20212020(Unfavorable)20212020(Unfavorable)
Income tax (expense) benefit$(549)$1,558 $(2,107)$(410)$1,110 $(1,520)
Income tax expenseIncome tax expense$(2,052)$(549)$(1,503)274 %$(3,171)$(410)$(2,761)673 %
Effective tax rateEffective tax rate1.3 %0.6 %1.3 %0.6 %Effective tax rate0.9 %1.3 %(0.4)%(31)%0.9 %1.3 %(0.4)%(31)%
The income tax provision resulted in an expense of $0.5$2.1 million and $0.4an expense of $3.2 million for the three and nine months ended September 30, 2021,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 1.3%0.9%, which is fully attributable to the State of Texas. In connection with the Juniper Transactions, we recorded an adjustment of $0.7 million to Paid-in capital (see Note 3 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information) attributable to certain state deferred income tax effects associated with the change in legal entity structure. Our net deferred income tax liability balance of $0.8$5.0 million as of September 30, 20212022 is also fully attributable to the State of Texas and primarily related to property.
We recognized a federal and stateThe income tax benefitprovision resulted in an expense of $1.6$0.5 million and $1.1an expense of $0.4 million for the three and nine months ended September 30, 2020,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 0.6%1.3% which was fully attributable to the State of Texas. The provision also reflected a reclassification of $1.2 million from deferred tax assets to current income taxes receivable for certain refundable alternative minimum tax credit carryforwards that were later received in June 2020.
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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, 2021,2022, we had liquidity of $172.0$304.6 million, comprised of cash and cash equivalents of $35.3$20.3 million and availability under our Credit Facility of $136.7$284.3 million (factoring in letters of credit), and excludes $15.4 million restricted cash -. The Credit Facility provides us up to $1.0 billion in borrowing commitments. The current representing escrowed accrued interest and an amount equivalent to the original issue discount for the 9.25% Senior Notes due 2026 which funds were subsequently released upon closing of the Merger. Additionally, following the closing of the Merger in connection with the Eleventh Amendment (as defined below), the borrowing base under the Credit Facility was increased to $600is $950.0 million with aggregate elected commitments of $400$500.0 million.
On August 10, 2021, our indirect, wholly-owned subsidiary Penn Virginia Escrow LLC (the “Escrow Issuer”) completed an offering of $400 million aggregate principal amount of the 9.25% Senior Notes due 2026 which bear interest at 9.25% and were sold at 99.018% of par. The gross proceeds of the offering and other funds had initially been deposited in an escrow account pending satisfaction of certain conditions, including the consummation of the Merger. At September 30, 2021, the gross proceeds plus accrued interest and original issue discount were held in escrow. Upon the closing of the Merger, Holdings assumed all obligations under the 9.25% Senior Notes due 2026 and the net proceeds and certain other funds were released from escrow and used to repay and discharge certain long-debt of Lonestar including accrued interest and related expenses, and the remainder, along with cash on hand, was used to repay the Second Lien Facility including a prepayment premium, accrued interest and related expenses. See Note 14 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information.
Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for crude oil, NGLNGLs and natural gas, products, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity and other supply chain dynamics, among other factors. All of these factors have been negatively impacted by the continuingvolatility 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.markets, as well as inflationary pressures and recession fears that impact demand. In order to mitigate this volatility, we are extensively utilizingutilize 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 2023.2024. 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.
We continually evaluate potential sales of assets, including certain non-strategic oil and gas properties and undeveloped acreage, among others. Additionally, from time-to-timeFrom 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.

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Capital Resources
Our 2021 capital budget contemplatesWe expect full year 2022 drilling and completions capital expenditures from $240 to $270 million, of which $235 to $265 million has been allocated to drillingbetween $507 and completion activities.$527 million. We plan to continue to fund our 20212022 capital program and our operations for the next twelve months primarily with cash on hand, cash from operating activities and, to the extent necessary, supplemental borrowings under the Credit Facility. Based upon current price and production expectations, we believe that our cash on hand, cash from operating activities and borrowings under our Credit Facility, as necessary, will be sufficient to fund our capital spending and operations for at least the next twelve months; however, future cash flows are subject to a number of variables including the length and magnitude of the current global economic uncertainties associated with the COVID-19 pandemiccontinued 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.

40


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,September 30,Nine Months Ended September 30,
20212020 20222021
Net cash provided by operating activitiesNet cash provided by operating activities204,084 189,723 Net cash provided by operating activities$489,182 $204,707 
Net cash used in investing activitiesNet cash used in investing activities(146,481)(138,927)Net cash used in investing activities(426,650)(146,481)
Net cash provided by (used in) financing activities376,146 (38,078)
Net increase in cash, cash equivalents and restricted cash$433,749 $12,718 
Net cash (used in) provided by financing activitiesNet cash (used in) provided by financing activities(65,869)375,523 
Net increase (decrease) in cash, cash equivalents and restricted cashNet increase (decrease) in cash, cash equivalents and restricted cash$(3,337)$433,749 
Cash Flows from Operating Activities. Activities. The increase of $14.4$284.5 million in net cash provided by operating activities for the nine months ended September 30, 20212022 compared to the corresponding period in 20202021 was primarily attributable to the effect of 2022 cash receipts that were derived from higher average commodity prices in 2021, as well as lower interest payments, net of interest rate swap settlements in the 2021 period as compared to 2020,and higher total sales volume, partially offset by (i) the effects of lower total sales volume (ii) higher net payments for commodity derivatives settlements and premiums, (iii)premiums. Additionally, during the nine months ended September 30, 2021, there were higher acquisition, integration and strategic transaction costs paid in connection with the Juniper Transactions and Lonestar acquisition and integration costs and (iv) 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, 20212022 as compared to the corresponding period in 2020,2021, 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 and completion program during a portion ofthat began in 2020 as a result ofdue to the COVID-19 pandemic and related market instability.global economic downturn associated with COVID-19.

41


The following table sets forth costs related to our capital expenditures program for the periods presented:
Nine Months Ended
September 30,September 30,Nine Months Ended September 30,
20212020 20222021
Drilling and completionDrilling and completion$181,144 $93,443 Drilling and completion$356,883 $181,144 
Lease acquisitions, land-related costs, and geological and geophysical (seismic) costsLease acquisitions, land-related costs, and geological and geophysical (seismic) costs2,315 3,317 Lease acquisitions, land-related costs, and geological and geophysical (seismic) costs4,806 2,315 
Pipeline, gathering facilities and other equipment, net 1
Pipeline, gathering facilities and other equipment, net 1
(632)1,221 
Pipeline, gathering facilities and other equipment, net 1
890 (632)
Total capital expenditures incurred Total capital expenditures incurred$182,827 $97,981 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,September 30,Nine Months Ended September 30,
20212020 20222021
Total capital expenditures program costs (from above)Total capital expenditures program costs (from above)$182,827 $97,981 Total capital expenditures program costs (from above)$362,579 $182,827 
Decrease (increase) in accounts payable for capital items and accrued capitalized costs(30,303)30,579 
Increase in accounts payable for capital items and accrued capitalized costsIncrease in accounts payable for capital items and accrued capitalized costs(55,008)(30,303)
Net purchases of tubular inventory and well materials 1
Net purchases of tubular inventory and well materials 1
1,858 3,441 
Net purchases of tubular inventory and well materials 1
1,712 1,858 
Prepayments for drilling and completion services, net of (transfers)Prepayments for drilling and completion services, net of (transfers)(12,653)3,613 Prepayments for drilling and completion services, net of (transfers)(8,762)(12,653)
Capitalized internal labor, capitalized interest and otherCapitalized internal labor, capitalized interest and other4,909 3,396 Capitalized internal labor, capitalized interest and other7,245 4,909 
Total cash paid for capital expendituresTotal cash paid for capital expenditures$146,638 $139,010 Total cash paid for capital expenditures$307,766 $146,638 

_______________________
1    Includes purchases made in advance of drilling.
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Cash Flows from Financing Activities. In JanuaryDuring 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 Common Units and Series A Preferred Stockequity 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 Facility, respectively. The remainder of the proceeds were used to pay: (i) $3.8 million of issue costs associated with the redeemable securities (Common UnitsTerm Loan, respectively and Series A Preferred Stock), (ii) $5.5pay $9.3 million of transaction costs attributable to Juniper’s Noncontrolling interest, (iii) $1.8 million ofand issue costs associated with the amendmentsrelated to the Credit Facility and Second Lien Facility in connection with the Juniper Transactions, (iv) $1.3 million to liquidate outstanding Second Lien Facility advances attributable to a single participant lender and (v) a portion of interest payments and other Juniper Transactions costs, both of which are presented as cash disbursements included in net cash provided by operating activities above.Juniper. The nine months ended September 30, 2021 also includes additional net repayments of $21.0 million under the Credit Facility and $5.6 million quarterly amortization payments under the Second Lien FacilityTerm Loan as well as $396.1 million net proceeds received from the 9.25% Senior Notes due 2026. The nine months ended September 30, 2020 includes borrowings of $51.0 million and repayments of $89.0 million under the Credit Facility which were used to fund a portion of the capital program at the beginning of 2020.
Capitalization
The following table summarizes our total capitalization as of the dates presented:
September 30,December 31,September 30, 2022December 31, 2021
20212020
Credit facility$212,900 $314,400 
Second lien facility, net139,133 195,097 
9.25 Senior Notes due 2026, net394,795 — 
Credit FacilityCredit Facility$215,000 $208,000 
9.25% Senior Notes due 2026, net9.25% Senior Notes due 2026, net388,214 386,427 
Mortgage debt 1
Mortgage debt 1
— 8,438 
Other 2
Other 2
284 2,516 
Total debt, netTotal debt, net746,828 509,497 Total debt, net603,498 605,381 
Total equityTotal equity426,590 212,838 Total equity964,532 669,508 
$1,173,418 $722,335 
Total capitalizationTotal capitalization$1,568,030 $1,274,889 
Debt as a % of total capitalizationDebt as a % of total capitalization64 %71 %Debt as a % of total capitalization38 %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, 2021,2022, the Credit Facility had a $1.0 billion revolving commitment and a $375an $950 million borrowing base, includingwith 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 generally 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. Prior to the Eleventh Amendment (as defined below), the Credit Facility was scheduled to mature in May 2024. We had $0.4$0.7 million and $0.9 million in letters of credit outstanding as of September 30, 20212022 and December 31, 2020.2021, respectively. The maturity date under the Credit Facility is October 6, 2025.
42


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 the London interbank offered rate (“LIBOR”) through 2021,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, including LIBOR,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, 2021,2022, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 3.09%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 PeriodWeighted-
Average
MaximumWeighted-
Average Rate
Three months ended September 30, 2021$212,900 $233,818 $238,900 3.10 %
Nine months ended September 30, 2021$212,900 $241,206 $314,400 3.13 %
 Borrowings Outstanding 
End of PeriodWeighted-
Average
MaximumWeighted-
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, effective upon the Eleventh Amendment, which holds real estate assets that are associated with Lonestar’s legacy mortgage obligations.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.
In9.25% Senior Notes due 2026. On August 10, 2021, we entered into the Master Assignment, Agreement and Amendment No. 11 to Credit Agreement (the “Eleventh Amendment”). The Eleventh Amendment, in addition to other changes described therein, amended the Credit
42


Facility to, effective on the closing of the Merger, (1) increase the borrowing base under to $600 million, with aggregate elected commitmentsour indirect, wholly-owned subsidiary completed an offering of $400 million (2) remove certain availability restrictions, (3) remove minimum hedging requirements, (4) remove the first lien leverage ratio covenant, (5) remove the Partnershipaggregate principal amount of senior unsecured notes due 2026 (the “9.25% Senior Notes due 2026”) that bear interest at 9.25% and PV Energy Holdings GP, LLC as guarantors, and (6) extend the maturity date to the date that is the four year anniversarywere sold at 99.018% of the date such amendment became effective, or October 6, 2025.
Second Lien Facility. On October 5, 2021, Holdings repaid all of its outstanding obligationspar. Obligations under the Second Lien Facility,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 terminatedare guaranteed by the Second Liensubsidiaries of Holdings that guarantee the Credit Facility. In accordance with the Second Lien Facility, we incurred a prepayment premium of 102% as a result of repayment.
Covenant Compliance. As of September 30, 2021, theThe Credit Facility requiredrequires 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. and (3) a maximum first lien leverage ratio (consolidated secured 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 2.50 to 1.00.
The Credit Facility also containsand the indenture governing the 9.25% Senior Notes due 2026 contain customary affirmative and negative covenants including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens and indebtedness, merger, consolidation or sale of assets, payment of dividends, and transactions with affiliates and other customary covenants. In addition,well as of September 30, 2021, the Credit Facility contained certain anti-cash hoarding provisions. See Note 14 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information.
The Credit Facility contains 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, 2021,2022, we were in compliance with all of the covenants under the Credit Facility and the Second Lien Facility.debt covenants.
See Note 147 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information on our debt, including the 9.25% Senior Notes due 2026.debt.

Off Balance Sheet Arrangements
As of September 30, 2021, we had no off-balance sheet arrangements other than information technology licensing, service agreements, in-kind commodity recovery arrangements for imbalances and letters of credit, all of which are customary in our business.
Critical Accounting Estimates
The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”)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, 2020.2021.
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. The carrying value of our proved oil and gas properties exceeded the limit determined by the Ceiling Test as of March 31, 2021, resulting in a $1.8 million impairment. There wasWe had no such impairmentimpairments of our proved oil and gas properties during the second or third quarters of 2021.2022.
43



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, 2021,2022, we had variable-rate borrowings of $212.9$215.0 million under the Credit Facility, $143.1 million under the Second Lien Facility and fixed-rate borrowings of $400.0 million for the 9.25% Senior Notes due 2026 at interest rates of 3.09%, 10.50%,5.63% and 9.25%, respectively. On October 5, 2021, the Second Lien Facility was repaid in full and terminated upon closing of the Lonestar acquisition. 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 $2.1$2.2 million on an annual basis, excluding the offsetting impact of our interest rate swap derivatives.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, 2021,2022, our commodity derivative portfolio was in a net liability position in the amount of $74.9$51.2 million. The contracts associated with this position are with nineseven 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, 2021,2022, we reported a net commodity derivative loss of $119.6$149.1 million. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our derivative instruments. Our results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which fluctuate with changes in crude oil, NGL and natural gas prices. These fluctuations could be significant in a volatile pricing environment. See Note 5 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for a further description of our commodity price risk management activities.
The following table illustrates the estimated impact on the fair values of our derivative financial instruments and operating income attributable to hypothetical changes in the underlying commoditycrude oil prices. This illustration assumes that crude oil production volumes, NGL prices and production volumes, and natural gas prices and production volumes remain constant at anticipated levels. The estimated changes in operating income exclude potential cash receipts or payments in settling these derivative positions.
Change of 10% per bbl of  Crude Oil
($ in millions)
Change of 10% per bbl of
Crude Oil
($ in millions)
IncreaseDecrease IncreaseDecrease
Effect on the fair value of crude oil derivatives 1
Effect on the fair value of crude oil derivatives 1
$(36.4)$26.7 
Effect on the fair value of crude oil derivatives 1
$(37.4)$37.8 
Effect of crude oil price changes for the remainder of 2021 on operating income, excluding derivatives 2
$20.3 $(15.4)
Effect of crude oil price changes for the remainder of 2022 on operating income, excluding derivatives 2
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, 2021.2022.
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, 2021.2022. 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, 2021,2022, such disclosure controls and procedures were effective.
(b) Changes in Internal Control Over Financial Reporting
During the quarter ended September 30, 2021,2022, 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, 20202021 and in Part II, Item 1A of our Quarterly ReportReports on Form 10-Q for the quarterquarterly periods ended March 31, 2022 and June 30, 2021.2022.
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:
PeriodTotal Number of Shares RepurchasedAverage Price Paid Per UnitTotal 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, 2022672,985$30.57 672,985$94,416,322 
August 1, 2022 - August 31, 2022202,800$37.14 202,800$86,883,893 
September 1, 2022 - September 30, 2022199,175$34.74 199,175$79,964,948 
Total1,074,960$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
(3.1)
Fourth Amended and Restated Articles of Incorporation of Ranger Oil Corporation,26, 2022 but made effective as of October 6, 2021 (incorporatedJuly 1, 2022, by referenceand between Ironwood Shiner Pipeline, LLC, as successor to Exhibit 3.1Nuevo Dos Gathering and Transportation, LLC, as successor to Registrant’s Current Report on Form 8-K filed on October 7, 2021).
(3.2)
Articles of Amendment, dated as of October 14, 20221, to the Fourth AmendedRepublic Midstream, LLC and Restated Articles of Incorporation of Ranger Oil Corporation (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on October 19, 2021).
(3.3)
Seventh Amended and Restated Bylaws of Ranger Oil Corporation, effective as of October 6, 2021 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed on October 7, 2021).
(3.4)
Amendment to the Seventh Amended and Restated Bylaws of Ranger Oil Corporation, effective October 14, 2021 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed on October 19, 2021).
(4.1)
Indenture, dated as of August 10, 2021 among Penn Virginia Escrow LLC, the guarantors party thereto and Citibank, N.A., as Trustee (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed on August 13, 2021).
Form of 9.250% Senior Note due 2026 (included as Exhibit A to Exhibit 4.1).
SupportCredit Agreement, dated as of July 10, 2021, by and between Lonestar Resources US Inc. and the shareholders of Penn Virginia set forth on Schedule A thereto (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on July 13, 2021).
Purchase Agreement, dated JulySeptember 27, 2021, by and2022, among Penn Virginia Escrow LLC, Penn VirginiaROCC Holdings, LLC, as borrower, Ranger Oil Corporation, as holdings, the guarantors named thereinsubsidiaries of holdings party thereto, certain lenders party thereto, and B of A Securities, Inc.,Wells Fargo Bank, National Association, as Representative ofadministrative agent for the several initial purchaserslenders and as an issuing lender (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on July 29, 2021)September 28, 2022).
Amendment No. 10 to the Credit Agreement
Master Assignment, Agreement and Amendment No. 11 to the Credit Agreement, entered into and dated as of August 18, 2021, among Penn Virginia Holdings, LLC, as borrower, Penn Virginia Corporation, as holdings, certain subsidiaries of holdings party thereto, certain lenders party thereto, Wells Faro Ban,m National Association, as administrative agent for the lenders an as an issuing lender, Citibank, N.A., as the issuer of certain letters of credit and such other persons identified as a “New Lender” on the signature pages thereto (incorporated by references to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on August 24, 2021).
(31.1) *
Certification Pursuant to Rule 13a-14(a), as Adopted Pursuant to Section 302 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, 2021,2022, formatted in Inline XBRL (included within the Exhibit 101 attachments).
_____________________________
*    Filed herewith.
**    Furnished herewith.
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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 4, 20213, 2022By:/s/ RUSSELL T KELLEY, JR.
  Russell T Kelley, Jr.
  Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
   
November 4, 20213, 2022By: /s/ KAYLA D. BAIRD
  Kayla D. Baird
  Vice President, Chief Accounting Officer and Controller
(Principal Accounting Officer)




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