BAYTEX ENERGY USA, INC. - Quarter Report: 2021 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________________________

FORM 10-Q

_______________________________________________________

(Mark One)


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

For the quarterly period ended September 30, 2021


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

For the transition period from to

Commission file number: 1-13283

RANGER OIL CORPORATION

(Exact name of registrant as specified in its charter)

__________________________________________________________


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

16285 PARK TEN PLACE, SUITE 500

HOUSTON, TX 77084

(Address of principal executive offices) (Zip Code)

(713) 722-6500

(Registrant’s telephone number, including area code)

Penn Virginia Corporation

(Former names or former address, if changed since last report)

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Class A Common Stock, $0.01 Par Value

ROCC

The Nasdaq Stock Market LLC

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 (“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 Filer

☐

Accelerated Filer

☒

Non-accelerated Filer

☐

Smaller Reporting Company

☒

Emerging Growth Company

☐

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

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

As of October 29, 2021, there were 43,637,251 shares of common stock outstanding, including 21,088,253 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, 2021

Table of Contents


Part I - Financial Information
Item		Page
1.	Financial Statements - unaudited
	Condensed Consolidated Statements of Operations	3
	Condensed Consolidated Statements of Comprehensive Income (Loss)	4
	Condensed Consolidated Balance Sheets	5
	Condensed Consolidated Statements of Cash Flows	6
	Condensed Consolidated Statements of Equity	7
	Notes to Condensed Consolidated Financial Statements:
	1. Nature of Operations	8
	2. Basis of Presentation	8
	3. Juniper Transactions	8
	4. Revenue Recognition	10
	5. Derivative Instruments	11
	6. Property and Equipment	14
	7. Long-Term Debt	14
	8. Income Taxes	16

	9. Supplemental Balance Sheet Detail	17
	10. Fair Value Measurements	18
	11. Commitments and Contingencies	19

	12. Share-Based Compensation and Other Benefit Plans	20

	13. Earnings per Share	22
	14. Subsequent Events	23
Forward-Looking Statements		24
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Overview and Executive Summary	26

	Results of Operations	31
	Liquidity and Capital Resources	40
	Off Balance Sheet Arrangements	43
	Critical Accounting Estimates	43
3.	Quantitative and Qualitative Disclosures About Market Risk	44
4.	Controls and Procedures	45
Part II - Other Information
1.	Legal Proceedings	45
1A.	Risk Factors	45
5.	Other Information	45
6.	Exhibits	46
Signatures		47

Part I. FINANCIAL INFORMATION

Item 1. Financial Statements

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – unaudited

(in thousands, except per share data)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Revenues and other
Crude oil	$	127,995	$	63,227	$	326,222	$	190,732
Natural gas liquids	7,165		2,824		15,115		6,295
Natural gas	4,973		2,563		10,893		7,273
Other operating income, net	928		797		2,085		1,972
Total revenues and other	141,061		69,411		354,315		206,272
Operating expenses
Lease operating	10,647		8,275		29,200		27,901
Gathering, processing and transportation	5,688		5,760		15,535		16,797
Production and ad valorem taxes	7,534		4,368		19,768		13,152
General and administrative	10,932		8,585		31,094		23,801
Depreciation, depletion and amortization	30,975		37,038		83,654		114,891
Impairments of oil and gas properties	—		235,989		1,811		271,498
Total operating expenses	65,776		300,015		181,062		468,040
Operating income (loss)	75,285		(230,604)		173,253		(261,768)
Other income (expense)
Interest expense, net of amounts capitalized	(10,582)		(7,497)		(21,282)		(24,213)
Loss on extinguishment of debt	—		—		(1,231)		—
Derivatives	(21,084)		(6,891)		(119,679)		109,879
Other, net	(7)		21		(13)		(42)
Income (loss) before income taxes	43,612		(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)
Net income attributable to Noncontrolling interest	(25,676)		—		(23,778)		—
Net income (loss) attributable to common shareholders	$	17,387	$	(243,413)	$	6,860	$	(175,034)
Net income (loss) per share:
Basic	$	1.13	$	(16.03)	$	0.45	$	(11.54)
Diluted	$	1.11	$	(16.03)	$	0.44	$	(11.54)

Weighted average shares outstanding – basic	15,319		15,183		15,298		15,168
Weighted average shares outstanding – diluted	15,713		15,183		15,669		15,168

See accompanying notes to condensed consolidated financial statements.

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) – unaudited

(in thousands)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Net income (loss)	$	43,063	$	(243,413)	$	30,638	$	(175,034)
Other comprehensive income (loss):
Change in pension and postretirement obligations, net of tax	1		(2)		4		(4)
	1		(2)		4		(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)

See accompanying notes to condensed consolidated financial statements.

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands, except share data)


	September 30,		December 31,
	2021		2020
Assets
Current assets
Cash and cash equivalents	$	35,258	$	13,020
Restricted cash - current	15,439		—
Accounts receivable, net of allowance for credit losses	87,773		45,849
Derivative assets	4,909		75,506

Prepaid and other current assets	8,532		19,045
Total current assets	151,911		153,420
Property and equipment, net (full cost method)	864,878		723,549
Restricted cash - non-current	396,072		—
Derivative assets	2,152		25,449

Other assets	4,304		4,908
Total assets	$	1,419,317	$	907,326

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	152,330		63,089
Derivative liabilities	63,089		85,106
Current portion of long-term debt	7,500		—
Total current liabilities	222,919		148,195

Deferred income taxes	837		—
Derivative liabilities	21,416		28,434
Other non-current liabilities	8,227		8,362
Long-term debt, net	739,328		509,497

Commitments and contingencies (Note 11)

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	2		—
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, respectively	153		152
Paid-in capital	156,950		203,463
Retained earnings	16,214		9,354
Accumulated other comprehensive loss	(130)		(131)
Ranger Oil shareholders’ equity	173,189		212,838
Noncontrolling interest	253,401		—
Total equity	426,590		212,838
Total liabilities and shareholders’ equity	$	1,419,317	$	907,326

See accompanying notes to condensed consolidated financial statements.

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)


	Nine Months Ended September 30,
	2021		2020
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 debt	1,231		—
Depreciation, depletion and amortization	83,654		114,891
Impairments of oil and gas properties	1,811		271,498
Derivative contracts:
Net (gains) losses	119,679		(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)
Non-cash interest expense	1,742		3,336
Share-based compensation	4,179		2,582
Other, net	20		23
Changes in operating assets and liabilities, net	7,048		17,056
Net cash provided by operating activities	204,084		189,723

Cash flows from investing activities

Capital expenditures	(146,638)		(139,010)
Proceeds from sales of assets, net	157		83

Net cash used in investing activities	(146,481)		(138,927)

Cash flows from financing activities
Proceeds from credit facility borrowings	20,000		51,000
Repayments of credit facility borrowings	(121,500)		(89,000)
Repayments of second lien facility	(56,890)		—
Proceeds from 9.25% Senior Notes due 2026, net of discount	396,072		—
Proceeds from redeemable common units	151,160		—
Proceeds from redeemable preferred stock	2		—
Transaction costs paid on behalf of Noncontrolling interest	(5,543)		—
Issue costs paid for Noncontrolling interest securities	(3,758)		—
Debt issuance costs paid	(3,397)		(78)


Net cash provided by (used in) financing activities	376,146		(38,078)
Net increase in cash, cash equivalents and restricted cash	433,749		12,718
Cash, cash equivalents and restricted cash – beginning of period	13,020		7,798
Cash, cash equivalents and restricted cash – end of period	$	446,769	$	20,516

Supplemental disclosures:
Cash paid for:
Interest, net of amounts capitalized	$	14,298	$	20,959
Income taxes, net of (refunds)	$	360	$	(2,471)
Non-cash investing and financing activities:
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 expenditures	$	30,303	$	(30,579)

See accompanying notes to condensed consolidated financial statements.

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(in thousands)


	Preferred Stock		Common Stock		Paid-in Capital		Retained Earnings/(Accumulated Deficit)		Accumulated Other Comprehensive Loss		Noncontrolling interest		Total Equity
Balance as of December 31, 2020	$	—	$	152	$	203,463	$	9,354	$	(131)	$	—	$	212,838
Net loss	—		—		—		(13,572)		—		(6,449)		(20,021)
Issuance of preferred stock	2		—		—		—		—		—		2
Issuance of Noncontrolling interest	—		—		(50,068)		—		—		229,620		179,552
All other changes 1	—		1		1,769		—		1		1		1,772
Balance as of March 31, 2021	$	2	$	153	$	155,164	$	(4,218)	$	(130)	$	223,172	$	374,143
Net income	—		—		—		3,045		—		4,551		7,596
All other changes 1	—		—		922		—		1		1		924
Balance as of June 30, 2021	$	2	$	153	$	156,086	$	(1,173)	$	(129)	$	227,724	$	382,663
Net income	—		—		—		17,387		—		25,676		43,063
All other changes 1	—		—		864		—		(1)		1		864
Balance as of September 30, 2021	$	2	$	153	$	156,950	$	16,214	$	(130)	$	253,401	$	426,590

_______________________

1 Includes equity-classified share-based compensation of $4.2 million during the nine months ended September 30, 2021. During the nine months ended September 30, 2021, 122,911 and 7,252 shares of common stock were issued in connection with the vesting of certain time-vested restricted stock units (“RSUs”) and performance restricted stock units (“PRSUs”), net of shares withheld for income taxes.


	Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Loss		Total 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	1		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, 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 of common stock were issued in connection with the vesting of certain RSUs and PRSUs, net of shares withheld for income taxes.

See accompanying notes to condensed consolidated financial statements.

RANGER OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – unaudited

For the Quarterly Period Ended September 30, 2021

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

1. Nature of Operations

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, 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 the Company (the “Merger”). The Merger was effected pursuant to the Agreement and Plan of Merger (the “Merger Agreement”), dated July 10, 2021, by and between the Company and Lonestar. Following the completion of the Merger, the Company changed its name from Penn Virginia Corporation (“Penn Virginia”) to Ranger Oil Corporation, 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.

2. 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 as 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). Our condensed consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). 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. 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. 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 affiliate of Juniper Capital Advisors, L.P. (“Juniper Capital” and, together with JSTX and Rocky Creek, “Juniper”); and (ii) the Contribution Agreement, dated November 2, 2020 (the “Asset Agreement,” and, together with the Contribution Agreement, the “Juniper Transaction Agreements”), by and among Rocky Creek Resources, LLC, an affiliate of Juniper Capital (“Rocky Creek”), the Company and the Partnership.

In connection with the consummation of the Juniper Transactions, the Company completed a reorganization into an up-C structure which was intended to, among other things, result in the affiliates of Juniper Capital having a voting interest in the Company that is commensurate with such holders’ economic interest in the Partnership, including (i) the conversion of each of the Company’s corporate subsidiaries into limited liability companies which are disregarded for U.S. federal income tax purposes, including the conversion of Penn Virginia Holding Corp. into 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”).

On the Juniper Closing Date, (i) pursuant to the terms of the Contribution Agreement, JSTX contributed to the Partnership, as a capital contribution, $150 million in cash in exchange for 17,142,857 newly issued Common Units and the Company issued to JSTX 171,428.57 shares of Series A Preferred Stock, par value $0.01 per share, of the Company (“Series A Preferred Stock”) at a price equal to the par value of the shares acquired, and (ii) pursuant to the terms of the Asset Agreement, including certain closing adjustments based on a September 1, 2020 effective date (the “Effective Date”), Rocky Creek contributed to our operating subsidiary certain oil and gas assets in exchange for 5,405,252 newly issued Common Units and the Company issued to Rocky Creek 54,052.52 shares of Series A Preferred Stock (5,406,141 Common Units and 54,061.41 shares of Series A Preferred Stock after post-closing adjustments) at a price equal to the par value of the shares acquired, including 495,900 Common Units and 4,959 shares of Series A Preferred Stock placed in a restricted account to support post-closing indemnification claims, 50% of such amount of which was disbursed 180 days after the Juniper Closing Date and the remainder 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 fees and other costs in connection with the Juniper Transactions. A total of $5.0 million were attributable to services and costs incurred and recognized in 2020 as 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.

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 it has a controlling financial interest in the Partnership and has the power to direct the activities most significant to the Partnership’s economic performance, as well as the obligation to absorb losses and receive benefits that are potentially significant. As such, the Partnership is reflected as a consolidated subsidiary in the condensed consolidated financial statements. The ownership interest in the Partnership held by Juniper (the “Noncontrolling interest”) is included in the condensed consolidated balance sheet as Noncontrolling interest, which is classified within permanent equity. The Noncontrolling interest is classified in permanent equity as it does not meet the definition of a liability under ASC 480, Distinguishing Liabilities from Equity and, among other considerations, the Common Units are optionally redeemable by the holder for a fixed number of shares (on a one-for-one basis) and there is no fixed or determinable date or fixed or determinable price for redemption; further, while the Common Units may be redeemed with Class A Common Stock or cash, the method of settlement is solely at the discretion of the Company, with the Company having the ability to settle the redemption in shares. Additionally, while the holders of the Series A Preferred Stock (now Class B Common Stock as described below), who also own the Common Units, could cause the Noncontrolling interest to be redeemed through an event that is not solely within the control of the Company such as a change-in-control, through their majority voting rights, all holders of equally and more subordinated equity interests in the Company would be entitled to receive the same form of consideration upon such event.

The Noncontrolling interest percentage is based on the proportionate amount of the number of Common Units held by Juniper to the total Common Units outstanding which is also equivalent to the voting power in the Company associated with the Series A Preferred Stock (now Class B Common Stock as described below) held by Juniper. The Noncontrolling interest was initially measured on the Juniper Closing Date as the sum of (i) total Shareholders’ equity immediately prior to the closing of the Juniper Transactions, (ii) the fair value of Juniper’s and Rocky Creek’s contributions provided in exchange for Common Units and Series A Preferred Stock (net of the Juniper transaction costs and securities issuance costs paid by the Company and including the cash received directly by the Company for a portion of the Rocky Creek revenues as discussed above and 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 interest and the fair value of the consideration received was recorded as a reduction to paid-in capital.

On October 6, 2021, the Company, JSTX and Rocky Creek entered into a Contribution and Exchange Agreement, whereby all outstanding shares of the Series A Preferred Stock were exchanged for newly issued shares of Class B Common Stock (“Class B Common Stock”), at a ratio of one share of Class B Common Stock for each 1/100th of a share of Series A Preferred Stock and the designation of the Series A Preferred Stock was cancelled. See Note 14 for additional information.

The following table reconciles the initial investment by Juniper and the carrying value of their Noncontrolling interest as of the Juniper Closing Date (after post-closing adjustments):


Cash contribution	$	150,000
Issue costs paid for Noncontrolling interest securities	(3,758)
Transaction costs paid on behalf of Noncontrolling interest	(5,543)
Fair value of Rocky Creek oil and gas properties contributed	38,561
Revenues received attributable to contributed properties	1,160
Suspense revenues attributable to the contributed properties	(146)
Asset retirement obligations of the contributed properties	(14)
Fair value of capital contributions	180,260
Income tax adjustment attributable to the Juniper Transactions	(708)
Total shareholders’ equity prior to the Juniper Closing Date	205,558
	$	385,110
Juniper voting power through Series A Preferred Stock	59.6		%
Noncontrolling interest as of the Juniper Closing Date	$	229,620

4. Revenue Recognition

Revenue from Contracts with Customers

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

NGLs. We have natural gas processing contracts in place with certain midstream processing vendors. We deliver “wet” natural gas to our midstream processing vendors at the inlet of their processing facilities through gathering lines, certain of which we own and others which are owned by gathering service providers. Subsequent to processing, NGLs are delivered or otherwise transported to a third-party customer. Currently, for these contracts, we have determined that we are the agent and the midstream processing vendor is our customer. Accordingly, we recognize these revenues on a net basis with processing costs presented as a reduction of revenue.

Natural gas. Subsequent to the processing of “wet” natural gas and the separation of NGL products, the “dry” or residue gas is delivered to us at the tailgate of the midstream processing vendors’ facilities and we market the product to our customers, most of whom are interstate pipelines. 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. 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.

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


	September 30,		December 31,
	2021		2020
Customers	$	76,909	$	39,672
Joint interest partners	10,102		3,079
Derivative settlements from counterparties	1,000		3,287
Other	8		8
Total	88,019		46,046
Less: Allowance for credit losses	(246)		(197)
Accounts receivable, net of allowance for credit losses	$	87,773	$	45,849

Major Customers

For the nine months ended September 30, 2021, three 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, three 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 three customers referenced above. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers.

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.

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:


	4Q2021		1Q2022		2Q2022		3Q2022		4Q2022		1Q2023		2Q2023		3Q2023		4Q2023		1Q2024		2Q2024
NYMEX WTI Crude Swaps
Average Volume Per Day (bbl)	815														457		457		462		308
Weighted Average Swap Price ($/bbl)	$	45.54													$	58.75	$58.75		$58.75		$58.75
NYMEX WTI Crude Collars
Average Volume Per Day (bbl)	16,304		13,750		7,830		6,114		4,484		2,917		2,885
Weighted Average Purchased Put Price ($/bbl)	$	51.40	$	53.94	$	47.37	$	44.00	$	40.00	$	40.00	$	40.00
Weighted Average Sold Call Price ($/bbl)	$	62.23	$	66.25	$	60.87	$	58.36	$	52.47	$	50.00	$	50.00
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 Swaps
Average Volume Per Day (bbl)	17,935		6,667		6,593
Weighted Average Swap Price ($/bbl)	$	0.168	$	0.625	$	0.625
NYMEX HH Swaps
Average Volume Per Day (MMBtu)	6,739
Weighted Average Swap Price ($/MMbtu)	$	3.540
NYMEX HH Collars
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
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 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
Average Volume per Day (gal)					28,022		27,717		27,717				98,901		34,239		34,239		34,615
Weighted Average Fixed Price ($/gal)					$	0.2500	$	0.2500	$	0.2500			$	0.2288	$	0.2275	$	0.2275	$	0.2275

__________________________________________________________________________________

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

Interest Rate Derivatives

As of September 30, 2021, we had a series of interest rate swap contracts (the “Interest Rate Swaps”) establishing fixed interest rates on a portion of our variable interest rate indebtedness. The notional amount of the Interest Rate Swaps totals $300 million, with us paying a weighted average fixed rate of 1.36% on the notional amount, and the counterparties paying a variable rate equal to LIBOR through May 2022.

Financial Statement Impact of Derivatives

The impact of our derivative activities on income is included within Derivatives on our condensed consolidated statements of operations. Derivative contracts that have expired at the end of a period, but for which cash had not been received or paid as of the balance sheet date, have been recognized as components of Accounts receivable (see Note 4) and Accounts payable and accrued liabilities (see Note 9) on the condensed consolidated balance sheets. The effects of derivative gains and (losses) and cash settlements are reported as adjustments to reconcile net income (loss) to net cash provided by operating activities. These items are recorded within the Derivative contracts section of our condensed consolidated statements of cash flows under Net (gains) losses and Cash settlements and premiums received (paid), net.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Interest Rate Swap gains (losses) recognized in the condensed consolidated statements of operations	$	(84)	$	32	$	(48)	$	(7,527)
Commodity gains (losses) recognized in the condensed consolidated statements of operations	(21,000)		(6,923)		(119,631)		117,406
	$	(21,084)	$	(6,891)	$	(119,679)	$	109,879

Interest rate cash settlements recognized in the condensed consolidated statements of cash flows	$	(973)	$	(919)	$	(2,851)	$	(1,287)
Commodity cash settlements and premiums received (paid) recognized in the condensed consolidated statements of cash flows	(21,265)		7,337		(43,190)		66,582
	$	(22,238)	$	6,418	$	(46,041)	$	65,295

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:


		September 30, 2021				December 31, 2020
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Interest rate contracts	Derivative assets/liabilities – current	$	—	$	2,496	$	—	$	3,655
Commodity contracts	Derivative assets/liabilities – current	4,909		60,593		75,506		81,451
Interest rate contracts	Derivative assets/liabilities – non-current	—		—		—		1,645
Commodity contracts	Derivative assets/liabilities – non-current	2,152		21,416		25,449		26,789
		$	7,061	$	84,505	$	100,955	$	113,540

As of September 30, 2021, we reported net commodity derivative liabilities of $74.9 million and net Interest Rate Swap liabilities of $2.5 million. The contracts associated with these positions are with nine counterparties for commodity derivatives and four counterparties for Interest Rate Swaps, all of which are investment grade financial institutions and are participants in our revolving credit facility (the “Credit Facility”). This concentration may impact our overall credit risk in that these counterparties may be similarly affected by changes in economic or other conditions. Non-performance risk is incorporated by utilizing discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is in a liability position.

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

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

6. Property and Equipment

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


	September 30,		December 31,
	2021		2020
Oil and gas properties:
Proved	$	1,762,268	$	1,545,910
Unproved	59,560		49,935
Total oil and gas properties	1,821,828		1,595,845
Other property and equipment	28,265		27,746
Total properties and equipment	1,850,093		1,623,591
Accumulated depreciation, depletion, amortization and impairments	(985,215)		(900,042)
Total property and equipment, net	$	864,878	$	723,549

Unproved property costs of $59.6 million and $49.9 million have been excluded from amortization as of September 30, 2021 and December 31, 2020, respectively. An additional $1.2 million of costs, associated with wells in-progress for which we had not previously recognized any proved undeveloped reserves, were excluded from amortization as of December 31, 2020. 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, from unproved properties to the full cost pool during the nine months ended September 30, 2021 and 2020, respectively. We capitalized internal costs of $2.8 million and $1.3 million and interest of $2.6 million and $2.1 million during the nine months ended September 30, 2021 and 2020, 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 and $16.63 for the nine months ended September 30, 2021 and 2020, 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”). During the three and nine months ended September 30, 2021, the Company recorded zero and a $1.8 million impairment of its oil and gas properties, respectively. During the three and nine months ended September 30, 2020, the Company recorded impairments of its oil and gas properties of $236.0 million and $271.5 million, respectively.

7. Long-Term Debt

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


	September 30, 2021		December 31, 2020
Credit Facility	$	212,900	$	314,400
Second Lien Facility	143,110		200,000
9.25% Senior Notes due 2026	400,000		—
Total	756,010		514,400
Less: Unamortized discount 1	(4,855)		(1,604)
Less: Unamortized deferred issuance costs 1, 2	(4,327)		(3,299)
Total, net	$	746,828	$	509,497
Less: Current portion	(7,500)		—
Long-term debt	$	739,328	$	509,497

_______________________

1 Discount and issuance costs of the Second Lien Facility are being amortized over the term of the underlying loan using the effective-interest method. The discount and issuance costs of the 9.25% Senior Notes due 2026 will be amortized over its respective term beginning in the fourth quarter of 2021 concurrent with the related proceeds being released from escrow and closing of the Lonestar acquisition.

2 Excludes issuance costs of the Credit Facility, which represent costs attributable to the access to credit over its contractual term, that have been presented as a component of Other assets (see Note 9) and are being amortized over the term of the Credit Facility using the straight-line method.

Credit Facility

As of September 30, 2021, the Credit Facility had a $1.0 billion revolving commitment and a $375 million borrowing base, including a $25 million sublimit for the issuance of letters of credit. Availability under the Credit Facility may not exceed the lesser of the aggregate commitments or the borrowing base; however, outstanding borrowings under the Credit Facility were limited to a maximum of $350 million as of September 30, 2021. 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 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 of the borrowing base during the first half of 2020.

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. 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. The obligations under the Credit Facility are secured by a first priority lien on substantially all of our subsidiaries’ assets.

The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 1.50% to 2.50%, determined based on the utilization level under the Credit Facility or (b) a Eurodollar rate, including LIBOR through 2021, 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, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 3.09%. Unused commitment fees are charged at a rate of 0.50%.

As of September 30, 2021, the Credit Facility required 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, (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 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, 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, we were in compliance with all of the covenants under the Credit Facility in effect at such time.

In August 2021, we entered into the Master Assignment, Agreement and Amendment No. 11 to Credit Agreement (the “Eleventh Amendment”). The Eleventh Amendment, in addition to other changes described therein, amended the Credit Facility to, effective on the closing of the 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

lender to liquidate their interest in the Second Lien Facility. The Second Lien Amendment provided for (i) the extension of the maturity date of the Second Lien Facility to September 29, 2024, (ii) an increase to the margin applicable to advances under the Second Lien Facility, (iii) the imposition of certain limitations on capital expenditures, acquisitions and investments if the Asset Coverage Ratio (as defined therein) at the end of any fiscal quarter is less than 1.25 to 1.00, (iv) the requirement for maximum and, in certain circumstances as described therein, minimum hedging arrangements, (v) beginning in 2021, a requirement to make quarterly amortization payments equal to $1.875 million and (vi) a provision for the replacement of the LIBOR interest rate upon its expiration. During the nine months ended September 30, 2021, we incurred and capitalized $1.4 million of issue costs in connection with the Second Lien Amendment and wrote off $1.2 million of previously capitalized issue costs and original issue discount allocable to the aforementioned prepayments as a loss on the extinguishment of debt.

The outstanding borrowings under the Second Lien 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.

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 of the 9.25% Senior Notes due 2026. The remaining $15.4 million is classified as Restricted cash - current as this portion represents accrued interest and an amount equivalent to the original issue discount. The net proceeds from the offering, along with cash on hand, were used to repay all outstanding amounts under the Second Lien Facility plus certain long-term debt of Lonestar upon consummation of the Merger. See Note 14 for additional information.

8. Income Taxes

The income tax provision resulted in an expense of $0.5 million and $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

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, 2021 and December 31, 2020. There were no interest and penalty charges recognized during the three and nine months ended September 30, 2021 and 2020. Tax years from 2015 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.

9. Supplemental Balance Sheet Detail

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


	September 30,		December 31,
	2021		2020
Prepaid and other current assets:
Inventories 1	$	6,015	$	4,274
Prepaid expenses 2	2,517		14,771
	$	8,532	$	19,045
Other assets:
Deferred issuance costs of the Credit Facility, net of amortization	$	2,422	$	2,349
Right-of-use assets – operating leases	1,882		2,432

Other	—		127
	$	4,304	$	4,908
Accounts payable and accrued liabilities:
Trade accounts payable	$	34,323	$	7,055
Drilling and other lease operating costs	32,726		16,088
Royalties	55,398		26,615
Production, ad valorem and other taxes	8,682		3,094
Derivative settlements to counterparties	6,813		321
Compensation	5,714		4,222
Interest	5,745		504
Current operating lease obligations	937		936
Other 3	1,992		4,254
	$	152,330	$	63,089
Other non-current liabilities:
Asset retirement obligations	$	5,972	$	5,461
Non-current operating lease obligations	1,161		1,752
Postretirement benefit plan obligations	1,094		1,149

	$	8,227	$	8,362

_______________________

1 Includes tubular inventory and well materials of $5.7 million and $3.9 million and crude oil volumes in storage of $0.3 million and $0.4 million as of September 30, 2021 and December 31, 2020, respectively.

2 The balances as of September 30, 2021 and December 31, 2020 include $1.0 million and $13.6 million, respectively, for the prepayment of drilling and completion materials and services.

3 The balance as of December 31, 2020 includes $3.5 million of accrued costs attributable to Juniper Transaction expenses.

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, cash equivalents and restricted cash, accounts receivable, and accounts payable approximate fair value due to their short-term maturities. As of September 30, 2021 and December 31, 2020, the carrying values of the borrowings outstanding under our credit facilities approximate fair value as the borrowings bear interest at variables rates tied to current market rates and the applicable margins represent market rates. The fair value of our fixed rate 9.25% Senior Notes due 2026 is estimated based on the published market prices for issuances of similar risk and tenor and is categorized as Level 2 within the fair value hierarchy. As of September 30, 2021, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $756.0 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 million.

Recurring Fair Value Measurements

The fair values of our derivative instruments are measured at fair value on a recurring basis on our condensed consolidated balance sheets. The following tables summarize the valuation of those assets and (liabilities) as of the dates presented:


	As of September 30, 2021
	Fair Value		Fair Value Measurement Classification
Description	Measurement		Level 1		Level 2		Level 3
Assets:


Commodity derivative assets – current	$	4,909	$	—	$	4,909	$	—
Commodity derivative assets – non-current	$	2,152	$	—	$	2,152	$	—
Liabilities:
Interest rate swap liabilities – current	$	(2,496)	$	—	$	(2,496)	$	—
Interest rate swap liabilities – non-current	$	—	$	—	$	—	$	—
Commodity derivative liabilities – current	$	(60,593)	$	—	$	(60,593)	$	—
Commodity derivative liabilities – non-current	$	(21,416)	$	—	$	(21,416)	$	—


	As of December 31, 2020
	Fair Value		Fair Value Measurement Classification
Description	Measurement		Level 1		Level 2		Level 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)	$	—

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

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

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

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

Non-Recurring Fair Value Measurements

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

11. Commitments and Contingencies

Drilling and Completion Commitments

As of September 30, 2021, we had contractual commitments on a pad-to-pad basis for two drilling rigs.

Gathering and Intermediate Transportation Commitments

We have long-term agreements with Nuevo G&T and Nuevo Dos Marketing, LLC (“Nuevo Marketing” and together with Nuevo G&T, collectively “Nuevo”) to provide gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in as well as volume capacity support for certain downstream interstate pipeline transportation.

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”) of 8,000 gross barrels of oil per day to Nuevo through 2031 under the gathering agreement. We are obligated to deliver the first 20,000 gross barrels of oil per day produced from Gonzales, Lavaca, Fayette and DeWitt Counties, Texas.

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’s capacity on a downstream interstate pipeline through 2026.

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

Excluding the application of existing credits that we have earned during the preceding 12-month period ended September 30, 2021 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, approximately $13.9 million per year for 2022 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, we have 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 contracted 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’ notice to the counterparty. We have also contracted for crude oil storage capacity for up to 90,000 barrels with a downstream interstate pipeline at a facility in DeWitt County, Texas, on a month-to-month basis which can be terminated by either party with 45-days’ notice to the counterparty. Finally, we have an agreement with a marketing affiliate of the aforementioned downstream interstate pipeline to utilize up to 62,000 barrels of capacity within their system on a firm basis and an additional 120,000 barrels, if available, on a flexible basis. Costs associated with these agreements are in the form of monthly fixed rate short-term leases and are charged as incurred on a monthly basis to GPT in our condensed consolidated statements of operations.

Legal, Environmental Compliance and Other Claims

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, 2021 and December 31, 2020, 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.

12. 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 Corporation Management Incentive Plan (the “Plan”) for share-based compensation awards. A total of 760,220 RSUs and 484,197 PRSUs have been granted to employees and directors through September 30, 2021. As of September 30, 2021, a total of 239,524 RSUs and 345,069 PRSUs are unvested and outstanding.

We 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 million of expense attributable to the RSUs and PRSUs for the nine months ended September 30, 2021 and 2020, respectively.

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:


	Nine Months Ended September 30,
	2021	2020
RSUs granted	118,223	281,382
Average grant-date fair value	$13.84	$4.49
Issued upon vesting, net of shares withheld for income taxes	122,911	45,435

Compensation expense for RSUs is being charged to expense on a straight-line basis over a range of less than one to three years.

The table below presents the number of PRSUs granted and the number of shares vested for the following periods:


	Nine Months Ended September 30,
	2021	2020
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	$13.63	not applicable
Issued upon vesting, net of shares withheld for income taxes	7,252	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).

Compensation expense for PRSUs with a market condition is being charged to expense on a straight-line basis for the 2021 grants and graded-vesting for the 2020 and 2019 grants, over a range of less than one to three years. Compensation expense for PRSUs with a performance condition is recognized on a straight-line basis over three years, when it is considered probable that the performance condition will be achieved and such grants are expected to vest.

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

Vesting of PRSUs granted in 2020 and 2019 range from zero to 200 percent of the original grant based on the performance of our common stock (TSR-based) relative to a defined peer group. Due to the market condition for the 2019, 2020 and a portion of the 2021 PRSU 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 these PRSUs granted during 2021, 2020 and 2019 are presented as follows:


	2021 1		2020 1		2019

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

___________________

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

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.

We recognize share-based compensation expense as a component of G&A expenses in our condensed consolidated statements of operations.

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 for the three and nine months ended September 30, 2021, respectively. We recognized $0.1 million and $0.5 million of expense attributable to the 401(k) Plan for the three and nine months ended September 30, 2020, 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, 2021 and 2020. The charges for these plans are recorded as a component of Other income (expense) in our condensed consolidated statements of operations.

13. Earnings per Share

Basic net earnings (loss) per share is calculated by dividing the net income (loss) available to common shareholders, excluding net income or loss attributable to Noncontrolling interest, 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 shares of Series A Preferred Stock held by Juniper as a Noncontrolling interest in the Partnership are exchanged for common shares, as applicable to the nine months ended September 30, 2021 (see Note 3). Accordingly, our reported net income (loss) attributable to common shareholders is adjusted to reflect the reallocation of the net income (loss) attributable to the Noncontrolling interest assuming exchange of the Common Units and Series A Preferred Stock held by 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,
	2021		2020		2021		2020
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 income	25,676		—		23,778		—
Net income (loss) attributable to common shareholders (diluted)	$	43,063	$	(243,413)	$	30,638	$	(175,034)

Weighted-average shares – basic	15,319		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 PRSUs	394		—		371		—
Weighted-average shares – diluted 1	15,713		15,183		15,669		15,168

___________________

1 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.

14. Subsequent Events

Acquisition of Lonestar Resources

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 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, 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.

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 acquisition of Lonestar, 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, and volatility of commodity prices for crude oil, natural gas liquids, or NGLs, and natural gas;

•the continued impact of the COVID-19 pandemic, including reduced demand for oil and natural gas, economic slowdown, governmental actions, stay-at-home orders, interruptions to our operations or our customer’s 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, 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 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;

• 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;

• uncertainties relating to general domestic and international economic and political conditions;

• 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 of the COVID-19 pandemic may give rise to risks that are currently unknown or amplify the risks associated with many of these factors.

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

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

The following discussion and analysis of the financial condition and results of operations of Ranger Oil Corporation and its consolidated subsidiaries (“Ranger,” “Ranger Oil,” the “Company,” “we,” “us” or “our”) should be read in conjunction with our condensed consolidated financial statements and notes thereto included in Part I, Item 1, “Financial Statements.” All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated. Also, due to the combination of different units of volumetric measure, the number of decimal places presented and rounding, certain results may not calculate explicitly from the values presented in the tables. Certain statistics for the prior period have been reclassified to conform to the current period presentation. References to “quarters” represent the three months ended September 30, 2021 or 2020, as applicable.

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 Resources

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 (“Class A Common Stock”) began trading on the Nasdaq under the ticker symbol “ROCC” on October 18, 2021. As the Merger was completed after the quarterly period ended September 30, 2021, our results exclude Lonestar’s financial information and operating results for all periods presented and discussed herein.

See Note 14 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information.

Financing Updates

9.25% Senior Notes due 2026

Debt Repayments

In connection with the consummation of the Merger, the net proceeds from the offering of $400 million aggregate principal amount of 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 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 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 Credit Agreement, dated as of September 29, 2017 (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, our borrowing base under the Credit Facility increased to $600 million with aggregate elected commitments of $400 million.

See Note 7 and Note 14 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for additional information on our debt.

Hedging Update

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.

See Note 14 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 dividend 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.”

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 create uncertainty for global economic activity. Over the past 18 months, 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, increased mobility and other factors has resulted in increased oil demand and commodity prices.

In addition, there remains a high level of uncertainty regarding the volatility of energy supply and demand as the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, collectively “OPEC+”) reached an agreement in July 2021 to increase production over this past quarter. In early October 2021, OPEC+ reconfirmed the agreement to boost output during the fourth quarter 2021. Higher energy prices may add to inflationary pressures, which could lead to increased service costs and a slowdown in the economic recovery.

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 all of our crude oil volumes under Magellan East Houston (“MEH”) pricing, whereas 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 historically been at a premium to NYMEX WTI, LLS has had a more favorable differential than MEH.

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”) price primarily due to differential adjustments for the location and the energy content of the natural gas. Location differentials result from variances in natural gas transportation costs based on the proximity of the natural gas to its major consuming markets that correspond with the ultimate delivery point as well as individual interaction of supply and demand.

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

In addition to the volatility of commodity prices, we are subject to inflationary and other factors that could result 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 actions with vendors and other service providers to secure products and services at fixed prices and to pay for certain materials and services in advance in order to lock in favorable costs.

Capital Expenditures, Development Progress and Production

We currently operate two drilling rigs and during the three and nine months ended September 30, 2021, incurred capital expenditures of approximately $60.0 million and $182.8 million, respectively, substantially all of which was directed to drilling and completion projects. During the third quarter 2021, a total of 10 gross (9.2 net) wells were drilled, completed and turned in line. 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, we had approximately 174,600 gross (142,600 net) acres in the Eagle Ford, net of expirations, of which approximately 93% is held by production.

Total sales volume for the third quarter 2021 was 2,344 thousand barrels of oil equivalent (“Mboe”), or 25,483 barrels of oil equivalent (“boe”) per day, with approximately 80%, or 1,879 thousand barrels of oil (“Mbbls”), of sales volume from crude oil, 11% from NGLs and 9% from natural gas.

Commodity Hedging Program

As of October 29, 2021, we have hedged a portion of our estimated future crude oil and natural gas production from October 1, 2021 through the first quarter of 2024. The following table summarizes our net hedge positions for the periods presented:


	4Q21		1Q22		2Q22		3Q22		4Q22		1Q23		2Q23		3Q23		4Q23		1Q24		2Q24
NYMEX WTI Crude Swaps
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
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
NYMEX WTI Collars
Average Volume Per Day (bbl)	16,304		15,417		12,775		7,745		6,114		2,917		2,885
Weighted Average Purchased Put Price ($/bbl)	$	51.40	$	55.14	$	52.90	$	47.37	$	45.33	$	40.00	$	40.00
Weighted Average Sold Call Price ($/bbl)	$	62.23	$	68.26	$	71.14	$	64.60	$	60.87	$	50.00	$	50.00
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 Swaps
Average Volume Per Day (bbl)	11,957		10,000		9,890		3,261		3,261
Weighted Average Swap Price ($/bbl)	$	0.17	$	0.79	$	0.79	$	1.12	$	1.12
NYMEX HH Swaps
Average Volume Per Day (MMBtu)	20,700		17,500		12,500		12,500		12,500		10,000		7,500
Weighted Average Swap Price ($/MMBtu)	$	3.530	$	3.857	$	3.342	$	3.360	$	3.408	$	3.346	$	3.325
NYMEX HH Collars
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
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 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
Average Volume per Day (gal)					28,022		27,717		27,717				98,901		34,239		34,239		34,615
Weighted Average Fixed Price ($/gal)					$	0.2500	$	0.2500	$	0.2500			$	0.2288	$	0.2275	$	0.2275	$	0.2275

Results of Operations

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


	Three Months Ended									Nine Months Ended
	September 30,			June 30,			September 30,			September 30,
	2021			2021			2020			2021			2020
Total sales volume (Mboe) 1	2,344			2,261			2,235			6,453			6,909
Average daily sales volume (boe/d) 1	25,483			24,844			24,295			23,638			25,214
Crude oil sales volume (Mbbl) 1	1,879			1,831			1,691			5,179			5,291
Crude oil sold as a percent of total 1	80		%	81		%	76		%	80		%	77		%
Product revenues	$	140,133		$	123,789		$	68,614		$	352,230		$	204,300
Crude oil revenues	$	127,995		$	116,314		$	63,227		$	326,222		$	190,732
Crude oil revenues as a percent of total	91		%	94		%	92		%	93		%	93		%
Realized prices:
Crude oil ($/bbl)	$	68.10		$	63.54		$	37.39		$	62.99		$	36.05
NGLs ($/bbl)	$	27.24		$	18.31		$	9.20		$	21.21		$	6.86
Natural gas ($/Mcf)	$	4.11		$	2.70		$	1.80		$	3.23		$	1.73
Aggregate ($/boe)	$	59.77		$	54.75		$	30.70		$	54.58		$	29.57
Realized prices, including effects of derivatives, net 2
Crude oil ($/bbl)	$	57.15		$	52.70		$	48.28		$	52.08		$	51.05
NGLs ($/bbl)	$	25.77		$	17.87		$	9.20		$	20.52		$	6.86
Natural gas ($/Mcf)	$	3.44		$	2.71		$	1.88		$	3.01		$	1.86
Aggregate ($/boe)	$	50.49		$	45.93		$	38.99		$	45.63		$	41.14
Production and lifting costs:
Lease operating ($/boe)	$	4.54		$	4.30		$	3.70		$	4.52		$	4.04
Gathering, processing and transportation ($/boe)	$	2.43		$	2.29		$	2.58		$	2.41		$	2.43
Production and ad valorem taxes ($/boe)	$	3.21		$	2.97		$	1.95		$	3.06		$	1.90
General and administrative ($/boe) 3	$	4.66		$	3.09		$	3.84		$	4.82		$	3.45
Depreciation, depletion and amortization ($/boe)	$	13.21		$	12.74		$	16.57		$	12.96		$	16.63

__________________________________________________________________________________

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

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

3 Includes combined amounts of $1.56, $0.43 and $1.20 per boe for the three months ended September 30, 2021, June 30, 2021 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 significant special charges related to organizational restructuring and acquisition, divestiture and strategic transaction costs, as described in the discussion of “Results of Operations - General and Administrative” that follows.

Sequential Quarterly Analysis

The following summarizes our key operating and financial highlights for the three months ended September 30, 2021, with comparison to the three months ended June 30, 2021. The year-over-year highlights for the quarterly periods ended September 30, 2021 and 2020 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 25,483 boe per day from 24,844 boe per day with 9.2 net wells turned in line for both third quarter 2021 and second quarter 2021. Total sales volume increased 4% to 2,344 Mboe from 2,261 Mboe.

•Product revenues increased 13% to $140.1 million from $123.8 million as a result of 7% higher crude oil realized prices, or $8.6 million, coupled with slightly higher crude oil sales volume, or $3.1 million. NGL revenues were higher due to 49% higher realized prices, or $2.3 million, as well as 10% higher sales volume, or $0.4 million. Natural gas revenues were 61% higher as a result of 52% 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 million from $14.9 million and increased on a per unit basis to $6.97 per boe from $6.59 per boe due primarily to the effects of slightly higher sales volume of 4%.

•Production and ad valorem taxes increased on an absolute and per unit basis to $7.5 million and $3.21 per boe from $6.7 million and $2.97 per boe, respectively, due to the overall effects of 9% higher aggregate realized product pricing, partially offset by lower estimated ad valorem tax assessments.

•General and administrative (“G&A”) expenses increased on an absolute and per unit basis to $10.9 million and $4.66 per boe from $7.0 million and $3.09 per boe, respectively, primarily due to $2.7 million of acquisition and integration costs associated with the Lonestar acquisition as well as higher employee compensation costs.

•Depreciation, depletion and amortization (“DD&A”) increased to $31.0 million and increased on a per unit basis to $13.21 per boe during the third quarter 2021 as compared to $28.8 million and $12.74 per boe during the second quarter 2021 due primarily to lower total proved reserves, partially offset by lower future development cost assumptions.

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. 2020			2021 vs. 2020
	Three Months Ended September 30,		Favorable	Three Months Ended September 30,		Favorable
	2021	2020	(Unfavorable)	2021	2020	(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. 2020			2021 vs. 2020
	Nine Months Ended September 30,		Favorable	Nine Months Ended September 30,		Favorable
	2021	2020	(Unfavorable)	2021	2020	(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)

__________________________________________________________________________________

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 flat during the third quarter 2021 as compared to the corresponding quarter 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, 2021 when compared to the corresponding period in 2020 as a result of the temporary suspension of the drilling program due to the global economic downturn associated with COVID-19 in 2020 as our overall production levels remained depressed in early 2021.

Approximately 80% of total sales volume during the three and nine month periods in 2021 was attributable to crude oil when compared to approximately 76% during the corresponding periods in 2020. The increase in the crude oil composition of total sales volume is due primarily to drilling in the oilier northern and eastern portions of our acreage holdings and focus on development plans with emphasis in such portions.

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 Revenues						Product Revenues per Unit of Volume
					2021 vs. 2020						2021 vs. 2020
	Three Months Ended September 30,				Favorable		Three Months Ended September 30,				Favorable
	2021		2020		(Unfavorable)		2021		2020		(Unfavorable)
							($ per unit of volume)
Crude oil	$	127,995	$	63,227	$	64,768	$	68.10	$	37.39	$	30.71
NGLs	7,165		2,824		4,341		$	27.24	$	9.20	$	18.04
Natural gas	4,973		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. 2020						2021 vs. 2020
	Nine Months Ended September 30,				Favorable		Nine Months Ended September 30,				Favorable
	2021		2020		(Unfavorable)		2021		2020		(Unfavorable)
							($ per unit of volume)
Crude oil	$	326,222	$	190,732	$	135,490	$	62.99	$	36.05	$	26.94
NGLs	15,115		6,295		8,820		$	21.21	$	6.86	$	14.35
Natural gas	10,893		7,273		3,620		$	3.23	$	1.73	$	1.50
Total	$	352,230	$	204,300	$	147,930	$	54.58	$	29.57	$	25.01

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


	Three Months Ended September 30, 2021 vs. 2020						Nine Months Ended September 30, 2021 vs. 2020
	Revenue Variance Due to						Revenue Variance Due to
	Volume		Price		Total		Volume		Price		Total
Crude oil	$	7,038	$	57,730	$	64,768	$	(4,014)	$	139,504	$	135,490
NGLs	(405)		4,746		4,341		(1,403)		10,223		8,820
Natural gas	(379)		2,789		2,410		(1,450)		5,070		3,620
	$	6,254	$	65,265	$	71,519	$	(6,867)	$	154,797	$	147,930

Our product revenues during the three and nine month periods in 2021 increased compared to the corresponding periods in 2020 due primarily to significantly higher prices and the continued economic recovery following the easing of COVID-19 restrictions as compared to the prior year that resulted in increases to the NYMEX WTI benchmark price of 70% for the three and nine month periods, as well as an increase of 11% in crude oil volume in the three month period, partially offset by lower NGL and natural gas volume. Total crude oil revenues remain over 90% of our total product revenues during both the three and nine month periods in 2021 and 2020.

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. 2020						2021 vs. 2020
	Three Months Ended September 30,				Favorable		Nine Months Ended September 30,				Favorable
	2021		2020		(Unfavorable)		2021		2020		(Unfavorable)
Realized crude oil prices ($/bbl)	$	68.10	$	37.39	$	30.71	$	62.99	$	36.05	$	26.94
Average WTI prices	70.52		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)	4.27		1.95		2.32		3.52		1.82		1.70
Realized differential to HH	$	(0.16)	$	(0.15)	$	(0.01)	$	(0.29)	$	(0.09)	$	(0.20)

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 month period in 2021 compared to the corresponding period in 2020 is primarily 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. 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 liquids 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 liquids 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”).

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


					2021 vs. 2020						2021 vs. 2020
	Three Months Ended September 30,				Favorable		Nine Months Ended September 30,				Favorable
	2021		2020		(Unfavorable)		2021		2020		(Unfavorable)




Realized crude oil prices ($/bbl)	$	68.10	$	37.39	$	30.71	$	62.99	$	36.05	$	26.94
Effects of derivatives, net ($/bbl)	(10.95)		10.89		(21.84)		(10.91)		15.00		(25.91)
Crude oil realized prices, including effects of derivatives, net ($/bbl)	$	57.15	$	48.28	$	8.87	$	52.08	$	51.05	$	1.03





Realized natural gas liquid prices ($/bbl)	$	27.24	$	9.20	$	18.04	$	21.21	$	6.86	$	14.35
Effects of derivatives, net ($/bbl)	(1.47)		—		(1.47)		(0.69)		—		(0.69)
Natural gas liquids realized prices, including effects of derivatives, net ($/bbl)	$	25.77	$	9.20	$	16.57	$	20.52	$	6.86	$	13.66





Realized natural gas prices ($/Mcf)	$	4.11	$	1.80	$	2.31	$	3.23	$	1.73	$	1.50
Effects of derivatives, net ($/Mcf)	(0.67)		0.08		(0.75)		(0.22)		0.13		(0.35)
Natural gas realized prices, including effects of derivatives, net ($/Mcf)	$	3.44	$	1.88	$	1.56	$	3.01	$	1.86	$	1.15

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 in this caption as a contra-revenue item.

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


					2021 vs. 2020						2021 vs. 2020
	Three Months Ended September 30,				Favorable		Nine Months Ended September 30,				Favorable
	2021		2020		(Unfavorable)		2021		2020		(Unfavorable)
Other operating income, net	$	928	$	797	$	131	$	2,085	$	1,972	$	113

Our marketing fees slightly increased in the three and nine month periods in 2021 as compared to the corresponding periods in 2020 due primarily to 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 in the nine month period due to lower sales volumes.

Lease Operating Expenses

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

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


					2021 vs. 2020							2021 vs. 2020
	Three Months Ended September 30,				Favorable			Nine Months Ended September 30,				Favorable
	2021		2020		(Unfavorable)			2021		2020		(Unfavorable)
Lease operating	$	10,647	$	8,275	$	(2,372)		$	29,200	$	27,901	$	(1,299)
Per unit ($/boe)	$	4.54	$	3.70	$	(0.84)		$	4.52	$	4.04	$	(0.48)
% change per unit					(22.7)		%					(11.9)		%

LOE increased on an absolute basis and per unit basis during the three month period in 2021 when compared to the corresponding period in 2020 due primarily to higher variable costs and greater utilization of gas lift and lower maintenance costs as substantial work was completed in the prior year during shut-in periods partially offset 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 improvements throughout 2021.

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. 2020							2021 vs. 2020
	Three Months Ended September 30,				Favorable			Nine Months Ended September 30,				Favorable
	2021		2020		(Unfavorable)			2021		2020		(Unfavorable)
GPT	$	5,688	$	5,760	$	72		$	15,535	$	16,797	$	1,262
Per unit ($/boe)	$	2.43	$	2.58	$	0.15		$	2.41	$	2.43	$	0.02
% change per unit					5.8		%					0.8		%

GPT expense was relatively flat on an absolute basis during the three month period in 2021 as compared to the corresponding period in 2020. GPT expense decreased on an absolute basis during the nine month period in 2021 as compared to the corresponding period in 2020 due primarily to lower gas gathering costs attributable to 20% lower natural gas sales volumes, as well as 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 portion of our crude oil production.

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.

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


							2021 vs. 2020								2021 vs. 2020
	Three Months Ended September 30,						Favorable		Nine Months Ended September 30,						Favorable
	2021			2020			(Unfavorable)		2021			2020			(Unfavorable)

Production/severance taxes	$	6,589		$	3,074		$	(3,515)	$	16,608		$	8,692		$	(7,916)
Ad valorem taxes	945			1,294			349		3,160			4,460			1,300
	$	7,534		$	4,368		$	(3,166)	$	19,768		$	13,152		$	(6,616)
Per unit ($/boe)	$	3.21		$	1.95		$	(1.26)	$	3.06		$	1.90		$	(1.16)
Production/severance tax rate as a percent of product revenues	4.7		%	4.5		%			4.7		%	4.3		%

Production taxes increased on an absolute basis and per unit basis during the three and nine month periods in 2021 when compared to the corresponding periods in 2020 due primarily to the increases in aggregate commodity sales prices in 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.

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 for the periods presented:


					2021 vs. 2020						2021 vs. 2020
	Three Months Ended September 30,				Favorable		Nine Months Ended September 30,				Favorable
	2021		2020		(Unfavorable)		2021		2020		(Unfavorable)
Primary G&A	$	7,281	$	5,913	$	(1,368)	$	19,341	$	19,322	$	(19)
Share-based compensation	971		775		(196)		4,179		2,582		(1,597)
Significant special charges:
Organizational restructuring, including severance	—		1,372		1,372		239		1,372		1,133
Acquisition/integration, divestiture and strategic transaction costs	2,680		525		(2,155)		7,335		525		(6,810)


Total G&A	$	10,932	$	8,585	$	(2,347)	$	31,094	$	23,801	$	(7,293)
Per unit ($/boe)	$	4.66	$	3.84	$	(0.82)	$	4.82	$	3.45	$	(1.37)
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)

Our primary G&A expenses increased on an absolute and per unit basis during the three and nine month periods in 2021 compared to the corresponding periods in 2020. The increase for the three month period in 2021 compared to 2020 is due primarily to higher incentive compensation costs. Primary G&A was relatively flat during the nine month period in 2021 compared to the corresponding period in 2020.

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

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 for the periods presented:


					2021 vs. 2020						2021 vs. 2020
	Three Months Ended September 30,				Favorable		Nine Months Ended September 30,				Favorable
	2021		2020		(Unfavorable)		2021		2020		(Unfavorable)
DD&A expense	$	30,975	$	37,038	$	6,063	$	83,654	$	114,891	$	31,237
DD&A rate ($/boe)	$	13.21	$	16.57	$	3.36	$	12.96	$	16.63	$	3.67

DD&A decreased on an absolute and a per unit basis during the three and nine month periods in 2021 when compared to the corresponding periods in 2020. Lower production volume provided for decreases of $7.6 million and lower DD&A rates resulted in decreases of $23.7 million in the first nine months of 2021. The lower DD&A rate in 2021 is primarily attributable to the effect of adding additional reserves in 2021 as well as the effect of the impairments recorded in the latter part of 2020 and in the first quarter 2021.

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. 2020						2021 vs. 2020
	Three Months Ended September 30,				Favorable		Nine Months Ended September 30,				Favorable
	2021		2020		(Unfavorable)		2021		2020		(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 the nine month period in 2021, we recorded an impairment of $1.8 million, compared to the $271.5 million recorded in the nine month period in 2020. These impairments were 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 includes charges for outstanding borrowings under the Credit Facility and Second Lien Facility derived from internationally-recognized interest rates with a premium based on our credit profile and the level of credit outstanding and the contractual rate associated with the 9.25% Senior Notes due 2026. 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.

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


					2021 vs. 2020						2021 vs. 2020
	Three Months Ended September 30,				Favorable		Nine Months Ended September 30,				Favorable
	2021		2020		(Unfavorable)		2021		2020		(Unfavorable)
Interest on borrowings and related fees	$	10,936	$	7,375	$	(3,561)	$	22,101	$	22,944	$	843
Accretion of original issue discount	84		205		121		274		602		328
Amortization of debt issuance costs	479		594		115		1,468		2,734		1,266
Capitalized interest	(917)		(677)		240		(2,561)		(2,067)		494
Total interest expense, net of capitalized interest	$	10,582	$	7,497	$	(3,085)	$	21,282	$	24,213	$	2,931

The increase in interest expense during the three month period in 2021 is substantially attributable to interest incurred in the amount of $5 million for the 9.25% Senior Notes due 2026. This is offset by decreased interest expense attributable to the Credit Facility and Second Lien Facility during the three and nine month periods in 2021 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.

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. 2020						2021 vs. 2020
	Three Months Ended September 30,				Favorable		Nine Months Ended September 30,				Favorable
	2021		2020		(Unfavorable)		2021		2020		(Unfavorable)
Commodity derivative gains (losses)	$	(21,000)	$	(6,923)	$	(14,077)	$	(119,631)	$	117,406	$	(237,037)
Interest rate swap gains (losses)	(84)		32		(116)		(48)		(7,527)		7,479
Total	$	(21,084)	$	(6,891)	$	(14,193)	$	(119,679)	$	109,879	$	(229,558)

In the three and nine month periods in 2021, commodity prices recovered to levels that were significantly higher on an average aggregate basis than those during the corresponding periods in 2020. Accordingly, the derivative losses in 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 prices for the underlying commodities relative to our hedged positions. In the second quarter 2021, we began hedging a portion of our NGL production. Realized settlement payments, net for crude oil, NGL and natural gas derivatives were $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, we began hedging a portion of our exposure to variable interest rates associated with our Credit Facility and Second Lien Facility. For the three and nine month periods in 2021, we paid $1.0 million and $2.9 million, respectively, of net settlements from our interest rate swaps. For the three and nine month periods in 2020, we paid $0.9 and $1.3 million of net settlements from our interest rate swaps, respectively.

Income Taxes

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

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


							2021 vs. 2020								2021 vs. 2020
	Three Months Ended September 30,						Favorable		Nine Months Ended September 30,						Favorable
	2021			2020			(Unfavorable)		2021			2020			(Unfavorable)
Income tax (expense) benefit	$	(549)		$	1,558		$	(2,107)	$	(410)		$	1,110		$	(1,520)
Effective tax rate	1.3		%	0.6		%			1.3		%	0.6		%

The income tax provision resulted in an expense of $0.5 million and $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 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 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 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 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.

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, we had liquidity of $172.0 million, comprised of cash and cash equivalents of $35.3 million and availability under our Credit Facility of $136.7 million (factoring in letters of credit), and excludes $15.4 million restricted cash - 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 $600 million, with aggregate elected commitments of $400 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, NGL and natural gas products, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity and other supply chain dynamics, among other factors. All of these factors have been negatively impacted by the continuing COVID-19 pandemic and the related instability in the global energy markets. In order to mitigate this volatility, we are extensively utilizing 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. 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-time and under market conditions that we believe are favorable to us, we may consider capital market transactions, including the offering of debt and equity securities. We maintain an effective shelf registration statement to allow for optionality.

Capital Resources

Our 2021 capital budget contemplates capital expenditures from $240 to $270 million, of which $235 to $265 million has been allocated to drilling and completion activities. We plan to fund our 2021 capital program and our operations for the next twelve months primarily with cash on hand, cash from operating activities and, to the extent necessary, supplemental borrowings under the Credit Facility. Based upon current price and production expectations, we believe that our cash on hand, cash from operating activities and borrowings under our Credit Facility, as necessary, will be sufficient to fund our capital spending and operations for at least the next twelve months; however, future cash flows are subject to a number of variables including the length and magnitude of the current global economic uncertainties associated with the COVID-19 pandemic and related instability in the global energy markets.

Cash Flows

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


	Nine Months Ended
	September 30,		September 30,
	2021		2020
Net cash provided by operating activities	204,084		189,723
Net cash used in investing activities	(146,481)		(138,927)
Net cash provided by (used in) financing activities	376,146		(38,078)
Net increase in cash, cash equivalents and restricted cash	$	433,749	$	12,718

Cash Flows from Operating Activities. The increase of $14.4 million in net cash provided by operating activities for the nine months ended September 30, 2021 compared to the corresponding period in 2020 was primarily attributable to the effect of cash receipts that were derived from higher average prices in 2021, as well as lower interest payments, net of interest rate swap settlements in the 2021 period as compared to 2020, partially offset by (i) the effects of lower total sales volume (ii) higher net payments for commodity derivatives settlements and premiums, (iii) 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, 2021 as compared to the corresponding period in 2020, due primarily to the suspension of the drilling and completion program during a portion of 2020 as a result of the COVID-19 pandemic and related market instability.

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


	Nine Months Ended
	September 30,		September 30,
	2021		2020
Drilling and completion	$	181,144	$	93,443
Lease acquisitions, land-related costs, and geological and geophysical (seismic) costs	2,315		3,317
Pipeline, gathering facilities and other equipment, net 1	(632)		1,221
Total capital expenditures incurred	$	182,827	$	97,981

__________________________________________________________________________________

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,
	2021		2020
Total capital expenditures program costs (from above)	$	182,827	$	97,981
Decrease (increase) in accounts payable for capital items and accrued capitalized costs	(30,303)		30,579
Net purchases of tubular inventory and well materials 1	1,858		3,441
Prepayments for drilling and completion services, net of (transfers)	(12,653)		3,613
Capitalized internal labor, capitalized interest and other	4,909		3,396
Total cash paid for capital expenditures	$	146,638	$	139,010

__________________________________________________________________________________

1 Includes purchases made in advance of drilling.

Cash Flows from Financing Activities. In January 2021, we received over $150 million of proceeds from the issuance of Common Units and Series A Preferred Stock in connection with the Juniper Transactions. These proceeds were used to 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 Units and Series A Preferred Stock), (ii) $5.5 million of transaction costs attributable to Juniper’s Noncontrolling interest, (iii) $1.8 million of issue costs associated with the amendments 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. 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 Facility 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,
	2021			2020
Credit facility	$	212,900		$	314,400
Second lien facility, net	139,133			195,097
9.25 Senior Notes due 2026, net	394,795			—
Total debt, net	746,828			509,497
Total equity	426,590			212,838
	$	1,173,418		$	722,335
Debt as a % of total capitalization	64		%	71		%

Credit Facility. As of September 30, 2021, the Credit Facility had a $1.0 billion revolving commitment and a $375 million borrowing base, including 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 million in letters of credit outstanding as of September 30, 2021 and December 31, 2020.

The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 1.50% to 2.50%, determined based on the utilization level under the Credit Facility or (b) a Eurodollar rate, including the London interbank offered rate (“LIBOR”) through 2021, plus an applicable margin ranging from 2.50% to 3.50%, determined based on the utilization level under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on Eurodollar, including LIBOR, borrowings is payable every one, three or six months, at our election, and is computed on the basis of a year of 360 days. As of September 30, 2021, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 3.09%. Unused commitment fees are charged at a rate of 0.50%.

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


			Borrowings Outstanding
	End of Period		Weighted- Average		Maximum		Weighted- Average Rate
Three months ended September 30, 2021	$	212,900	$	233,818	$	238,900	3.10	%
Nine months ended September 30, 2021	$	212,900	$	241,206	$	314,400	3.13	%

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. 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.

Facility to, effective on the closing of the Merger, (1) increase the borrowing base under 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. 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.

Covenant Compliance. As of September 30, 2021, the Credit Facility required 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, (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.

As of September 30, 2021, we were in compliance with all of the covenants under the Credit Facility and the Second Lien Facility.

See Note 14 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.

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”) 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.

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 was no such impairment of our proved oil and gas properties during the second or third quarters of 2021.

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, we had variable-rate borrowings of $212.9 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%, 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 million on an annual basis, excluding the offsetting impact of our interest rate swap derivatives.

Commodity Price Risk

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

As of September 30, 2021, our commodity derivative portfolio was in a net liability position in the amount of $74.9 million. The contracts associated with this position are with nine 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, we reported a net commodity derivative loss of $119.6 million. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our derivative instruments. Our results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which fluctuate with changes in crude oil, NGL and natural gas prices. These fluctuations could be significant in a volatile pricing environment. See Note 5 to the condensed consolidated financial statements included in Part I, Item 1, “Financial Statements” for a further description of our commodity price risk management activities.

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


	Change of 10% per bbl of Crude Oil ($ in millions)
	Increase		Decrease
Effect on the fair value of crude oil derivatives 1	$	(36.4)	$	26.7
Effect of crude oil price changes for the remainder of 2021 on operating income, excluding derivatives 2	$	20.3	$	(15.4)

_____________________________

1 Based on derivatives outstanding as of September 30, 2021.

2 These sensitivities are subject to significant change.

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. 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, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

During the quarter ended September 30, 2021, 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, 2020 and in Part II, Item 1A of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2021.

Item 5. Other Information

None.

Item 6. Exhibits


(2.1)			Merger Agreement, dated as of July 10, 2021, by and among Penn Virginia, Merger Sub Inc, Merger Sub LLC and Lonestar (incorporated by reference to Exhibit 2.1 to Registrants Current Report on Form 8-K filed on July 13, 2021).

(3.1)			Fourth Amended and Restated Articles of Incorporation of Ranger Oil Corporation, effective as of October 6, 2021 (incorporated by reference to Exhibit 3.1 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 Amended 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).

(4.2)			Form of 9.250% Senior Note due 2026 (included as Exhibit A to Exhibit 4.1).

(10.1)			Form of Support Agreement, by and between Penn Virginia and the stockholders of Lonestar Resources US Inc. set forth on Schedule A thereto included as Exhibit A to Exhibit 2.1).

(10.2)			Support 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).

(10.3)			Purchase Agreement, dated July 27, 2021, by and among Penn Virginia Escrow LLC, Penn Virginia Holdings, LLC, the guarantors named therein and B of A Securities, Inc., as Representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on July 29, 2021).

(10.4) *			Amendment No. 10 to the Credit Agreement

(10.5)			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.

(31.2) *			Certification Pursuant to Rule 13a-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32.1) †			Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(32.2) †			Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(101.INS) *			Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

(101.SCH) *			Inline XBRL Taxonomy Extension Schema Document

(101.CAL) *			Inline XBRL Taxonomy Extension Calculation Linkbase Document

(101.DEF) *			Inline XBRL Taxonomy Extension Definition Linkbase Document

(101.LAB) *			Inline XBRL Taxonomy Extension Label Linkbase Document

(101.PRE) *			Inline XBRL Taxonomy Extension Presentation Linkbase Document

(104) *			The cover page of Ranger Oil Corporation’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2021, formatted in Inline XBRL (included within the Exhibit 101 attachments).

_____________________________

* Filed herewith.

† Furnished herewith.

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, 2021	By:	/s/ RUSSELL T KELLEY, JR.
		Russell T Kelley, Jr.
		Senior Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

November 4, 2021	By:	/s/ KAYLA D. BAIRD
		Kayla D. Baird
		Vice President, Chief Accounting Officer and Controller
		(Principal Accounting Officer)