UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended March 31, ~~2021~~2022


☐			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

~~PENN VIRGINIA~~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~~Park Ten Place, Suite 500

~~HOUSTON,~~Houston, TX 77084

(Address of principal executive offices) (Zip Code)

(713) 722-6500

(Registrant’s telephone number, including area code)

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Class A Common Stock, $0.01 Par Value

~~PVAC~~ROCC

The Nasdaq ~~Global Select~~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

☐

Accelerated ~~Filer~~filer

☒

Non-accelerated ~~Filer~~filer

☐

Smaller ~~Reporting Company~~reporting company

☒

Emerging ~~Growth Company~~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 ☒

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Exchange Act subsequent to the distribution of securities under a plan confirmed by a court. Yes ☒No ☐

As of April ~~30, 2021,~~28, 2022, there were ~~37,857,930~~43,712,392 shares of common stock ~~and common stock equivalents~~ outstanding, including ~~15,309,821~~21,163,394 shares of ~~common stock~~Class A Common Stock and ~~equity with economic and voting power equal to 22,548,109~~22,548,998 shares of ~~common stock (as further described in this Quarterly Report on Form 10-Q).~~Class B Common Stock.

~~PENN VIRGINIA~~RANGER OIL CORPORATION

QUARTERLY REPORT ON FORM 10-Q

For the Quarterly Period Ended March 31, ~~2021~~2022

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
4
Condensed Consolidated Balance Sheets
5
Condensed Consolidated Statements of Cash Flows
6
Notes to Condensed Consolidated Financial Statements:
1. Nature of Operations
7
2. Basis of Presentation
7
3. Juniper Transactions
7
4. Accounts Receivable and Revenues from Contracts with Customers
9
5. Derivative Instruments
10
6. Property and Equipment
13
7. Long-Term Debt
13
8. Income Taxes
15
9. Leases
15
10. Supplemental Balance Sheet Detail
17
11. Fair Value Measurements
17
12. Commitments and Contingencies
19
13. Equity
19
14. Share-Based Compensation and Other Benefit Plans
20
15. Interest Expense
21
16. Earnings per Share
22
Forward-Looking Statements
22
2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Overview and Executive Summary
24
Key Developments
26
Financial Condition
28
Results of Operations
33
Off Balance Sheet Arrangements
40
Critical Accounting Estimates
40
3. Quantitative and Qualitative Disclosures About Market Risk.
40
4. Controls and Procedures.
42
Part II - Other Information
1. Legal Proceedings.
43
1A. Risk Factors.
43
5. Other Information.
43
6. Exhibits.
44
Signatures
45


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

Part I. FINANCIAL INFORMATION

Item 1. Financial ~~Statements.~~Statements

~~PENN VIRGINIA~~RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – ~~unaudited~~UNAUDITED

(in thousands, except per share data)


		Three Months Ended March 31,						Three Months Ended March 31,
			2021		2020				2022		2021
Revenues and other	Revenues and other						Revenues and other
Crude oil	Crude oil		$	81,913	$	86,308	Crude oil		$	226,732	$	81,913
Natural gas liquids	Natural gas liquids		3,562		1,893		Natural gas liquids		16,740		3,562
Natural gas	Natural gas		2,833		2,690		Natural gas		12,127		2,833
Other operating income, net	Other operating income, net		247		488		Other operating income, net		856		247
Total revenues and other	Total revenues and other		88,555		91,379		Total revenues and other		256,455		88,555
Operating expenses	Operating expenses						Operating expenses
Lease operating	Lease operating		8,825		10,532		Lease operating		18,102		8,825
Gathering, processing and transportation	Gathering, processing and transportation		4,674		5,444		Gathering, processing and transportation		9,040		4,674
Production and ad valorem taxes	Production and ad valorem taxes		5,513		6,154		Production and ad valorem taxes		13,140		5,513
General and administrative	General and administrative		13,177		7,230		General and administrative		9,779		13,177
Depreciation, depletion and amortization	Depreciation, depletion and amortization		23,884		40,718		Depreciation, depletion and amortization		50,893		23,884
Impairments of oil and gas properties	Impairments of oil and gas properties		1,811		0		Impairments of oil and gas properties		—		1,811
Total operating expenses	Total operating expenses		57,884		70,078		Total operating expenses		100,954		57,884
Operating income	Operating income		30,671		21,301		Operating income		155,501		30,671
Other income (expense)	Other income (expense)						Other income (expense)
Interest expense			(5,397)		(8,180)
Loss on extinguishment of debt			(1,231)		0
Derivatives			(44,368)		151,119
Interest expense, net of amounts capitalized							Interest expense, net of amounts capitalized		(10,697)		(5,397)
Gain (loss) on extinguishment of debt							Gain (loss) on extinguishment of debt		2,157		(1,231)
Derivative losses							Derivative losses		(167,887)		(44,368)
Other, net	Other, net		(6)		(8)		Other, net		76		(6)
Income (loss) before income taxes			(20,331)		164,232
Income tax (expense) benefit			310		(1,138)
Net income (loss)			(20,021)		163,094
Loss before income taxes							Loss before income taxes		(20,850)		(20,331)
Income tax benefit							Income tax benefit		189		310
Net loss							Net loss		(20,661)		(20,021)
Net loss attributable to Noncontrolling interest	Net loss attributable to Noncontrolling interest		6,449		0		Net loss attributable to Noncontrolling interest		10,676		6,449
Net income (loss) attributable to common shareholders			$	(13,572)	$	163,094
Net income (loss) per share:
Net loss attributable to common shareholders							Net loss attributable to common shareholders		$	(9,985)	$	(13,572)

Net loss per share attributable to common shareholders:							Net loss per share attributable to common shareholders:
Basic	Basic		$	(0.89)	$	10.76	Basic		$	(0.47)	$	(0.89)
Diluted	Diluted		$	(0.89)	$	10.76	Diluted		$	(0.47)	$	(0.89)

Weighted average shares outstanding – basic	Weighted average shares outstanding – basic		15,263		15,152		Weighted average shares outstanding – basic		21,107		15,263
Weighted average shares outstanding – diluted	Weighted average shares outstanding – diluted		15,263		15,160		Weighted average shares outstanding – diluted		21,107		15,263

See accompanying notes to condensed consolidated financial statements.

~~PENN VIRGINIA~~RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE ~~INCOME~~LOSS – ~~unaudited~~UNAUDITED

(in thousands)

Three Months Ended March 31,
2021 2020
Net income (loss) $ (20,021) $ 163,094
Other comprehensive income (loss):
Change in pension and postretirement obligations, net of tax 2 (1)
2 (1)
Comprehensive income (loss) (20,019) 163,093
Net loss attributable to Noncontrolling interest 6,449 0
Other comprehensive income attributable to Noncontrolling interest (1) 0
Comprehensive income (loss) attributable to common shareholders $ (13,571) $ 163,093


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

See accompanying notes to condensed consolidated financial statements.

~~PENN VIRGINIA~~RANGER OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS – ~~unaudited~~UNAUDITED

(in thousands, except share data)


		March 31,		December 31,
		2021		2020			March 31, 2022		December 31, 2021
Assets	Assets					Assets
Current assets	Current assets					Current assets
Cash and cash equivalents	Cash and cash equivalents	$	11,868	$	13,020	Cash and cash equivalents	$	6,358	$	23,681
Accounts receivable, net of allowance for credit losses	Accounts receivable, net of allowance for credit losses	66,371		45,849		Accounts receivable, net of allowance for credit losses	154,179		118,594
Derivative assets	Derivative assets	13,093		75,506		Derivative assets	9,631		11,478

Prepaid and other current assets	Prepaid and other current assets	19,547		19,045		Prepaid and other current assets	15,989		20,998
Assets held for sale						Assets held for sale	11,400		11,400
Total current assets	Total current assets	110,879		153,420		Total current assets	197,557		186,151
Property and equipment, net (full cost method)	Property and equipment, net (full cost method)	792,077		723,549		Property and equipment, net (full cost method)	1,417,715		1,383,348
Derivative assets	Derivative assets	5,269		25,449		Derivative assets	2,912		2,092

Other assets	Other assets	4,906		4,908		Other assets	4,636		5,017
Total assets	Total assets	$	913,131	$	907,326	Total assets	$	1,622,820	$	1,576,608

Liabilities and Equity	Liabilities and Equity					Liabilities and Equity
Current liabilities	Current liabilities					Current liabilities
Accounts payable and accrued liabilities	Accounts payable and accrued liabilities	$	99,950	$	63,089	Accounts payable and accrued liabilities	246,189		214,381
Derivative liabilities	Derivative liabilities	44,328		85,106		Derivative liabilities	149,008		50,372
Current portion of long-term debt	Current portion of long-term debt	7,500		0		Current portion of long-term debt	1,925		4,129
Total current liabilities	Total current liabilities	151,778		148,195		Total current liabilities	397,122		268,882

Deferred income taxes	Deferred income taxes	397		0		Deferred income taxes	2,073		2,793
Derivative liabilities	Derivative liabilities	14,914		28,434		Derivative liabilities	42,620		23,815
Other non-current liabilities	Other non-current liabilities	8,337		8,362		Other non-current liabilities	9,900		10,358
Long-term debt, net	Long-term debt, net	363,562		509,497		Long-term debt, net	521,780		601,252

Commitments and contingencies (Note 12)		0		0
Commitments and contingencies (Note 11)						Commitments and contingencies (Note 11)	0		0

Equity	Equity					Equity
Preferred stock of $0.01 par value – 5,000,000 shares authorized; 225,481.09 and NaN issued at March 31, 2021 and December 31, 2020, respectively		2		0
Common stock of $0.01 par value – 45,000,000 shares authorized; 15,309,821 and 15,200,435 shares issued as of March 31, 2021 and December 31, 2020, respectively		153		152
Preferred stock of $0.01 par value – 5,000,000 shares authorized; none issued as of March 31, 2022 and December 31, 2021						Preferred stock of $0.01 par value – 5,000,000 shares authorized; none issued as of March 31, 2022 and December 31, 2021	—		—
Class A common stock of $0.01 par value – 110,000,000 shares authorized; 21,146,230 and 21,090,259 shares issued as of March 31, 2022 and December 31, 2021, respectively						Class A common stock of $0.01 par value – 110,000,000 shares authorized; 21,146,230 and 21,090,259 shares issued as of March 31, 2022 and December 31, 2021, respectively	729		729
Class B common stock of $0.01 par value – 30,000,000 shares authorized; 22,548,998 shares issued as of March 31, 2022 and December 31, 2021						Class B common stock of $0.01 par value – 30,000,000 shares authorized; 22,548,998 shares issued as of March 31, 2022 and December 31, 2021	2		2
Paid-in capital	Paid-in capital	155,164		203,463		Paid-in capital	273,807		273,329
Retained earnings (Accumulated deficit)		(4,218)		9,354
Retained earnings						Retained earnings	39,598		49,583
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(130)		(131)		Accumulated other comprehensive loss	(111)		(111)
Ranger Oil shareholders’ equity						Ranger Oil shareholders’ equity	314,025		323,532
Noncontrolling interest	Noncontrolling interest	223,172		0		Noncontrolling interest	335,300		345,976
Total equity	Total equity	374,143		212,838		Total equity	649,325		669,508
Total liabilities and equity	Total liabilities and equity	$	913,131	$	907,326	Total liabilities and equity	$	1,622,820	$	1,576,608

See accompanying notes to condensed consolidated financial statements.

~~PENN VIRGINIA~~RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – ~~unaudited~~UNAUDITED

(in thousands)


		Three Months Ended March 31,					Three Months Ended March 31,
		2021		2020			2022		2021
Cash flows from operating activities	Cash flows from operating activities					Cash flows from operating activities
Net income (loss)		$	(20,021)	$	163,094
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss on exchange of debt		1,231		0
Net loss						Net loss	$	(20,661)	$	(20,021)
Adjustments to reconcile net loss to net cash provided by operating activities:						Adjustments to reconcile net loss to net cash provided by operating activities:
(Gain) loss on extinguishment of debt						(Gain) loss on extinguishment of debt	(2,157)		1,231
Depreciation, depletion and amortization	Depreciation, depletion and amortization	23,884		40,718		Depreciation, depletion and amortization	50,893		23,884
Impairments of oil and gas properties	Impairments of oil and gas properties	1,811		0		Impairments of oil and gas properties	—		1,811
Derivative contracts:	Derivative contracts:					Derivative contracts:
Net (gains) losses		44,368		(151,119)
Cash settlements and premiums received (paid), net		(7,169)		(269)
Deferred income tax expense (benefit)		(310)		2,320
Gain on sales of assets, net		(4)		(6)
Net losses						Net losses	167,887		44,368
Cash settlements and premiums paid, net						Cash settlements and premiums paid, net	(29,408)		(7,169)
Deferred income tax benefit						Deferred income tax benefit	(721)		(310)
Non-cash interest expense	Non-cash interest expense	611		823		Non-cash interest expense	800		611
Share-based compensation	Share-based compensation	2,246		856		Share-based compensation	924		2,246
Other, net	Other, net	6		8		Other, net	(182)		2
Changes in operating assets and liabilities, net	Changes in operating assets and liabilities, net	(14,442)		16,048		Changes in operating assets and liabilities, net	(33,540)		(13,966)
Net cash provided by operating activities	Net cash provided by operating activities	32,211		72,473		Net cash provided by operating activities	133,835		32,687

Cash flows from investing activities	Cash flows from investing activities					Cash flows from investing activities

Capital expenditures	Capital expenditures	(34,758)		(62,015)		Capital expenditures	(71,173)		(34,758)
Proceeds from sales of assets, net	Proceeds from sales of assets, net	4		75		Proceeds from sales of assets, net	656		4

Net cash used in investing activities	Net cash used in investing activities	(34,754)		(61,940)		Net cash used in investing activities	(70,517)		(34,754)

Cash flows from financing activities	Cash flows from financing activities					Cash flows from financing activities
Proceeds from credit facility borrowings	Proceeds from credit facility borrowings	0		46,000		Proceeds from credit facility borrowings	50,000		—
Repayment of credit facility borrowings		(85,500)		(9,000)
Repayment of second lien term loan		(53,140)		0
Repayments of credit facility borrowings						Repayments of credit facility borrowings	(130,000)		(85,500)
Repayments of second lien term loan						Repayments of second lien term loan	—		(53,140)
Repayments of acquired debt						Repayments of acquired debt	(83)		—
Proceeds from redeemable common units	Proceeds from redeemable common units	151,160		0		Proceeds from redeemable common units	—		151,160
Proceeds from redeemable preferred stock	Proceeds from redeemable preferred stock	2		0		Proceeds from redeemable preferred stock	—		2
Transaction costs paid on behalf of Noncontrolling interest	Transaction costs paid on behalf of Noncontrolling interest	(5,543)		0		Transaction costs paid on behalf of Noncontrolling interest	—		(5,543)
Issue costs paid for Noncontrolling interest securities		(3,758)		0
Issuance costs paid for Noncontrolling interest securities						Issuance costs paid for Noncontrolling interest securities	—		(3,758)
Withholding taxes for share-based compensation						Withholding taxes for share-based compensation	(445)		(476)
Debt issuance costs paid	Debt issuance costs paid	(1,830)		0		Debt issuance costs paid	(113)		(1,830)

Net cash provided by financing activities		1,391		37,000
Net increase (decrease) in cash and cash equivalents		(1,152)		47,533
Net cash provided by (used in) financing activities						Net cash provided by (used in) financing activities	(80,641)		915
Net decrease in cash and cash equivalents						Net decrease in cash and cash equivalents	(17,323)		(1,152)
Cash and cash equivalents – beginning of period	Cash and cash equivalents – beginning of period	13,020		7,798		Cash and cash equivalents – beginning of period	23,681		13,020
Cash and cash equivalents – end of period	Cash and cash equivalents – end of period	$	11,868	$	55,331	Cash and cash equivalents – end of period	$	6,358	$	11,868

Supplemental disclosures:	Supplemental disclosures:					Supplemental disclosures:
Cash paid for:	Cash paid for:					Cash paid for:
Interest, net of amounts capitalized	Interest, net of amounts capitalized	$	4,888	$	7,442	Interest, net of amounts capitalized	$	20,214	$	4,888

Non-cash investing and financing activities:	Non-cash investing and financing activities:					Non-cash investing and financing activities:
Changes in property and equipment related to capital contributions	Changes in property and equipment related to capital contributions	$	(38,415)	$	0	Changes in property and equipment related to capital contributions	$	—	$	(38,415)
Changes in asset retirement obligation related to capital contributions		$	14	$	0
Changes in accrued liabilities related to capital expenditures	Changes in accrued liabilities related to capital expenditures	$	20,246	$	18,660	Changes in accrued liabilities related to capital expenditures	$	9,361	$	20,246

See accompanying notes to condensed consolidated financial statements.

~~PENN VIRGINIA~~RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - UNAUDITED

(in thousands)


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

_______________________

1 Includes equity-classified share-based compensation of $0.9 million during the three months ended March 31, 2022. During the three months ended March 31, 2022, 69,206 of common stock were issued in connection with the vesting of certain time-vested restricted stock units (“RSUs”), net of shares withheld for income taxes. No shares of common stock were issued in connection with the vesting of performance-based restricted stock units (“PRSUs”) during the three months ended March 31, 2022.


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

_______________________

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

See accompanying notes to condensed consolidated financial statements.

RANGER OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – ~~unaudited~~UNAUDITED

For the Quarterly Period Ended March 31, ~~2021~~2022

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

~~1. Nature~~

Note 1 – Organization and Description of ~~Operations~~Business

~~Penn Virginia~~Ranger Oil Corporation (together with its consolidated subsidiaries, unless the context otherwise requires, ~~“Penn Virginia,~~“Ranger Oil,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company focused on the onshore ~~exploration,~~ 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 ~~Gonzales, Lavaca, Fayette and DeWitt Counties in~~ South Texas. We operate in and report our financial results and disclosures as ~~one~~1 segment, which is the ~~exploration,~~ development and production of crude oil, NGLs and natural gas.

~~2. Basis of Presentation~~

Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. A substantial nonncontrolling interest in our subsidiaries is provided for in our Condensed Consolidated Statements of Operations and Comprehensive Income as well as our Condensed Consolidated Balance Sheets as of and for the period ended March 31, 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 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 three months ended March 31, 2021 are not necessarily indicative of the results that may be expected for the year ending December 31, 2021. Certain amounts on the Condensed Consolidated Statements of Operation for the three months ended March 31, 2020 and the Condensed Consolidated Balance Sheet as of December 31, 2020 have been reclassified to conform to the 2021 presentation.

~~Subsequent Events~~

Management has evaluated all of our activities through the issuance date of our Condensed Consolidated Financial Statements and has concluded that no subsequent events have occurred that would require recognition or disclosure in our Condensed Consolidated Financial Statements or disclosure in the Notes thereto.

~~3. Juniper Transactions~~

On January 15, 2021, ~~(the “Closing Date”),~~ the Company consummated the ~~previously announced~~ 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 ~~its affiliates~~JSTX and Rocky Creek Resources, LLC, “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.~~

Partnership pursuant to which Juniper contributed $150 million in cash and certain oil and gas assets in South Texas in exchange for equity that entitles Juniper to both vote and share in any dividend on the same basis as 22,548,998 shares of our Class A Common Stock, par value $0.01 per share (“Class A Common Stock”) (after post-closing adjustments). In connection with the consummation of the Juniper Transactions, the Company completed a reorganization into an up-C structure which iswas intended to, among other things, result in the ~~holders~~affiliates of ~~the Series A Preferred Stock, par value $0.01 per share, of the Company (“Series A Preferred Stock”)~~Juniper Capital having a voting interest in the Company that is commensurate with such holders’ economic interest in the ~~Partnership, including (i)~~Partnership.

Note 2 – Summary of Significant Accounting Policies

Basis of Presentation

Our unaudited condensed consolidated financial statements include the ~~conversion~~accounts of ~~each~~Ranger Oil and all of our subsidiaries as of the relevant dates. Intercompany balances and transactions have been eliminated. A substantial noncontrolling interest in our subsidiaries is provided for in our condensed consolidated statements of operations and comprehensive loss and our condensed consolidated balance sheets for the periods presented. Our condensed consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) and the rules and regulations of the Securities Exchange Commission (the “SEC”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments considered necessary for a fair presentation of our condensed consolidated financial statements have been included. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications did not have a material impact on prior period financial statements. Our condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes included in our Annual Report on Form 10-K for the year ended December 31, 2021. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

Significant Accounting Policies

The Company’s ~~corporate subsidiaries into limited liability companies which~~significant accounting policies are ~~disregarded~~described in “Note 3 – Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in its Annual Report on Form 10-K for ~~U.S. federal income tax purposes, including~~ the ~~conversion of Penn Virginia Holding Corp. into Penn Virginia Holdings, LLC, a Delaware limited liability company~~year ended December 31, 2021 (“~~Holdings”~~2021 Annual Report”), and ~~(ii)~~are supplemented by the notes included in this Quarterly Report on Form 10-Q. The financial statements and related notes included in this report should be read in conjunction with the Company’s ~~contribution~~2021 Annual Report.

Recent Accounting Pronouncements

We consider the applicability and impact of all ~~of its equity interests in Holdings~~Accounting Standard Updates (“ASUs”). ASUs not listed below were assessed and determined to ~~the Partnership in exchange for 15,268,686 newly issued common units representing limited partner interests (the “Common Units”).~~be not applicable.

Recently Issued Accounting Pronouncements Not Yet Adopted

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

Note 3 – Acquisition

Acquisition of Lonestar Resources

On October 5, 2021 (the “Closing Date”), the ~~Closing Date, (i)~~Company acquired Lonestar Resources US Inc., a Delaware corporation (“Lonestar”), as a result of which Lonestar and its subsidiaries became wholly-owned subsidiaries of the Company (the “Lonestar Acquisition”). The Lonestar Acquisition was effected pursuant to the Agreement and Plan of Merger (the “Merger Agreement”), dated July 10, 2021, by and between the Company and Lonestar. In accordance with the terms of the ~~Contribution~~Merger Agreement, ~~JSTX contributed~~Lonestar shareholders received 0.51 shares of the Company’s common stock for each share of Lonestar common stock held immediately prior 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 at a price equal to the par valueeffective time of the ~~shares acquired, and (ii) pursuant to~~Lonestar Acquisition. Based on the ~~terms~~closing price of the ~~Asset Agreement, including certain closing adjustments based~~Company’s common stock on ~~a September 1, 2020 effective date (the “Effective Date”), Rocky Creek contributed to our operating subsidiary certain oil~~October 5, 2021 of $30.19, 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 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 an indemnity escrow to support post-closing indemnification claims, 50% of such escrowed amount to be disbursed 180 days after the Closing and the remainder one year after the Closing. 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 2020 through the 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 Consolidated Balance Sheet. The remainder of $4.7 million, representing professional fees and other costs, has been 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) on and after July 14, 2021 and there’s no fixed or determinable date or fixed or determinable price for redemption; further, while the Common Units may be redeemed with 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, who also own the Common Units, could cause the Non-controlling 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~~Lonestar Acquisition, the total Common Units outstanding which is also equivalent to the voting power in the Company associated with the Series A Preferred Stock held by Juniper. The Noncontrolling interest was initially measured on the Closing Date as the sum of (i) total Shareholders’ equity immediately prior to the closing 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 of 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~~Company’s common stock issued to holders of Lonestar common stock, warrants and restricted stock units as applicable, was ~~recorded as a reduction to paid-in capital.~~

approximately $173.6 million.

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

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

Pro Forma Operating Results (Unaudited)

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

~~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~~

~~38,415~~

~~Revenues received attributable to contributed properties~~

~~1,160~~

~~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 Closing Date~~

~~205,558~~

~~385,110~~

~~Juniper voting power through Series A Preferred Stock~~

~~59.6~~

~~Noncontrolling interest as of the Closing Date~~

~~229,620~~

~~Net loss attributable to Noncontrolling interest~~

~~(6,449)~~

~~Other comprehensive income attributable to Noncontrolling interest~~

~~Noncontrolling interest as of~~Three Months Ended March 31, 2021

Total revenues

~~223,172~~128,371

Net income (loss) attributable to common shareholders

(23,850)

Note 4 – Revenue Recognition

~~4. Accounts Receivable and Revenues~~Revenue from Contracts with Customers

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

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

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

Performance obligations

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

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

Accounts Receivable ~~and Major~~from Contracts with Customers

Our accounts receivable consists mainly of trade receivables from commodity sales and joint interest billings due from partners on properties we operate. Our allowance for credit losses is entirely attributable to receivables from joint interest partners. We generally have the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, our oil, natural gas, and NGL receivables are collected within 30 to 90 days. The following table summarizes our accounts receivable by type as of the dates presented:

March 31, December 31,
2021 2020
Customers $ 52,623 $ 39,672
Joint interest partners 11,270 3,079
Derivative settlements from counterparties 2,835 3,287
Other 7 8
66,735 46,046
Less: Allowance for credit losses (364) (197)
$ 66,371 $ 45,849

~~Revenue from Contracts with Customers~~

For the three months ended March 31, 2021, 3 customers accounted for $54.1 million, or approximately 61%, of our consolidated product revenues. The revenues generated from these customers during the three months ended March 31, 2021, were $23.0 million, $20.1 million and $11.0 million, or 26%, 23% and 12% of the consolidated total, respectively. For the three months ended March 31, 2020, 4 customers accounted for $66.5 million, or approximately 73%, of our consolidated product revenues. As of March 31, 2021 and December 31, 2020, $23.5 million and $24.1 million, or approximately 45% and 61%, respectively, of our consolidated accounts receivable from customers was related to these customers. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers.

~~Credit Losses and Allowance for Credit Losses~~

In accordance with our accounting policies, we assess our portfolio of accounts receivable for credit losses by assigning credit risks to receivables originating by portfolio segment type as described below.

~~Customers~~. We sell our commodity products to approximately 16 customers. A substantial majority of these customers are large, internationally recognized refiners and marketers in the case of our crude oil sales and large domestic processors and interstate pipelines with respect to our NGL and natural gas sales. Due primarily to the historical market efficiencies and generally timely settlements associated with commodity sale transactions for crude oil, NGLs and natural gas, we have assessed this portfolio segment at 0 risk for those receivables originated during the three months ended March 31, 2021.

~~Mutual Operators~~. As of March 31, 2021, we had mutual joint interest partner relationships with 2 upstream producers that also operate properties for which we have non-operated working interests. We have assessed receivables from these operators that originated in the three months ended March 31, 2021 with a 5 percent risk.

~~Large Partners~~. As of March 31, 2021, 5 legal entities had working interests of 10 percent or greater in properties that we operate. These entities are primarily passive investors. We have assessed receivables from these entities that originated in the three months ended March 31, 2021 with a 2 percent risk.

~~All Others~~. As of March 31, 2021, approximately 15 legal entities had working interests of less than 10 percent in properties that we operate. We have assessed receivables from these entities that originated in the three months ended March 31, 2021 with a 10 percent risk. As of March 31, 2021 and December 31, 2020, approximately $0.2 million of accounts receivables attributable to this portfolio segment was past due, or over 60 days. In addition, the derivative settlements from counterparties referenced in the table above have been assessed zero risk. Collectability from these counterparties is discussed further in Note 5.

As of March 31, 2021 and December 31, 2020, the allowance for credit losses is entirely attributable to receivables from joint interest partners. The following table summarizes the activity in our allowance for credit losses, by portfolio segment, for the three months ended March 31, 2021:

Mutual Operators Large Partners All Others Total
Balance at beginning of period $ 9 $ 87 $ 101 $ 197
Provision for expected credit losses (7) 202 (28) 167
Write-offs and recoveries 0 0 0 0
Balance at end of period $ 2 $ 289 $ 73 $ 364


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

5.Note 5 – Derivative Instruments

We utilize derivative instruments, typically swaps, put options and call options which are placed with financial institutions that we believe are acceptable credit risks, to mitigate our financial exposure to commodity price volatility associated with anticipated sales of our future production and volatility in interest rates attributable to our variable rate debt instruments. Our derivative instruments are not formally designated as hedges ~~in the context of GAAP.~~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~~

~~The following is a general description of the~~For our commodity ~~derivative instruments~~derivatives, we ~~have employed:~~

~~Swaps~~. A swap contract is an agreement between two parties pursuant to which the parties exchange payments at specified dates on the basis of a specified notional amount, or the swap price, with the payments calculated by reference to specified commodities or indexes. The counterparty to a swap contract is required to make a payment to us based on the amount of the swap price in excess of the settlement price multiplied by the notional volume if the settlement price for any settlement period is below the swap price for such contract. We are required to make a payment to the counterparty based on the amount of the settlement price in excess of the swap price multiplied by the notional volume if the settlement price for any settlement period is above the swap price for such contract.

~~Put Options~~. A put option has a defined strike, or floor price. We have entered into put option contracts in the roles of buyer and seller depending upon our particular hedging objective. The buyer of the put option pays the seller a premium to enter into the contract. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the notional volume. When the settlement price is above the floor price, the put option expires worthless. Certain of our purchased put options have deferred premiums. For the deferred premium puts, we agree to pay a premium to the counterparty at the time of settlement.

~~Call Options~~. A call option has a defined strike, or ceiling price. We have entered into call option contracts in the roles of buyer and seller depending upon our particular hedging objective. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the notional volume. When the settlement price is below the ceiling price, the call option expires worthless.

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.

We determine the fair values of our commodity derivative instruments using industry-standard models that consider various assumptions, including current market value and contractual prices for the underlying instruments, implied volatilities, time value and nonperformance risk. For the current market prices, we use third-party quoted forward prices, as applicable, for NYMEX West Texas Intermediate (“NYMEX WTI”), Magellan East Houston (“MEH”) crude oil, NYMEX Henry Hub (“NYMEX HH”) natural gas and OPIS Mt. Belvieu Ethane (“OPIS Mt Belv Ethane”) natural gas liquids closing prices as of the end of the reporting period. Nonperformance 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.Commodity Derivatives 1

The following table sets forth our commodity derivative positions, presented on a net basis by period of maturity, as of March 31, ~~2021:~~2022:


		2Q2021		3Q2021		4Q2021		1Q2022		2Q2022		3Q2022		4Q2022		1Q2023	2Q2023		2Q2022		3Q2022		4Q2022		1Q2023		2Q2023		3Q2023		4Q2023		1Q2024		2Q2024
NYMEX WTI Crude Swaps	NYMEX WTI Crude Swaps																	NYMEX WTI Crude Swaps
Average Volume Per Day (bbl)	Average Volume Per Day (bbl)	3,297		815		815												Average Volume Per Day (bbl)	3,000		3,000		3,000		2,500		2,400		2,807		2,657		462		462
Weighted Average Swap Price ($/bbl)	Weighted Average Swap Price ($/bbl)	$	55.89	$	45.54	$	45.54											Weighted Average Swap Price ($/bbl)	$	74.12	$	73.01	$	69.20	$	54.40	$	54.26	$	54.92	$	54.93	$	58.75	$58.75
NYMEX WTI Crude Collars	NYMEX WTI Crude Collars																	NYMEX WTI Crude Collars
Average Volume Per Day (bbl)	Average Volume Per Day (bbl)	12,088		10,870		8,152		5,417		4,533		4,484		4,484		2,917	2,855	Average Volume Per Day (bbl)	17,720		14,266		9,375		6,250		6,181		1,630		1,630
Weighted Average Purchased Put Price ($/bbl)	Weighted Average Purchased Put Price ($/bbl)	$	43.82	$	41.80	$	40.40	$	40.00	$	40.00	$	40.00	$	40.00	40.00	40.00	Weighted Average Purchased Put Price ($/bbl)	$	59.12	$	57.14	$	52.17	$	50.67	$	50.67	$	60.00	$	60.00
Weighted Average Sold Call Price ($/bbl)	Weighted Average Sold Call Price ($/bbl)	$	54.67	$	56.09	$	52.10	$	53.49	$	52.47	$	52.47	$	52.47	50.00	50.00	Weighted Average Sold Call Price ($/bbl)	$	77.01	$	81.13	$	67.57	$	65.65	$	65.65	$	76.12	$	76.12
NYMEX WTI Sold Puts
Average Volume Per Day (bbl)		4,945		5,707		5,707
Weighted Average Sold Put Price ($/bbl)		$	29.83	$	35.14	$	35.14

NYMEX WTI Crude CMA Roll Basis Swaps	NYMEX WTI Crude CMA Roll Basis Swaps																	NYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (bbl)	Average Volume Per Day (bbl)	18,132		17,935		17,935												Average Volume Per Day (bbl)	20,879		14,674		14,674
Weighted Average Swap Price ($/bbl)	Weighted Average Swap Price ($/bbl)	$	0.17	$	0.17	$	0.17											Weighted Average Swap Price ($/bbl)	$	1.120	$	1.172	$	1.172
NYMEX HH Swaps																		NYMEX HH Swaps
Average Volume Per Day (MMBtu)																		Average Volume Per Day (MMBtu)	12,500		12,500		12,500		10,000		7,500
Weighted Average Swap Price ($/MMBtu)																		Weighted Average Swap Price ($/MMBtu)	$	3.727	$	3.745	$	3.793	$	3.620	$	3.690
NYMEX HH Collars	NYMEX HH Collars																	NYMEX HH Collars
Average Volume Per Day (MMBtu)	Average Volume Per Day (MMBtu)	9,890		9,783		9,783												Average Volume Per Day (MMBtu)	13,187		13,043		13,043				11,538		11,413		11,413		11,538		11,538
Weighted Average Purchased Put Price ($/MMBtu)	Weighted Average Purchased Put Price ($/MMBtu)	$	2.607	$	2.607	$	2.607											Weighted Average Purchased Put Price ($/MMBtu)	$	2.500	$	2.500	$	2.500			$	2.500	$	2.500	$	2.500	$	2.500	$	2.328
Weighted Average Sold Call Price($/MMBtu)	Weighted Average Sold Call Price($/MMBtu)	$	3.117	$	3.117	$	3.117											Weighted Average Sold Call Price($/MMBtu)	$	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)		6,593		6,522		6,522
Weighted Average Sold Put Price ($/MMBtu)		$	2.000	$	2.000	$	2.000

OPIS Mt Belv Ethane Swaps	OPIS Mt Belv Ethane Swaps																	OPIS Mt Belv Ethane Swaps
Average Volume per Day (gal)	Average Volume per Day (gal)	36,264		35,870														Average Volume per Day (gal)	28,022		27,717		27,717				98,901		34,239		34,239		34,615
Weighted Average Fixed Price ($/gal)	Weighted Average Fixed Price ($/gal)	$	0.2263	$	0.2288													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

~~We have~~As of March 31, 2022, we had a series of interest rate swap contracts (the “Interest Rate Swaps”) establishing fixed interest rates on a portion of our variable interest rate ~~indebtedness under the credit agreement (the “Credit Facility”) and the Second Lien Credit Agreement, dated as of September 29, 2017 (the “Second Lien Facility”).~~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 ~~in the “Derivatives” caption~~within Derivatives on our ~~Condensed Consolidated Statements~~condensed consolidated statements of ~~Operations.~~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”~~Accounts receivable (see Note 4) and ~~“Accounts~~Accounts payable and accrued ~~liabilities”~~liabilities (see Note ~~10)~~9) on the ~~Condensed Consolidated Balance Sheets.~~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 inwithin the ~~“Derivative contracts”~~Derivative contracts section of our ~~Condensed Consolidated Statements~~condensed consolidated statements of ~~Cash Flows~~cash flows under ~~“Net (gains) losses”~~Net losses and ~~“Cash~~Cash settlements and premiums ~~received (paid),~~paid, net.”

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

Three Months Ended March 31,
2021 2020
Interest rate swap gains (losses) recognized in the Condensed Consolidated Statements of Operations $ 32 $ (6,683)
Commodity gains (losses) recognized in the Condensed Consolidated Statements of Operations (44,400) 157,802
$ (44,368) $ 151,119
Interest rate cash settlements recognized in the Condensed Consolidated Statements of Cash Flows $ (922) $ 68
Commodity cash settlements and premiums received (paid) recognized in the Condensed Consolidated Statements of Cash Flows (6,247) (337)
$ (7,169) $ (269)


	Three Months Ended March 31,
		2022		2021
Interest Rate Swap gains recognized in the condensed consolidated statements of operations		$	83	$	32
Commodity losses recognized in the condensed consolidated statements of operations		(167,970)		(44,400)
		$	(167,887)	$	(44,368)

Interest rate cash settlements recognized in the condensed consolidated statements of cash flows		$	(938)	$	(922)
Commodity cash settlements and premiums paid recognized in the condensed consolidated statements of cash flows		(28,470)		(6,247)
		$	(29,408)	$	(7,169)

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


													Fair Values
			March 31, 2021				December 31, 2020						March 31, 2022				December 31, 2021
			Derivative		Derivative		Derivative		Derivative				Derivative		Derivative		Derivative		Derivative
Type	Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities		Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Interest rate contracts	Interest rate contracts	Derivative assets/liabilities - current	$	0	$	3,730	$	0	$	3,655	Interest rate contracts	Derivative assets/liabilities – current	$	—	$	458	$	—	$	1,480
Commodity contracts	Commodity contracts	Derivative assets/liabilities – current	13,093		40,598		75,506		81,451		Commodity contracts	Derivative assets/liabilities – current	9,631		148,550		11,478		48,892
Interest rate contracts	Interest rate contracts	Derivative assets/liabilities - noncurrent	0		615		0		1,645		Interest rate contracts	Derivative assets/liabilities – non-current	—		—		—		—
Commodity contracts	Commodity contracts	Derivative assets/liabilities – noncurrent	5,269		14,299		25,449		26,789		Commodity contracts	Derivative assets/liabilities – non-current	2,912		42,620		2,092		23,815
			$	18,362	$	59,242	$	100,955	$	113,540			$	12,543	$	191,628	$	13,570	$	74,187

As of March 31, ~~2021,~~2022, we reported net commodity derivative liabilities of ~~$36.5~~$178.6 million and net Interest Rate Swap liabilities of ~~$4.3~~$0.5 million. The contracts associated with these positions are with 78 counterparties for commodity derivatives and 4 counterparties for Interest Rate Swaps, all of which are investment grade financial institutions and are participants in ~~the Credit Facility.~~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.Note 6 – Property and Equipment

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


		March 31,		December 31,
		2021		2020			March 31, 2022		December 31, 2021
Oil and gas properties:	Oil and gas properties:					Oil and gas properties:
Proved	Proved	$	1,626,435	$	1,545,910	Proved	$	2,412,399	$	2,327,686
Unproved	Unproved	63,489		49,935		Unproved	58,686		57,900
Total oil and gas properties	Total oil and gas properties	1,689,924		1,595,845		Total oil and gas properties	2,471,085		2,385,586
Other property and equipment		27,796		27,746
Other property and equipment 1						Other property and equipment 1	31,060		31,055
Total properties and equipment	Total properties and equipment	1,717,720		1,623,591		Total properties and equipment	2,502,145		2,416,641
Accumulated depreciation, depletion and amortization		(925,643)		(900,042)
		$	792,077	$	723,549
Accumulated depreciation, depletion, amortization and impairments						Accumulated depreciation, depletion, amortization and impairments	(1,084,430)		(1,033,293)
Total property and equipment, net						Total property and equipment, net	$	1,417,715	$	1,383,348

_______________________

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

Unproved property costs of ~~$63.5~~$58.7 million and ~~$49.9~~$57.9 million have been excluded from amortization as of March 31, ~~2021~~2022 and December 31, 2020, respectively. An additional $0.5 million and $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 March 31, 2021, ~~and December 31, 2020,~~ respectively. We transferred ~~$7.6~~$0.7 million and ~~$1.4~~$7.6 million of undeveloped leasehold costs, including capitalized interest, associated with proved undeveloped reserves, acreage unlikely to be drilled or ~~associated with proved undeveloped reserves, including capitalized interest,~~expiring acreage, from unproved properties to the full cost pool during the three months ended March 31, ~~2021~~2022 and ~~2020,~~2021, respectively. We capitalized internal costs of ~~$0.7~~$1.4 million and ~~$0.8~~$0.7 million and interest of ~~$0.8~~$1.1 million and ~~$0.7~~$0.8 million during the three months ended March 31, ~~2021~~2022 and ~~2020,~~2021, respectively, in accordance with our accounting policies. Average depreciation, depletion and amortization per barrel of oil equivalent of proved oil and gas properties was ~~$12.92~~$14.98 and ~~$16.73~~$12.92 for the three months ended March 31, ~~2021~~2022 and ~~2020,~~2021, respectively.

At the end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated after-tax discounted future net revenues from proved properties adjusted for costs excluded from amortization (the “Ceiling Test”). AsBeginning in early 2020, certain events such as the COVID-19 pandemic and the decisions by the Organization of ~~March 31,~~the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, collectively “OPEC+”) negatively impacted the oil and gas industry with significant declines in crude oil prices and oversupply of crude oil. Over the past year, however, increased mobility, deployment of vaccines and other factors have resulted in increased oil demand and commodity prices. A high level of uncertainty remains regarding the volatility of energy supply and demand as a result of OPEC’s continued strategy to increase production as well as the Russia-Ukraine conflict and related sanctions which began in the first quarter of 2022. WTI crude oil prices have surged, closing at over $120 per bbl during first quarter 2022 due to concerns that it might result in significant oil supply shortages. Because the Ceiling Test utilizes commodity prices based on a trailing 12 month average, the decline in commodity prices in the first quarter of 2021 ~~the carrying value~~as a result of COVID-19 and macroeconomic factors resulted in impairments of our ~~proved~~ oil and gas properties ~~exceeded the limit determined by the Ceiling Test, resulting in a~~of $1.8 million ~~impairment for~~during the ~~quarter.~~

three months ended March 31, 2021. We did not record any impairments of our oil and gas properties during the three months ended March 31, 2022.

7.Note 7 – Long-Term Debt

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

March 31, 2021 December 31, 2020
Principal
Unamortized Discount and Deferred Issuance Costs 1, 2
Principal
Unamortized Discount and Deferred Issuance Costs 1, 2
Credit facility $ 228,900 $ 314,400
Second lien term loan 146,860 $ 4,698 200,000 $ 4,903
Totals 375,760 $ 4,698 514,400 $ 4,903
Less: Unamortized discount 2
(1,096) (1,604)
Less: Unamortized deferred issuance costs 1, 2
(3,602) (3,299)
Totals, net $ 371,062 $ 509,497
Less: Current portion (7,500) 0
Long-term debt $ 363,562 $ 509,497


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

_______________________

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

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

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

4 Excludes issuance costs associated with the Credit Facility, which ~~represent~~represents costs attributable to the access to credit over its contractual term, that have been presented as a component of Other assets (see Note ~~10)~~9) and are being amortized over the term of the Credit Facility using the straight-line method.

2 ~~Discount and issuance costs~~Credit Facility

As of March 31, 2022, the ~~Second Lien Facility are being amortized over the term of the underlying loan using the effective-interest method.~~

~~Credit Facility~~

~~The~~ Credit Facility ~~provides for~~had a $1.0 billion revolving commitment and a ~~$375~~$725 million borrowing base ~~including~~with aggregate elected commitments of $400 million, and a $25 million sublimit for the issuance of letters of credit. Availability under the Credit Facility may not exceed the lesser of the aggregate elected commitments or the borrowing ~~base; however,~~base less outstanding ~~borrowings under the Credit Facility are limited to a maximum~~advances and letters of ~~$350 million.~~credit. The borrowing base under the Credit Facility is redetermined semi-annually, generally in the Spring and Fall of each year. Our next borrowing base redetermination is scheduled in May 2022. Additionally, we and the Credit Facility lenders ~~generally~~ may, upon request, initiate a redetermination at any time during the six-month period between scheduled redeterminations. However, we have the option to forego a redetermination until Fall 2021 assuming we continue to satisfy certain minimum hedging conditions that became effective with the Agreement and Amendment No. 9 to Credit Agreement (the “Ninth Amendment”) in January 2021. The Credit Facility is available to us for general corporate purposes, including working capital. The Credit Facility is scheduled to mature in May 2024. We had $0.4 million in letters of credit outstanding as of March 31, 2021 and December 31, 2020. During the three months ended March 31, 2021, we incurred and capitalized approximately $0.4 million of issue costs associated with the Ninth Amendment.

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,~~2023, plus an applicable margin ranging from 2.50% to 3.50%, determined based on the utilization level under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on Eurodollar borrowings is payable every one, three or six months, at the election of the borrower, and is computed on the basis of a year of 360 days. As of March 31, ~~2021,~~2022, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was ~~3.11%~~3.02%. Unused commitment fees are charged at a rate of 0.50%.

The Credit Facility is guaranteed by the Partnership and all of its subsidiaries (excluding the borrower subsidiary) ( the “Guarantor Subsidiaries”). 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.

The Credit Facility requires us to maintain (1) a minimum current ratio (as defined in the Credit Facility, which considers the unused portion of the total commitment as a current asset), measured as of the last day of each fiscal quarter of 1.00 to 1.00 and (2) a maximum leverage ratio (consolidated indebtedness to adjusted earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses, both as defined in the Credit Facility), measured as of the last day of each fiscal quarter of 3.50 to 1.00 and (3) a maximum first lien leverage ratio (consolidated secured indebtedness to adjusted earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses, both as defined in the Credit Facility), measured as of the last day of each fiscal quarter, of 2.50 to 1.00.

The Credit Facility also contains other customary affirmative and negative covenants ~~including~~ as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports and budgets, weekly cash balance reports, 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, the Credit Facility contains certain anti-cash hoarding provisions, including the requirement to repay outstanding loans and cash collateralize outstanding letters of credit on a weekly basis in the amount of any cash on the balance sheet (subject to certain exceptions) in excess of $25 million.

~~The Credit Facility contains~~well as events of default and remedies. If we do not comply with the financial and other covenants in the Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Credit Facility.

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

9.25% Senior Notes due 2026

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

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

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

As of March 31, 2022, we were in compliance with all ~~of the covenants under the Credit Facility.~~

~~Second Lien Facility~~

We entered into the $200 million Second Lien Facility in September 2017 at which time we received proceeds of $187.8 million, net of an original issue discount (“OID”) of $4.0 million and issue costs of $8.2 million, that were used to fund a significant acquisition and 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 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. 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 OID allocable to the aforementioned prepayments as a loss on the extinguishment of debt.

The outstanding borrowings under the Second Lien Facility bear 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 will increase to 8.25% and 9.25%, respectively, during any quarter in which the quarterly amortization payment is not made. As of March 31, 2021, the actual interest rate of outstanding borrowings under the Second Lien Facility was 9.25%. 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 or three months (including in three month intervals if we select a six-month interest period), at our election and is computed on the basis of a 360-day year.

We have the right, to the extent permitted under the Credit Facility and an intercreditor agreement between the lenders under the Credit Facility and the lenders under the Second Lien Facility, to prepay loans under the Second Lien Facility at any time, subject to the following prepayment premiums (in addition to customary “breakage” costs with respect to Eurodollar loans): from January 15, 2021 through January 14, 2022, 102% of the amount being prepaid; from January 15, 2022 through January 14, 2023, 101% of the amount being prepaid; and thereafter, no premium. The Second Lien Facility also provides for the following prepayment premiums in the event of a change in control that results in an offer of prepayment that is accepted by the lenders under the Second Lien Facility: from January 15, 2021 through January 14, 2022, 102% of the amount being prepaid; from January 15, 2023 through January 14, 2023, 101% of the amount being prepaid; and thereafter, no premium.

The Second Lien Facility is collateralized by substantially all of the Partnership’s and its subsidiaries’ assets with lien priority subordinated to the liens securing the Credit Facility. The obligations under the Second Lien Facility are guaranteed by the Partnership and the Guarantor Subsidiaries.

The Second Lien Facility has no financial covenants, but contains 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 customarydebt covenants.

~~As of March 31, 2021, we were in compliance with all of the covenants under the Second Lien Facility.~~

8.Note 8 – Income Taxes

The income tax provision resulted in a benefit of $0.2 million for the three months ended March 31, ~~2021~~2022. The federal portion was fully offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of 0.9%, which is fully attributable to the State of Texas. Our net deferred income tax liability balance of $2.1 million as of March 31, 2022 is also fully attributable to the State of Texas and primarily related to property.

The income tax provision resulted in a benefit of $0.3 ~~million.~~million for the three months ended March 31, 2021. The federal portion was fully offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of 1.5%, which is fully attributable to the State of Texas. 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 $0.4 million as of March 31, 2021 is also fully attributable to the State of Texas and primarily related to property.

~~We recognized a federal and state income tax expense for the three months ended March 31, 2020 of $1.1 million. The feder~~al 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 0.7% 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 0no liability for unrecognized tax benefits as of March 31, 2022 and December 31, 2021. There were 0no interest and penalty charges recognized during the ~~periods~~three months ended March 31, ~~2021~~2022 and ~~2020.~~2021. Tax years from ~~2015~~2017 forward remain open to examination by the major taxing jurisdictions to which the Company is subject; however, net operating losses originating in prior years are subject to examination when utilized.

~~9. Leases~~

We generally have lease arrangements for office facilities and certain office equipment, certain field equipment including compressors, drilling rigs, crude oil storage tank capacity, land easements and similar arrangements for rights-of-way and certain gas gathering and gas lift assets. Our short-term leases included in the disclosures below are primarily comprised of our contractual arrangements with certain vendors for operated drilling rigs, crude oil storage tank capacity and our field compressors. Our primary variable lease was represented by our field gas gathering and gas lift agreement with a midstream service provider and the lease payments are charged on a volumetric basis at a contractual fixed rate.

~~The following table summarizes the components of our total lease cost for the periods presented:~~

Three Months Ended March 31,
2021 2020
Operating lease cost $ 216 $ 210
Short-term lease cost 2,752 11,296
Variable lease cost 4,874 5,657
Less: Amounts charged as drilling costs 1
(2,082) (10,621)
Total lease cost recognized in the Condensed Consolidated Statement of Operations 2
$ 5,760 $ 6,542

~~___________________~~

1 Represents the combined gross amounts incurred and (i) capitalized as drilling costs for our working interest share and (ii) billed to joint interest partners for their working interest share for short-term leases of operated drilling rigs.

2 Includes $2.2 million and $2.8 million recognized in Gathering, processing and transportation expense (“GPT”), $3.3 million and $3.5 million recognized in Lease operating expense (“LOE”) for the three months ended March 31, 2021 and 2020, respectively, and $0.2 million recognized in G&A for each of the three months ended March 31, 2021 and 2020.

1614

~~10.~~Note 9 – Supplemental Balance Sheet Detail

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


		March 31,		December 31,
		2021		2020			March 31, 2022		December 31, 2021
Prepaid and other current assets:	Prepaid and other current assets:					Prepaid and other current assets:
Inventories 1	Inventories 1	$	4,036	$	4,274	Inventories 1	$	13,025	$	10,305
Prepaid expenses 2	Prepaid expenses 2	15,511		14,771		Prepaid expenses 2	2,964		10,693
		$	19,547	$	19,045		$	15,989	$	20,998
Other assets:	Other assets:					Other assets:
Deferred issuance costs of the Credit Facility, net of amortization	Deferred issuance costs of the Credit Facility, net of amortization	$	2,542	$	2,349	Deferred issuance costs of the Credit Facility, net of amortization	$	3,138	$	3,308
Right-of-use assets – operating leases	Right-of-use assets – operating leases	2,237		2,432		Right-of-use assets – operating leases	1,498		1,671

Other	Other	127		127		Other	—		38
		$	4,906	$	4,908		$	4,636	$	5,017
Accounts payable and accrued liabilities:	Accounts payable and accrued liabilities:					Accounts payable and accrued liabilities:
Trade accounts payable	Trade accounts payable	$	29,137	$	7,055	Trade accounts payable	$	32,463	$	32,452
Drilling and other lease operating costs	Drilling and other lease operating costs	18,002		16,088		Drilling and other lease operating costs	47,103		35,045
Royalties		34,223		26,615
Revenue and royalties payable						Revenue and royalties payable	110,493		95,521
Production, ad valorem and other taxes	Production, ad valorem and other taxes	5,242		3,094		Production, ad valorem and other taxes	12,224		7,905
Derivative settlements to counterparties	Derivative settlements to counterparties	8,773		321		Derivative settlements to counterparties	25,146		6,117
Compensation		2,270		4,222
Compensation and benefits						Compensation and benefits	7,957		13,942
Interest	Interest	401		504		Interest	5,003		15,321
Environmental remediation liability 3						Environmental remediation liability 3	2,277		2,287
Current operating lease obligations	Current operating lease obligations	894		936		Current operating lease obligations	891		914
Other 3		1,008		4,254
Other						Other	2,632		4,877
		$	99,950	$	63,089		$	246,189	$	214,381
Other liabilities:
Other non-current liabilities:						Other non-current liabilities:
Asset retirement obligations	Asset retirement obligations	$	5,648	$	5,461	Asset retirement obligations	$	8,186	$	8,413
Noncurrent operating lease obligations		1,553		1,752
Defined benefit pension obligations		845		865
Postretirement health care benefit obligations		291		284
Non-current operating lease obligations						Non-current operating lease obligations	755		975
Postretirement benefit plan obligations						Postretirement benefit plan obligations	959		970
							$	9,900	$	10,358
		$	8,337	$	8,362

_______________________

1 Includes tubular inventory and well materials of ~~$3.3~~$12.2 million and ~~$3.9~~$9.5 million and crude oil volumes in storage of ~~$0.7~~$0.8 million and ~~$0.4~~$0.8 million as of March 31, ~~2021~~2022 and December 31, ~~2020,~~2021, respectively.

2 The balances as of March 31, ~~2021~~2022 and December 31, ~~2020~~2021 include ~~$13.9~~$0.6 million and ~~$13.6~~$9.6 million, respectively, for the prepayment of drilling and completion materials and ~~services, respectively.~~services.

3 The balance as of March 31, 2022 and December 31, ~~2020 includes $3.5 million~~2021 represents estimated costs associated with remediation activities for certain wells and tanks acquired as part of ~~accrued costs attributable to Juniper Transaction expenses.~~the Lonestar Acquisition.

~~11.~~Note 10 – Fair Value Measurements

We apply the authoritative accounting provisions included in GAAP for measuring the fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date.

Our financial instruments, ~~that are subject to fair value disclosure consist of~~including cash and cash equivalents, accounts receivable, and accounts payable ~~derivatives and our Credit Facility and Second Lien Facility borrowings.~~approximate fair value due to their short-term maturities. As of March 31, ~~2021~~2022 and December 31, ~~2020,~~2021, the carrying values of ~~all~~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 ~~these financial instruments approximated~~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.~~

value hierarchy. As of March 31, 2022, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $536.7 million and $559.4 million, respectively. As of December 31, 2021, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $619.0 million and $634.6 million.

Recurring Fair Value Measurements

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

As of March 31, 2021
Fair Value Fair Value Measurement Classification
Description Measurement Level 1 Level 2 Level 3
Assets:
Commodity derivative assets – current $ 13,093 $ 0 $ 13,093 $ 0
Commodity derivative assets – noncurrent $ 5,269 $ 0 $ 5,269 $ 0
Liabilities:
Interest rate swap liabilities – current $ (3,730) $ — $ (3,730) $ —
Interest rate swap liabilities – noncurrent $ (615) $ — $ (615) $ —
Commodity derivative liabilities – current $ (40,598) $ 0 $ (40,598) $ 0
Commodity derivative liabilities – noncurrent $ (14,299) $ 0 $ (14,299) $ 0


	As of March 31, 2022
	Level 1		Level 2		Level 3		Total
Financial assets:


Commodity derivative assets – current	$	—	$	9,631	$	—	$	9,631
Commodity derivative assets – non-current	—		2,912		—		2,912
Total financial assets	$	—	$	12,543	$	—	$	12,543
Financial liabilities:
Interest rate swap liabilities – current	$	—	$	(458)	$	—	$	(458)

Commodity derivative liabilities – current	—		(148,550)		—		(148,550)
Commodity derivative liabilities – non-current	—		(42,620)		—		(42,620)
Total financial liabilities	$	—	$	(191,628)	$	—	$	(191,628)

As of December 31, 2020
Fair Value Fair Value Measurement Classification
Description Measurement Level 1 Level 2 Level 3
Assets:
Commodity derivative assets – current $ 75,506 $ 0 $ 75,506 $ 0
Commodity derivative assets – noncurrent $ 25,449 $ 0 $ 25,449 $ 0
Liabilities:
Interest rate swap liabilities – current $ (3,655) $ — $ (3,655) $ —
Interest rate swap liabilities – noncurrent $ (1,645) $ — $ (1,645) $ —
Commodity derivative liabilities – current $ (81,451) $ 0 $ (81,451) $ 0
Commodity derivative liabilities – noncurrent $ (26,789) $ 0 $ (26,789) $ 0

Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one level of the fair value hierarchy to another level. In such instances, the transfer is deemed to have occurred at the beginning of the quarterly period in which the event or change in circumstances that caused the transfer occurred. There were no transfers during the three months ended March 31, 2021 and 2020.


	As of December 31, 2021
	Level 1		Level 2		Level 3		Total
Financial assets:


Commodity derivative assets – current	$	—	$	11,478	$	—	$	11,478
Commodity derivative assets – non-current	—		2,092		—		2,092
Total financial assets	$	—	$	13,570	$	—	$	13,570
Financial liabilities:
Interest rate swap liabilities – current	$	—	$	(1,480)	$	—	$	(1,480)

Commodity derivative liabilities – current	—		(48,892)		—		(48,892)
Commodity derivative liabilities – non-current	—		(23,815)		—		(23,815)
Total financial liabilities	$	—	$	(74,187)	$	—	$	(74,187)

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

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

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

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

Non-Recurring Fair Value Measurements

~~In addition to the fair value measurements applied with respect to assets contributed in the Juniper Transactions, the~~The most significant non-recurring fair value measurements utilized in the preparation of our ~~Condensed Consolidated Financial Statements~~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.

~~12.~~Note 11 – Commitments and Contingencies

Drilling and Completion Commitments

As of March 31, ~~2021,~~2022, we ~~had~~have a one year contract for 1 drilling rig and a contractual ~~commitments~~commitment on a pad-to-pad basis for ~~two~~1 other drilling rigs. Additionally, we have an agreement, effective January 2, 2021, which can be terminated with 30 days’ notice by either party, to utilize certain frac services and related materials, with no minimum commitment, through December 31, 2021. In March 2021, we made a prepayment of $12 million under the frac services agreement in advance of completion projects for the second quarter of 2021.rig.

Gathering and Intermediate Transportation Commitments

We have long-term agreements that provide us with ~~Nuevo G&T and Nuevo Dos Marketing, LLC (“Nuevo Marketing” and together with Nuevo G&T, collectively “Nuevo”) to provide~~field gathering and intermediate pipeline transportation services for a ~~substantial portion~~majority of our crude oil and condensate production in ~~as well as~~Lavaca and Gonzales Counties, Texas. We also have volume capacity support for certain downstream interstate pipeline transportation. The following table provides details on these contractual arrangements as of March 31, 2022:

Nuevo is obligated to gather and transport our crude oil and condensate from within a dedicated area in the Eagle Ford via a gathering system and intermediate takeaway pipeline connecting to a downstream interstate pipeline operated by a third party through 2041. We have a minimum volume commitment (“MVC”)

Description of contractual arrangement

Expiration
of Contractual Arrangement

Minimum Volume
Commitment (MVC)
(bbl/d)

Expiration of Minimum Volume Commitment (MVC)

Field gathering agreement

February 2041

8,000

February 2031

Intermediate pipeline transportation services

February 2026

8,000

February 2026

Volume capacity support

April 2026

8,000

April 2026

Each of ~~8,000 gross barrels of oil per day to Nuevo through 2031 under the gathering agreement. We are obligated~~these arrangements also contain an obligation to deliver the first 20,000 gross barrels of oil per day produced from Gonzales, Lavaca ~~Fayette~~ and ~~DeWitt~~Fayette Counties, Texas.

~~Under a marketing agreement, we have a commitment to sell 8,000 barrels per day~~ For certain of our crude oil ~~(gross)~~volumes gathered under the field gathering agreement, our rate includes an adjustment based on NYMEX WTI prices. As crude oil prices increase, up to ~~Nuevo, or~~a cap of $90 per bbl, the gathering rate escalates pursuant to ~~any third party, utilizing Nuevo Marketing’s capacity on a downstream interstate pipeline through 2026.~~the field gathering agreement.

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

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

Excluding the application of existing credits that we have earned during the preceding 12-month period ended March 31, ~~2021~~2022 for deliveries of volumes in excess of the volume commitment, and the potential impact of the effects of price escalation from commodity price changes, if any, the minimum fee requirements attributable to the MVC under the gathering, transportation and marketing agreements are as follows: $10.5 million for the remainder of ~~2021,~~2022, approximately $13.9 million per year for ~~2022~~2023 through 2025, $7.8 million for 2026, $3.8 million per year for 2027 through 2030 and $0.6 million for 2031.

Crude Oil Storage

As ~~a component~~ of ~~the crude oil gathering agreement referenced above,~~March 31, 2022, we ~~have~~had access to up to approximately 180,000 barrels of dedicated tank capacity for no additional charge at the service provider’s central delivery point facility (“CDP”), in Lavaca County, Texas through February 2041. ~~We have also contracted~~In addition, we had access for ~~access~~up to upa maximum of 340,000 barrels of tank capacity and evergreen month-to-month at several locations in the South Texas region comprised of (i) access to an additional 70,000 barrels of tank capacity at the CDP on a month-to-month basis, which can be terminated by either party with ~~45-days’~~45 days’ notice to the ~~counterparty. We have also contracted for~~counterparty, (ii) crude oil storage capacity for up to 90,000 barrels with a downstream interstate pipeline at a facility in DeWitt County, Texas, on a month-to-month basis, which ~~can be terminated by either party with 45-days’ notice to the counterparty. Finally, we have~~expired in April 2022, and (iii) an agreement with a marketing affiliate of the aforementioned downstream interstate pipeline to utilize up to 62,000 barrels of capacity within their system on a firm basis and an additional 120,000 barrels, if available, on a flexible basis ~~through July 2021.~~that both expired in April 2022. Costs associated with these agreements are in the form of monthly fixed rate short-term leases and are charged as incurred on a monthly basis to ~~GPT.~~GPT in our condensed consolidated statements of operations.

Other Agreements

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

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

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

Legal, Environmental Compliance and Other ~~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. As of March 31, ~~2021, we had AROs of approximately $5.6 million attributable to the plugging of abandoned wells. As of March~~2022 and December 31, 2021, we had an estimated reserve of approximately $0.1 million for certain claims made against us regarding previously divested operations included in ~~“Accounts~~Accounts payable and accrued ~~liabilities.”~~liabilities on our condensed consolidated balance sheets.

As of March 31, 2022 and December 31, 2021, we had AROs of approximately $8.2 million and $8.4 million attributable to the plugging of abandoned wells, respectively. Additionally, we had $2.3 million of environmental remediation liabilities assumed in the Lonestar Acquisition as of March 31, 2022 and December 31, 2021.

Additionally, we have entered into certain contractual arrangements for other products and services and have commitments under information technology licensing and service agreements, among others.

~~13. Equity~~

~~The following tables summarize the components of equity and the changes therein as of and for the quarterly periods in 2021 and 2020.~~

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 $ 0 $ 152 $ 203,463 $ 9,354 $ (131) $ 0 $ 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 0 1 1 1,772
Balance as of March 31, 2021 $ 2 $ 153 $ 155,164 $ (4,218) $ (130) $ 223,172 $ 374,143

~~_______________________~~

1 Includes equity-classified share-based compensation of $2.2 million during the three months ended March 31, 2021. During the three months ended March 31, 2021, 102,586 and 6,800 shares of common stock were issued in connection with the vesting of certain 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 0 (1) 556
Balance as of March 31, 2020 $ 152 $ 201,222 $ 483,005 $ (60) $ 684,319

~~_______________________~~

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 $0.9 million during the three months ended March 31, 2020. During the three months ended March 31, 2020, 22,321 shares of common stock were issued in connection with the vesting of certain RSUs, net of shares withheld for income taxes.

~~14.~~Note 12 – Share-Based Compensation and Other Benefit Plans

Share-Based Compensation

We ~~recognize share-based compensation expense related to our share-based compensation plans as a component of G&A expenses in our Condensed Consolidated Statements of Operations.~~

We reserved ~~a total of~~ 4,424,600 shares of ~~common stock~~Class A Common Stock for issuance under the ~~Penn Virginia Corporation~~Ranger Oil Management Incentive Plan (the “Plan”) for share-based compensation awards. A total of ~~608,938~~762,259 RSUs and ~~201,491~~484,197 PRSUs have been granted to employees and directors ~~under the Plan~~ through March 31, ~~2021. Additionally, in~~2022.

We recognized expense attributable to the ~~third quarter of 2020 and first quarter of 2021, 57,500 and 24,200~~ RSUs and ~~57,500 and 24,200~~ PRSUs ~~respectively, were issued outside~~of $0.9 million for the ~~Plan to Mr. Henke and to Ms. Gwaltney as an inducement awards upon their appointments as President and CEO and Senior Vice President, Development, respectively. As of~~three months ended March 31, ~~2021, a total of 209,486 RSUs~~2022 and ~~150,512 PRSUs are unvested and outstanding.~~

~~We recognized~~ $2.2 million, including approximately $1.9 million as a result of a change-in-control event associated with the Juniper ~~transactions, and $0.9 million of expense attributable to the RSUs and PRSUs~~Transactions for the three months ended March 31, ~~2021 and 2020, respectively~~2021. We recognize share-based compensation expense as a component of G&A expenses in our condensed consolidated statements of operations.

~~A total of 48,641 RSUs were granted during~~

Time-Vested Restricted Stock Units

The table below summarizes activity for the three months ended March 31, ~~2021~~2022 with ~~an average grant-date fair value~~respect to awarded RSUs:


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

Compensation expense for RSUs is recognized on a straight-line basis over the applicable vesting period, which is generally over a three-year period. As of ~~$13.69. A total~~March 31, 2022, we had $1.2 million of ~~223,882 RSUs were granted during~~unrecognized compensation cost attributable to RSUs. We expect that cost to be recognized over a weighted-average period of 1.71 years.

Performance-Based Restricted Stock Units

During the three months ended March 31, ~~2020~~2022, we did not have any activity with ~~an average grant-date fair value~~respect to the PRSUs. As of ~~$2.78. The RSUs are~~March 31, 2022, a total of 345,069 PRSUs were unvested and outstanding.

Compensation expense for PRSUs with a market condition is being charged to expense on a straight-line basis for the 2021 grants and graded-vesting for the 2020 and 2019 grants, over a range of less than one to three years. InCompensation expense for PRSUs with a performance condition is recognized on a straight-line basis over three years when it is considered probable that the ~~three months ended March 31,~~performance condition will be achieved and such grants are expected to vest. PRSUs with a market condition do not allow for the reversal of previously recognized expense, even if the market condition is not achieved and no shares ultimately vest.

The 2021 PRSU grants are based 50% on the Company’s return on average capital employed (“ROCE”) relative to a defined peer group and ~~2020, 102,586~~50% based on the Company’s absolute total shareholder return and ~~22,321 shares were issued upon vesting/settlement~~total shareholder return (“TSR”) relative to a defined peer group over the three-year performance period. The 2021 PRSUs cliff vest from 0% to 200% of ~~RSUs, net~~the original grant at the end of ~~shares withheld for income taxes, respectively.~~a three-year performance period based on satisfaction of the respective underlying conditions.

~~During the three months ended March 31, 2021, 24,200 PRSUs were granted. A total~~Vesting of ~~87,899 PRSUs were granted during the three months ended March 31, 2020. For the~~ PRSUs granted in ~~2019~~2020 and March 2020, the performance period is 2020 through 2022. The performance period for Mr. Henke’s September 2020 PRSU inducement grant and Ms. Gwaltney’s January 2021 grant is 2021 through 2023. Vesting of the PRSUs can2019 range from 00% to ~~200 percent~~200% of the original grant based on ~~the performance of our common stock~~TSR relative to a defined peer ~~group. Due to their market condition,~~group over the ~~PRSUs are being charged to expense using graded vesting over~~three year performance period. As TSR is deemed a ~~maximum of three years. The~~“market condition”, the grant-date fair value for the 2019, 2020 and a portion of ~~each PRSU award was estimated on their applicable grant date~~the 2021 grants is derived by using a Monte Carlo simulation with $34.02 per PRSU for the 2019 grants, a range of $2.40 to $16.02 per PRSU for the 2020 grants and $21.82 per PRSU for the 2021 grant. In the three months ended March 31, 2021, 6,800 shares were issued upon settlement of PRSUs, net of shares withheld for income taxes.

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


									2021 1		2020 1		2019
		2021		2020		2019
Expected volatility	Expected volatility	126.2	%	101.32% to 117.71%		49.9	%	Expected volatility	131.74% to 134.74%		101.32% to 117.71%		49.9	%
Dividend yield	Dividend yield	0.0	%	0.0	%	0.0	%	Dividend yield	0.0	%	0.0	%	0.0	%
Risk-free interest rate	Risk-free interest rate	0.22	%	0.18% to 0.51%		1.66	%	Risk-free interest rate	0.22% to 0.29%		0.18% to 0.51%		1.66	%
Performance period								Performance period	2021-2023		2020-2022		2020-2022

_______________________

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

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

Other Benefit Plans

We maintain the Penn Virginia Corporation and Affiliated Companies Employees 401(k) Plan (the “401(k) Plan”), a defined contribution plan, which covers substantially all of our employees. We recognized $0.2 million ~~and $0.2 million~~ of expense attributable to the 401(k) Plan for both the three months ended March 31, ~~2021~~2022 and ~~2020, respectively.~~2021. The charges for the 401(k) Plan are recorded as a component of G&A expenses in our ~~Condensed Consolidated Statements~~condensed consolidated statements of ~~Operation.~~operations.

We maintain unqualified legacy defined benefit pension and defined benefit postretirement plans that cover a limited number of former employees, all of whom retired prior to January 1, 2000. The combined expense recognized with respect to these plans was less than $0.1 million for each of the three and three months ended March 31, ~~2021~~2022 and ~~2020.~~2021. The charges for these plans are recorded as a component of ~~“Other~~Other income (expense)” in our ~~Condensed Consolidated Statements~~condensed consolidated statements of ~~Operation.~~

operations.

~~15. Interest Expense~~

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

Three Months Ended March 31,
2021 2020
Interest on borrowings and related fees $ 5,632 $ 8,045
Accretion of original issue discount 1
105 196
Amortization of debt issuance costs 506 627
Capitalized interest (846) (688)
$ 5,397 $ 8,180

~~___________________~~

1 ~~Attributable to the Second Lien Facility (see~~ Note ~~7).~~

~~16.~~13 – Earnings ~~per~~Per Share

Basic net earnings (loss) per share is calculated by dividing the net income (loss) available to common shareholders, ~~(excluding~~excluding net income or loss attributable to Noncontrolling interest, ~~as applicable to the three months ended March 31, 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 ~~PBRSUs~~PRSUs have vested and outstanding Common Units ~~and~~(and shares of ~~Series A Preferred~~Class B Common Stock, ~~held by Juniper as a Noncontrolling interest are exchanged for common shares,~~par value $0.01 per share (“Class B Common Stock”) as applicable to the three months ended March 31, ~~2021 (see Note 3).~~2022 and Series A Preferred Stock, par value $0.01 per share (“Series A Preferred Stock”) as applicable to the three months ended March 31, 2021) held by the Noncontrolling interest in the Partnership are exchanged for common shares. Accordingly, our reported net income (loss) attributable to common shareholders is adjusted to reflect the reallocation of the net income (loss) attributable to the Noncontrolling interest assuming exchange of the Common Units (and shares of Class B Common Stock as applicable to the three months ended March 31, 2022 and Series A Preferred Stock as applicable to the three months ended March 31, 2021) held by the Noncontrolling interest.

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

Three Months Ended March 31,
2021 2020
Net income (loss) $ (20,021) $ 163,094
Net income (loss) attributable to Noncontrolling interest 6,449 0
Net income (loss) attributable to common shareholders - basic (13,572) 163,094
Reallocation of Noncontrolling interest assuming exchange of Common Units and
Series A Preferred Stock held by Noncontrolling interest (6,449) 0
Net income (loss) attributable to common shareholders - diluted $ (20,021) $ 163,094
Weighted-average shares – basic 15,263 15,152
Effect of dilutive securities:
Common Units and Series A Preferred Stock that are exchangeable for common shares 0 0
RSUs and PRSUs 0 8
Weighted-average shares – diluted 1
15,263 15,160


	Three Months Ended March 31,
		2022		2021
Net loss		$	(20,661)	$	(20,021)
Net loss attributable to Noncontrolling interest		10,676		6,449
Net loss attributable to common shareholders (basic)		(9,985)		(13,572)
Reallocation of Noncontrolling interest net loss		(10,676)		(6,449)
Net loss attributable to common shareholders (diluted)		$	(20,661)	$	(20,021)

Weighted-average shares – basic		21,107		15,263
Effect of dilutive securities:
Common Units and Series A Preferred Stock or Class B Common Stock, as applicable, that are exchangeable for common shares 1		—		—
RSUs and PRSUs		—		—
Weighted-average shares – diluted 2		21,107		15,263

~~___________________~~_______________________

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

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

2220

Note 14 – Subsequent Events

Share Repurchase Program

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

Acquisitions

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

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 ~~recently completed transactions with Juniper and its affiliates,~~fourth quarter 2021 acquisition of Lonestar Resources US Inc, including the risk that the benefits of the ~~transactions~~acquisition may not be fully realized or may take longer to realize than expected, and that management attention will be diverted to ~~transaction-related~~integration-related issues;

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

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

•the decline in, sustained market uncertainty of, and volatility of commodity prices for crude oil, natural gas liquids, or NGLs, and natural ~~gas, including the recent dramatic decline of such prices;~~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,~~order and interruptions to our operations or our customer’s ~~operations;~~operations, including as a result of any resurgence or new variant;

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

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

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

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

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

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

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

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

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

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

•the timing of receipt of necessary regulatory permits;

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

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

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

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

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

•physical, electronic and cybersecurity breaches;

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

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

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

•sustainability initiatives; and

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

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

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

The following discussion and analysis of the financial condition and results of operations of ~~Penn Virginia~~Ranger Oil Corporation and its consolidated subsidiaries (“~~Penn Virginia,~~Ranger,” “Ranger Oil,” the “Company,” “we,” “us” or “our”) should be read in conjunction with our ~~Condensed Consolidated Financial Statements~~condensed consolidated financial statements and ~~Notes~~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~~amounts for the prior period ~~ended March 31, 2020~~ have been reclassified to conform to the ~~2021~~current period presentation. References to “quarters” represent the three months ended March 31, ~~2021~~2022 or ~~2020,~~2021, as applicable.

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

Overview and Executive Summary

We are an independent oil and gas company focused on the onshore ~~exploration,~~ 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 ~~Gonzales, Lavaca, Fayette~~South Texas.

Recent Developments

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

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

Industry Environment and Recent Operating and Financial Highlights

Commodity Price and Other Economic Conditions

As an oil and gas ~~exploration~~development and ~~development~~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”) has had an adverse effect on~~COVID-19 created uncertainty for global economic ~~activity with~~activity. Beginning in March 2020, the ~~impact of travel restrictions, business closures, limitations to person-to-person contact and the institution of quarantining and other restrictions on movement in many communities. 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. ~~While we~~Over the past year, however, increased mobility, deployment of vaccines and other factors have ~~seen a relative improvement~~resulted in ~~global market stability, a return to pre-COVID 19 levels~~increased oil demand and commodity prices.

A high level of ~~economic activity~~uncertainty remains ~~uncertain in its magnitude~~regarding the volatility of energy supply and ~~eventual timing.~~

~~In addition, global crude oil prices experienced a collapse starting in early March 2020~~demand as ~~a result of the dual impact of demand deterioration and market oversupply caused by disagreements between~~ the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, collectively “OPEC+”) ~~with respect~~continued to ~~production curtailments.~~execute its strategy throughout 2021 to gradually increase production. In its most recent March 2022 meeting, OPEC+ ~~ultimately agreed~~reconfirmed the agreement to ~~specific adjustments to production in the Spring of 2020 which, for the most part, held for the remainder of the year and were supplemented~~increase output targets each month by additional voluntary downward adjustments, led primarily by Saudi Arabia. Collectively these curtailments contributed to a relative stabilization of commodity prices and rebalancing of the global crude oil markets by the end of 2020. However, there remains a high level of uncertainty regarding the volatility of energy supply and demand as OPEC+ announced on April432,000 bbl/day beginning May 1, ~~2021 that it would be easing existing limits on production beginning in May.~~

~~The combined effect of COVID-19 and the continuing energy industry instability led to significant volatility in NYMEX West Texas Intermediate (“NYMEX WTI”)~~2022. Most recently, WTI crude oil prices ~~throughout 2020 and~~have surged, closing at over $120 per bbl during first quarter ~~2021.~~2022 as a result of the Russia-Ukraine conflict and related sanctions and concerns that it might result in significant oil supply shortages. In ~~the beginning of January 2020,~~response, governmental authorities have implemented, and are expected to continue to implement, measures to address rising crude oil prices, ~~were approximately $62 per barrel (“bbl”) but declined rapidly~~including releasing emergency oil reserves. Higher energy prices, along with the global supply chain issues and other factors, have increased inflationary pressures, which has led or may lead to ~~end first quarter 2020 at approximately $20 per bbl, a decrease~~increased costs of ~~approximately 68 percent during the quarter. Prices began to increase~~services and modestly stabilized following the implementation of the aforementioned OPEC+ production curtailments, as well as proactive economic relief efforts in many countries, including the United States and crude oil ended 2020 at approximately $48 per bbl. In first quarter 2021 the rebound and stabilization continued, with crude oil averaging approximately $58 per bblcertain materials necessary for ~~the quarter.~~

NYMEX Henry Hub (“NYMEX HH”) pricing was 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, particular in February 2021. During the three months ended March 31, 2021, NYMEX HH reached a high of $23.61 per MMBtu and a low of $2.38 per MMBtu compared to a high of $2.12 per MMBtu and a low of $1.63 per MMBtu during the three months ended March 31, 2020.our operations.

Our crude oil production is sold at a premium or deduct differential to the prevailing NYMEX ~~WTI Price.~~West Texas Intermediate (“NYMEX WTI”) price. The differential reflects adjustments for location, quality and transportation and gathering costs, as applicable. ~~Historically,~~All of our crude oil ~~volume~~volumes are sold ~~was largely priced using either Light Louisiana Sweet (“LLS”), or~~under Magellan East Houston (“MEH”) ~~grade differentials; however, in 2020 our contracts continued to shift more heavily to MEH~~ pricing, ~~and by year-end 2020 we were selling all of our crude oil volumes under MEH pricing contracts. While both LLS and MEH have~~which historically has been at a premium to NYMEX WTI, LLS has had a more favorable differential than MEH. During the three months ended March 31, 2021, the average differential for NYMEX WTI versus MEH was a premium of approximately $1.37 per bbl, comparedWTI.

Similar to ~~a premium of approximately $2.04 per bbl and $1.85 per bbl for NYMEX WTI versus MEH and LLS, respectively, for the same period in 2020. During the first quarter 2020 our realized~~ crude ~~oil price was a slight premium to NYMEX WTI of $0.12 but~~

~~sold at a discount of $2.38 for the three months ended March 31, 2021 primarily~~prices, Natural gas prices have jumped substantially as a result of ~~shifting fully to MEH pricing, as~~the Russia-Ukraine conflict, with NYMEX Henry Hub (“NYMEX HH”) closing well asover $5.00 per Mcf during first quarter 2022, which is the ~~narrowing of the MEH differential to NYMEX WTI.~~

highest level in more than a decade. Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity, and supply and demand relationships in that region or locality. Similar to crude oil, our natural gas production price has a premium or deduct differential to the prevailing NYMEX HH price primarily due to differential adjustments for the location and the energy content of the natural gas. Location differentials result from variances in natural gas transportation costs based on the proximity of the natural gas to its major consuming markets that correspond with the ultimate delivery point as well as individual interaction of supply and demand. ~~Our realized natural gas~~

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, ~~of $2.80~~we are subject to inflationary and ~~$1.83 per Mcf sold~~other factors that have resulted in higher costs for products, materials and services that we utilize in both our capital projects and with respect to our operating expenses. In 2021, we took certain actions with vendors and other service providers to secure products and services at ~~discounts~~fixed prices and to ~~NYMEX HH of $0.58~~pay for certain materials and ~~$0.05 per MMBtu for~~services in advance in order to lock in favorable costs but we have continued to experience higher costs and this may be exacerbated in the future.

Capital Expenditures, Development Progress and Production

During the three months ended March 31, ~~2021 and 2020, respectively.~~

~~A summary of these pricing differentials in tabular form is provided in the discussion of “Results of Operations~~ – ~~General and Administrative” that follows.~~

~~Capital Expenditures and Development Progress~~

~~We are operating~~2022, we operated two drilling rigs and ~~during the three months ended March 31, 2021,~~ incurred capital expenditures of approximately ~~$54.1~~$83.5 million, ~~with 99 percent~~of which $82.8 million was directed to drilling and completion ~~projects through which~~projects. During the first quarter 2022, a total of 1314 gross ~~(11.5~~(8.9 net) wells were ~~drilled,~~ completed and turned in line. During the second quarter of 2022, we entered into a contract to ~~sales.~~operate a spot drilling rig.

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

~~The following summarizes our key operating and financial highlights~~Total sales volume for the three months ended March 31, 2021, with comparison to the three months ended December 31, 2020 as presented in the table that follows. The year-over-year highlights for the quarterly periods ended March 31, 2021 and 2020 are addressed in further detail in the discussions for ~~Financial Condition~~ ~~and~~ ~~Results~~first quarter 2022 was 3,398 thousand barrels of ~~Operations~~ ~~that follow.~~

•~~Daily sales volume declined marginally to 20,534~~oil equivalent (“Mboe”), or 37,752 barrels of oil equivalent (“boe”) per day, from 21,502 boe per day due primarily to the effect of natural well declines, as well as the impacts of Winter Storm Uri that occurred in February 2021 that resulted in shut-ins of our wells for a portion of several days during the month. The declines were partially offset by new wells turned to sales during the three months ended March 31, 2021. Total sales volume decreased seven percent to 1,848with approximately 71%, or 2,428 thousand barrels of oil ~~equivalent~~ (“~~Mboe”~~Mbbl”) ~~from 1,978 Mboe due primarily to the impact~~, of ~~the aforementioned natural well declines.~~

•~~Product revenues increased 33 percent to $88.3 million~~sales volume from ~~$66.5 million due primarily to 41 percent higher~~ crude oil, ~~prices, or $23.7 million, partially offset by five percent lower~~15% from NGLs and 14% from natural gas.

Commodity Hedging Program

As of April 28, 2022, we have hedged a portion of our estimated future crude oil sales volume, or $2.7 million. NGL revenues were 34 percent higher due to 58 percent higher prices, or $1.3 million partially offset by 15 percent lower sales volume, or $0.4 million. Natural gas revenues were essentially unchanged with offsetting amounts from higher pricing and lower sales volume.

•Production and lifting costs (consisting of Lease operating expenses (“LOE”) and Gathering, processing and transportation expenses (“GPT”)) decreased on an absolute basis to $13.5 million from $14.8 million and declined on a per unit basis to $7.31 per boe from $7.49 per boe. Contributing to this decline were lower chemicals, water disposal, repairs and maintenance and contract labor costs primarily associated with the lower crude oil sales volume, partially offset by higher gas lift and natural gas ~~gathering costs.~~production from April 1, 2022 through the first half of 2024. The following table summarizes our net hedge position for the periods presented:


	2Q2022		3Q2022		4Q2022		1Q2023		2Q2023		3Q2023		4Q2023		1Q2024		2Q2024
NYMEX WTI Crude Swaps
Average Volume Per Day (bbl)	3,000		3,000		3,000		2,500		2,400		2,807		2,657		462		462
Weighted Average Swap Price ($/bbl)	$	74.12	$	73.01	$	69.20	$	54.40	$	54.26	$	54.92	$	54.93	$	58.75	$58.75
NYMEX WTI Crude Collars
Average Volume Per Day (bbl)	17,720		14,266		9,375		6,250		6,181		1,630		1,630
Weighted Average Purchased Put Price ($/bbl)	$	59.12	$	57.14	$	52.17	$	50.67	$	50.67	$	60.00	$	60.00
Weighted Average Sold Call Price ($/bbl)	$	77.01	$	81.13	$	67.57	$	65.65	$	65.65	$	76.12	$	76.12



NYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (bbl)	20,879		7,337		1,630
Weighted Average Swap Price ($/bbl)	$	1.120	$	1.172	$	1.020
NYMEX HH Swaps
Average Volume Per Day (MMBtu)	12,500		12,500		12,500		10,000		7,500
Weighted Average Swap Price ($/MMBtu)	$	3.727	$	3.745	$	3.793	$	3.620	$	3.690
NYMEX HH Collars
Average Volume Per Day (MMBtu)	13,187		15,679		14,511		6,417		11,538		11,413		11,413		11,538		11,538
Weighted Average Purchased Put Price ($/MMBtu)	$	2.500	$	3.088	$	2.854	$	6.000	$	2.500	$	2.500	$	2.500	$	2.500	$	2.328
Weighted Average Sold Call Price($/MMBtu)	$	3.220	$	4.141	$	3.791	$	10.000	$	2.682	$	2.682	$	2.682	$	3.650	$	3.000



OPIS Mt Belv Ethane Swaps
Average Volume per Day (gal)	28,022		27,717		27,717				98,901		34,239		34,239		34,615
Weighted Average Fixed Price ($/gal)	$	0.2500	$	0.2500	$	0.2500			$	0.2288	$	0.2275	$	0.2275	$	0.2275

•Production and ad valorem taxes increased on an absolute and per unit basis to $5.5 million and $2.98 per boe from $3.5 million and $1.75 per boe, respectively, due to the overall effects of 42 percent higher aggregate realized product pricing partially offset by lower than anticipated ad valorem tax assessments.

•General and administrative (“G&A”) expenses increased on an absolute and per unit basis to $13.2 million and $7.13 per boe from $10.0 million and $5.05 per boe, respectively, due primarily to: (i) $1.9 million of costs associated with share-based compensation awards whose vesting was accelerated by the Juniper Transactions, (ii) $0.2 million of higher transaction costs associated with the Juniper Transactions in the three month period in 2021, (iii) $0.2 million of executive restructuring charges including severance costs and termination benefits and (iv) $0.4 million of higher employee benefits costs in the three month period in 2021.

•Depreciation, depletion and amortization (“DD&A”) decreased to $23.9 million and $12.92 per boe during the first quarter of 2021 as compared to $25.8 million and $13.03 per boe during the fourth quarter of 2020 due primarily to the lower depletion rate attributable to the impairment recorded in the fourth quarter of 2020.

•We recorded an impairment of our oil and gas properties of $1.8 million during the first quarter of 2021 and $120.3 million in the fourth quarter of 2020 as the unamortized cost of our oil and gas properties, net of deferred income taxes, exceeded the sum of our estimated after-tax discounted future net revenues from proved properties adjusted for costs excluded from amortization (the “Ceiling Test”).

•Due to the combined impact of the matters noted in the bullets above, we recorded operating income of $30.7 million in the first quarter of 2021 compared to an operating loss of $107.4 million in fourth quarter of 2020.

Results of Operations

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


		Three Months Ended
		March 31,			December 31,			March 31,			Three Months Ended
		2021			2020			2020					March 31, 2022			December 31, 2021			March 31, 2021
Total sales volume (Mboe) 1	Total sales volume (Mboe) 1	1,848			1,978			2,433				Total sales volume (Mboe) 1	3,398			3,702			1,848
Average daily sales volume (boe/d) 1	Average daily sales volume (boe/d) 1	20,534			21,502			26,740				Average daily sales volume (boe/d) 1	37,752			40,236			20,534
Crude oil sales volume (Mbbl) 1	Crude oil sales volume (Mbbl) 1	1,469			1,538			1,881				Crude oil sales volume (Mbbl) 1	2,428			2,532			1,469
Crude oil sold as a percent of total 1	Crude oil sold as a percent of total 1	80		%	78		%	77		%		Crude oil sold as a percent of total 1	71		%	68		%	80		%
Product revenues	Product revenues	$	88,308		$	66,492		$	90,891			Product revenues	$	255,599		$	224,594		$	88,308
Crude oil revenues	Crude oil revenues	$	81,913		$	61,009		$	86,308			Crude oil revenues	$	226,732		$	191,079		$	81,913
Crude oil revenues as a percent of total	Crude oil revenues as a percent of total	93		%	92		%	95		%		Crude oil revenues as a percent of total	89		%	85		%	93		%
Realized prices:	Realized prices:											Realized prices:
Crude oil ($/bbl)	Crude oil ($/bbl)	$	55.76		$	39.66		$	45.90			Crude oil ($/bbl)	$	93.38		$	75.48		$	55.76
NGLs ($/bbl)	NGLs ($/bbl)	$	16.95		$	10.71		$	6.16			NGLs ($/bbl)	$	33.40		$	29.91		$	16.95
Natural gas ($/Mcf)	Natural gas ($/Mcf)	$	2.80		$	2.45		$	1.83			Natural gas ($/Mcf)	$	4.32		$	4.54		$	2.80
Aggregate ($/boe)	Aggregate ($/boe)	$	47.79		$	33.61		$	37.35			Aggregate ($/boe)	$	75.23		$	60.67		$	47.79
Realized prices, including effects of derivatives, net 2	Realized prices, including effects of derivatives, net 2											Realized prices, including effects of derivatives, net 2
Crude oil ($/bbl)	Crude oil ($/bbl)	$	44.80		$	48.84		$	54.15			Crude oil ($/bbl)	$	74.00		$	64.50		$	44.80

Natural gas ($/Mcf)	Natural gas ($/Mcf)	$	2.84		$	1.95		$	1.90			Natural gas ($/Mcf)	$	3.96		$	2.99		$	2.84
Aggregate ($/boe)	Aggregate ($/boe)	$	39.10		$	40.46		$	43.78			Aggregate ($/boe)	$	61.08		$	51.77		$	39.10
Production and lifting costs:	Production and lifting costs:											Production and lifting costs:
Lease operating ($/boe)	Lease operating ($/boe)	$	4.78		$	4.83		$	4.33			Lease operating ($/boe)	$	5.33		$	4.38		$	4.78
Gathering, processing and transportation ($/boe)	Gathering, processing and transportation ($/boe)	$	2.53		$	2.66		$	2.24			Gathering, processing and transportation ($/boe)	$	2.66		$	2.19		$	2.53
Production and ad valorem taxes ($/boe)	Production and ad valorem taxes ($/boe)	$	2.98		$	1.75		$	2.53			Production and ad valorem taxes ($/boe)	$	3.87		$	3.05		$	2.98
General and administrative ($/boe) 3	General and administrative ($/boe) 3	$	7.13		$	5.05		$	2.97			General and administrative ($/boe) 3	$	2.88		$	9.57		$	7.13
Depreciation, depletion and amortization ($/boe)	Depreciation, depletion and amortization ($/boe)	$	12.92		$	13.03		$	16.73			Depreciation, depletion and amortization ($/boe)	$	14.98		$	12.97		$	12.92
Capital expenditure program costs 4		$	54,122		$	32,627		$	79,220
Cash provided by operating activities 5		$	32,211		$	32,055		$	72,473
Cash paid for capital expenditures 6		$	34,758		$	29,555		$	62,015
Cash and cash equivalents at end of period		$	11,868		$	13,020		$	55,331
Debt outstanding at end of period, net 7		$	371,062		$	509,497		$	592,624
Credit available under credit facility at end of period 8		$	145,700		$	35,200		$	100,200
Net development wells drilled and completed		11.5			2.0			11.0

_______________________

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

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

3 Includes combined amounts of ~~$3.86, $1.93~~$0.79, $7.57 and ~~$0.35~~$3.86 per boe for the three months ended March 31, ~~2021~~2022, December 31, ~~2020~~2021 and March 31, ~~2020,~~2021, respectively, attributable to share-based compensation and significant special charges, ~~including~~comprised of organizational restructuring, acquisition and ~~acquisition, divestiture~~integration costs and strategic transaction costs, including costs attributable to the Lonestar Acquisition during the first quarter 2022 and fourth quarter 2021 periods and a change-in-control event during the first quarter of 2021 as described in the discussion of ““Results of Operations –- General and ~~Administrative~~Administrative”” that follows.

Sequential Quarterly Analysis

~~Includes amounts accrued~~The following summarizes our key operating and ~~excludes capitalized interest and capitalized labor.~~

5 ~~Includes net cash received (paid) for derivative settlements and premiums received (paid) of $(7.2) million, $12.8 million and $(0.3) million~~financial highlights for the three months ended March 31, ~~2021, December 31, 2020 and March 31, 2020, respectively. Reflects changes in operating assets and liabilities of $(14.4) million, $(12.9) million and $16.0 million for~~2022, with comparison to the three months ended December 31, 2021. The year-over-year highlights for the quarterly periods ended March 31, 2022 and 2021 ~~December 31, 2020~~are addressed in further detail in the discussions that follow below in Year over Year Analysis of Operating and ~~March 31, 2020, respectively.~~Financial Results.

6• ~~Represents actual cash paid~~Daily sales volume decreased to 37,752 boe per day from 40,236 boe per day with 8.9 net wells turned in line for ~~capital expenditures including capitalized interest and capitalized labor.~~the first quarter 2022 compared to 10.4 net wells turned in line for the fourth quarter 2021. Total sales volume decreased 8% to 3,398 Mboe from 3,702 Mboe.

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

•Production and lifting costs, consisting of ~~$4.7 million, $4.9~~Lease operating expenses (“LOE”) and Gathering, processing and transportation expenses (“GPT”), increased on an absolute basis and per unit basis to $27.1 million and ~~$6.8~~$7.99 per boe from $24.3 million asand $6.57 per boe due primarily to the impact of ~~March 31, 2021, December 31, 2020 and March 31, 2020, respectively.~~the Lonestar Acquisition, partially offset by the effects of 8% lower sales volume.

8• ~~The borrowing base under~~Production and ad valorem taxes increased on an absolute and per unit basis to $13.1 million and $3.87 per boe from $11.3 million and $3.05 per boe, respectively, due to the ~~credit agreement (“Credit Facility”) was $375 million~~overall effects of 24% higher aggregate realized product pricing, coupled with ~~availability further limited to a maximum of $350 million.~~

higher estimated ad valorem tax assessments in 2022.

•

~~Key Developments~~

~~The following general business developments had or may have a significant impact~~General and administrative (“G&A”) expenses decreased on ~~our results of operations, financial position~~an absolute and ~~cash flows:~~

~~Strategic Investment by Juniper~~

~~In January 2021, we consummated the previously announced Juniper Transactions whereby affiliates of Juniper contributed $150~~per unit basis to $9.8 million ~~in cash~~ and ~~certain oil~~$2.88 per boe from $35.4 million and ~~gas assets in Lavaca~~$9.57 per boe, respectively, primarily due to less acquisition 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 22,548,109 shares of common stock. Each holder of Common Units has the right to cause the Company to redeem on or after July 14, 2021, all or a portion of its Common Units (together with one one-hundredth (1/100th) of a share of Preferred Stock for each Common Unit to be redeemed), in exchange for, at the Partnership’s option, shares of Common Stock, on a one-for-one basis, or cash. Each 1/100th of a share of preferred Stock has no economic rights but entitles its holder to one vote on all matters to be voted on by shareholders generally. Further, because Penn Virginia is a holding company with no independent means of generating revenues and the assets of the consolidated Company all reside in operating subsidiaries, the holders of Common Units would be entitled to participate in any cash distribution or dividend on the same basis as the Common Stock whether or not the Common Units and Preferred Stock are redeemed or exchanged. Because the Common Units and Preferred Stock entitle Juniper to both vote and share in any distribution or dividend on the same basis as 22,548,109 shares of common stock, we view them as common stock equivalents. For additional information regarding the Juniper Transactions, see Note 3 to the Condensed Consolidated Financial Statements included in Part I, Item 1, “Financial Statements .”

~~Amendments to Credit Facility and Affirmation of Borrowing Base~~

In January 2021, we entered into Amendment No. 9 to the Credit Agreement (the “Ninth Amendment”) permitting the Juniper Transactions and affirming our borrowing base at $375 million with borrowings limited to a maximum of $350 million. In addition, the Ninth Amendment: (i) provides for certain minimum hedging conditions, (ii) a first lien leverage ratio covenant of 2.50 times, tested quarterly and (iii) permits amortization payments of up to $1.875 million per quarter to be made under the Second Lien Credit Agreement, dated as of September 29, 2017 (the “Second Lien Facility”) until January 2022 if no default exists both before and after giving effect to the payments and thereafter using available free cash flow upon the satisfaction of certain conditions (including maintaining a leverage ratio of 2.00 to 1.00 and availability of at least 25% under the Credit Facility after giving pro forma effect to the payment). Concurrent with the Ninth Amendment, we paid down $80.5 million of outstanding borrowings under the Credit Facility plus accrued interest of $0.1 million which was funded with the proceeds from the Juniper Transactions. We incurred and capitalized $0.4 million of issue and otherintegration costs associated with the ~~Ninth Amendment in January 2021.~~

~~Amendment to the Second Lien Facility~~

~~On November 2, 2020, we entered into the amendment dated November 2, 2020 (the “Second Lien Amendment”) which became effective upon the Closing~~Lonestar Acquisition of the Juniper Transactions. The Second Lien Amendment (1) extends the maturity date of the Second Lien Facility to September 29, 2024, (2) increases the margin applicable to advances under the Second Lien Facility, (3) impose 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 and (4) requires maximum and, in certain circumstances as described therein, minimum hedging arrangements.

Under the Second Lien Amendment, the Company is required to make quarterly amortization payments equal to $1,875,000 and outstanding borrowings under the Second Lien Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate based on the prime rate plus an applicable margin of 7.25% or (b) a Eurodollar rate, including LIBOR through 2021, with a floor of 1%, plus an applicable margin of 8.25%; provided that the applicable margin will increase to 8.25% and 9.25% respectively$1.7 million incurred during ~~any quarter in which the quarterly amortization payment is not made.~~

We paid down $50.0 million of outstanding loans under the Second Lien Facility plus accrued interest of $0.2 million attributable to lenders and $1.3 million including accrued interest to a non-consenting lender in January 2021 which was funded with the proceeds from the Juniper Transaction. We incurred and capitalized $1.4 million of issue and other costs and wrote-off $1.3 million of unamortized issuance costs in connection with the Second Lien Amendment in January 2021 as a loss on the extinguishment of debt.

~~Development Plans and Production~~

We drilled, completed and turned 13 gross (11.5 net) wells to sales during the quarter ended March 31, 2021. As of April 30, 2021, we turned an additional two gross (1.6 net) wells to sales and four gross (2.9 net) wells were completing and seven gross (6.3 net) wells were in progress.

~~Total sales volume for~~ the first quarter of2022 compared to $27.0 million during the fourth quarter 2021.

•Depreciation, depletion and amortization (“DD&A”) increased on an absolute and per unit basis to $50.9 million and $14.98 per boe during the first quarter 2022 as compared to $48.0 million and $12.97 per boe during the fourth quarter 2021 ~~was 1,848 Mboe, or 20,534 boe/d, with approximately 80 percent, or 1,469 Mbbls, of sales volume from crude oil, 11 percent from NGLs and 9 percent from natural gas, respectively.~~due primarily to higher development costs.

As of March 31, 2021, we had approximately 102,400 gross (90,400 net) acres in the Eagle Ford, net of expirations. Approximately 91 percent of our acreage is held by production and substantially all is operated by us.

~~Commodity Hedging Program~~

As of April 30, 2021, we have hedged a portion of our estimated future crude oil and natural gas production from April 1, 2021 through the first half of 2023. The following table summarizes our net hedge positions for the periods presented:

2Q2021 3Q2021 4Q2021 1Q2022 2Q2022 3Q2022 4Q2022 1Q2023 2Q2023
NYMEX WTI Crude Swaps
Average Volume Per Day (bbl) 3,297 815 815
Weighted Average Swap Price ($/bbl) $ 55.89 $ 45.54 $ 45.54
NYMEX WTI Collars
Average Volume Per Day (bbl) 12,637 12,500 9,783 5,417 4,533 4,484 4,484 2,917 2,855
Weighted Average Purchased Put Price ($/bbl) $ 44.65 $ 42.87 $ 42.00 $ 40.00 $ 40.00 $ 40.00 $ 40.00 $ 40.00 $ 40.00
Weighted Average Sold Call Price ($/bbl) $ 55.10 $ 55.13 $ 54.92 $ 53.49 $ 52.47 $ 52.47 $ 52.47 $ 50.00 $ 50.00
NYMEX WTI Sold Puts
Average Volume Per Day (bbl) 4,945 5,707 5,707
Weighted Average Sold Put Price ($/bbl) $ 29.83 $ 35.14 $ 35.14
NYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (bbl) 18,132 17,935 17,935
Weighted Average Swap Price ($/bbl) $ 0.17 $ 0.17 $ 0.17
NYMEX HH Collars
Average Volume Per Day (MMBtu) 9,890 9,783 9,783
Weighted Average Purchased Put Price($/MMBtu) $ 2.607 $ 2.607 $ 2.607
Weighted Average Sold Call Price ($/MMBtu) $ 3.117 $ 3.117 $ 3.117
NYMEX HH Sold Puts
Average Volume Per Day (MMBtu) 6,593 6,522 6,522
Weighted Average Sold Put Price ($/MMBtu) $ 2.000 $ 2.000 $ 2.000
OPIS Mt Belv Ethane Swaps
Average Volume per Day (gal) 36,264 35,870
Weighted Average Fixed Price ($/gal) $ 0.2263 $ 0.2288

~~Financial Condition~~

~~Liquidity~~

Our primary sources of liquidity include our cash on hand, cash provided by operating activities and borrowings under the Credit Facility. The Credit Facility provides us with up to $1.0 billion in borrowing commitments. The current borrowing base under the Credit Facility is $375 million with availability further limited to a maximum of $350 million. As of April 30, 2021, we had $100.7 million available under the Credit Facility.

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 the 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.

~~Capital Resources~~

Under our 2021 capital program, we anticipate capital expenditures of up to $186 million for the remaining three quarters of the year for an estimated annual total of up to $240 million with approximately 98 percent of capital being directed to drilling and completions. 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 for the remainder of 2021, 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 on Hand and Cash From Operating Activities.~~ ~~For additional information and an analysis of our historical cash from operating activities, see the “Cash Flows” discussion that follows.~~

~~Credit Facility Borrowings.~~ During the three months ended March 31, 2021, we repaid $85.5 million under the Credit Facility including $80.5 million funded from the capital contribution associated with the Juniper Transactions. We also borrowed $20 million in April 2021 to fund a portion of our capital expenditures. For additional information regarding the terms and covenants under the Credit Facility, see the “~~Capitalization” discussion that follows.~~

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

Borrowings Outstanding
End of Period Weighted-
Average Maximum Weighted-
Average Rate
Three months ended March 31, 2021 $ 228,900 $ 243,644 $ 314,400 3.18 %

~~Proceeds from Sales of Assets~~. We continually evaluate potential sales of assets, including certain non-strategic oil and gas properties and undeveloped acreage, among others. For additional information and an analysis of our historical proceeds from sales of assets, see the “~~Cash Flows” discussion that follows.~~

~~Capital Markets Transactions~~. 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.

~~Cash Flows~~

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

Three Months Ended
March 31, March 31,
2021 2020
Cash flows from operating activities
Operating cash flows, net of working capital changes $ 49,162 $ 80,183
Crude oil derivative settlements and premiums received (paid), net (6,289) (440)
Natural gas derivative settlements received, net 42 104
Interest rate swap settlements paid, net (922) 68
Interest payments, net of amounts capitalized (4,888) (7,442)
Organizational restructuring costs, including severance benefits, paid (239) —
Strategic transaction costs paid (4,655) —
Net cash provided by operating activities 32,211 72,473
Cash flows from investing activities
Capital expenditures (34,758) (62,015)
Proceeds from sales of assets, net 4 75
Net cash used in investing activities (34,754) (61,940)
Cash flows from financing activities
Proceeds from (repayment of) credit facility borrowings, net (85,500) 37,000
Repayment of second lien term loan (53,140) —
Proceeds from redeemable common units 151,160 —
Proceeds from redeemable preferred stock 2 —
Transaction costs of Noncontrolling interest paid (5,543) —
Issue costs of Noncontrolling interest paid (3,758) —
Debt issuance costs paid (1,830) —
Net cash provided by financing activities 1,391 37,000
Net increase (decrease) in cash and cash equivalents $ (1,152) $ 47,533

~~Cash Flows from Operating Activities.~~ The decrease of $40.2 million in net cash provided by operating activities for the three months ended March 31, 2021 compared to the corresponding period in 2020 was primarily attributable to the effect of 24 percent lower total sales volume and the timing effect of revenues receipts as the first quarter of 2021 included cash receipts from the fourth quarter of 2020 which were derived from lower average prices than revenue receipts in the first quarter of 2020 which were derived from higher average prices from the fourth quarter of 2019. The adverse impact on cash received from realized revenues in the three months ended March 31, 2021 was exacerbated by: (i) higher net payments for commodity derivatives settlements and premiums, (ii) transaction costs paid in connection with the Juniper Transactions and (iii) executive restructuring costs including severance payments. These items were partially offset by lower interest payments, net of interest rate swap settlements, due to substantially lower outstanding borrowings and lower weighted-average variable rates.

~~Cash Flows from Investing Activities~~. As illustrated in the tables below, our cash payments for capital expenditures were significantly lower during the three months ended March 31, 2021 as compared to the corresponding period in 2020, due primarily to the fact that we were operating three drilling rigs during the three month ended March 31, 2020 prior to the suspension of the program that resulted from the COVID-19 pandemic, compared to two drilling rigs throughout the three months ended March 31, 2021. In addition, we received lower proceeds from the sale of scrap tubular and well materials during the three months ended March 31, 2021 compared to the corresponding period in 2020.

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

Three Months Ended
March 31, March 31,
2021 2020
Drilling and completion $ 53,585 $ 76,161
Lease acquisitions and other land-related costs 787 1,930
Pipeline, gathering facilities and other equipment, net (251) 1,124
Geological and geophysical (seismic) costs 1 5
$ 54,122 $ 79,220

The following table reconciles the total costs of our capital expenditures program with the net cash paid for capital expenditures as reported in our Condensed Consolidated Statements of Cash Flows for the periods presented:

Three Months Ended
March 31, March 31,
2021 2020
Total capital expenditures program costs (from above) $ 54,122 $ 79,220
Decrease (increase) in accounts payable for capital items and accrued capitalized costs (20,246) (18,660)
Less:
Transfers from tubular inventory and well materials (2,194) (3,424)
Sales and use tax refunds received and applied to property accounts (425) —
Add:
Prepayments for drilling and completion services, net of transfers 339 —
Tubular inventory and well materials purchased in advance of drilling 1,649 3,395
Capitalized internal labor 667 796
Capitalized interest 846 688
Total cash paid for capital expenditures $ 34,758 $ 62,015

~~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 three months ended March 31, 2021 includes an additional repayment of $5 million under the Credit Facility and a $1.9 million quarterly amortization payment under the Second Lien Facility. The three months ended March 31, 2020 includes borrowings of $46.0 million and repayments of $9.0 million under the Credit Facility which were used to fund a portion of the capital program during that period.

~~Capitalization~~

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

March 31, December 31,
2021 2019
Credit facility $ 228,900 $ 314,400
Second lien term loan, net 142,162 195,097
Total debt, net 371,062 509,497
Equity 374,143 212,838
$ 745,205 $ 722,335
Debt as a % of total capitalization 50 % 71 %

~~Credit Facility~~. The Credit Facility provides 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 are limited to a maximum of $350 million. 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. However, we have the option to forego a redetermination until Fall 2021 assuming we continue to satisfy certain minimum hedging conditions. The Credit Facility is available to us for general corporate purposes including working capital. The Credit Facility is scheduled to mature in May 2024. We had $0.4 million in letters of credit outstanding as of March 31, 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 March 31, 2021, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 3.11%. Unused commitment fees are charged at a rate of 0.50%.

The Credit Facility is guaranteed by the Partnership and all of its subsidiaries excluding the borrower subsidiary (the “Guarantor Subsidiaries”). 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 our ability 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.

~~Second Lien Facility. In accordance with the recent amendment, the maturity date of the Second Lien Facility was extended to September 29, 2024.~~

The Company is required to make quarterly amortization payments of $1.875 million and outstanding borrowings under the Second Lien Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate based on the prime 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 will increase to 8.25% and 9.25%, respectively, during any quarter in which the quarterly amortization payment is not made. As of March 31, 2021, the actual interest rate of outstanding borrowings under the Second Lien Facility was 9.25%. 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 or three months (including in three month intervals if we select a six-month interest period), at our election and is computed on the basis of a 360-day year. We have the right, to the extent permitted under the Credit Facility and an intercreditor agreement between the lenders under the Credit Facility and the lenders under the Second Lien Facility, to prepay loans under the Second Lien Facility at any time, subject to the following prepayment premiums (in addition to customary “breakage” costs with respect to Eurodollar loans): from January 15, 2021 through January 14, 2022, 102% of the amount being prepaid; from January 15, 2022 through January 14, 2023, 101% of the amount being prepaid; and thereafter, no premium. The Second Lien Facility also provides for the following prepayment premiums in the event of a change in control that results in an offer of prepayment that is accepted by the lenders under the Second Lien Facility: from January 15, 2021 through January 14, 2023, 102% of the amount being prepaid; from January 15, 2023 through January 14, 2024, 101% of the amount being prepaid; and thereafter, no premium.

The Second Lien Facility is collateralized by substantially all of our subsidiaries’ assets with lien priority subordinated to the liens securing the Credit Facility. The obligations under the Second Lien Facility are guaranteed by the Partnership and the Guarantor Subsidiaries.

~~Covenant Compliance.~~ The Credit Facility requires us to maintain (1) a minimum current ratio (as defined in the Credit Facility, which considers the unused portion of the total commitment as a current asset) of 1.00 to 1.00, (2) a maximum leverage ratio (consolidated indebtedness to EBITDAX, each as defined in the Credit Facility), in each case measured as of the last day of each fiscal quarter of 3.50 to 1.00. and (3) a maximum first lien leverage ratio (consolidated secured indebtedness to adjusted earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses, both as defined in the Credit Facility), measured as of the last day of each fiscal quarter, of 2.50 to 1.00.

The Credit Facility and Second Lien Facility also contain 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. In addition, the Credit Facility contains certain anti-cash hoarding provisions, including the requirement to repay outstanding loans and cash collateralize outstanding letters of credit on a weekly basis in the amount of any cash on the balance sheet (subject to certain exceptions) in excess of $25 million.

The Credit Facility and Second Lien Facility contain events of default and remedies. If we do not comply with the financial and other covenants in the Credit Facility and Second Lien Facility, as applicable, the lenders thereto may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Credit Facility and Second Lien Facility.

~~As of March 31, 2021, we were in compliance with all of the covenants under the Credit Facility and the Second Lien Facility.~~

~~Results of Operations~~

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					Three Months Ended March 31,
				2021 vs. 2020				2021 vs. 2020
		Three Months Ended March 31,		Favorable	Three Months Ended March 31,			Favorable
		2021	2020	(Unfavorable)	2021	2020		(Unfavorable)
Total Sales Volume 1									Total Sales Volume 1	2022	2021	Change	% Change
Crude oil (Mbbl and bbl/d)	Crude oil (Mbbl and bbl/d)	1,469	1,881	(412)	16,324	20,665		(4,341)	Crude oil (Mbbl and bbl/d)	2,428	1,469	959	65	%
NGLs (Mbbl and bbl/d)	NGLs (Mbbl and bbl/d)	210	307	(97)	2,335	3,376		(1,041)	NGLs (Mbbl and bbl/d)	501	210	291	139	%
Natural gas (MMcf and MMcf/d)	Natural gas (MMcf and MMcf/d)	1,013	1,474	(461)	11	16		(5)	Natural gas (MMcf and MMcf/d)	2,810	1,013	1,797	177	%
Total (Mboe and boe/d)	Total (Mboe and boe/d)	1,848	2,433	(585)	20,534	26,740		(6,206)	Total (Mboe and boe/d)	3,398	1,848	1,550	84	%

							Three Months Ended March 31,

Average Daily Sales Volume 1									Average Daily Sales Volume 1	2022	2021	Change	% Change
Crude oil (Mbbl and bbl/d)									Crude oil (Mbbl and bbl/d)	26,980	16,324	10,656	65	%
NGLs (Mbbl and bbl/d)									NGLs (Mbbl and bbl/d)	5,568	2,335	3,233	138	%
Natural gas (MMcf and MMcf/d)									Natural gas (MMcf and MMcf/d)	31	11	20	182	%
Total (Mboe and boe/d)									Total (Mboe and boe/d)	37,752	20,534	17,218	84	%

_______________________

1 All volumetric statistics ~~presented~~ 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 ~~decreased 24 percent~~increased 84% during the three ~~month period in 2021~~months ended March 31, 2022 when compared to the corresponding period in ~~2020. While the number of wells turned to sales were comparable during each~~2021 as a result of the ~~three month periods, fewer wells were turned to sales~~Lonestar Acquisition that closed in ~~the~~ fourth quarter of ~~2020 than during the fourth quarter of 2019 resulting in comparatively lower production for the three month period in~~ 2021 ~~from the most recently completed wells. Crude oil sales volume decreased 22 percent during the three month period in 2021 when compared to the corresponding period in 2020.~~and increased drilling activity throughout 2021.

Approximately ~~80 percent~~71% of total sales volume during the three month ~~period~~periods in ~~2021~~2022 was attributable to crude oil when compared to approximately ~~77 percent~~80% during the corresponding ~~period~~periods in ~~2020.~~2021. The ~~increase~~decrease in the crude oil composition of total sales volume ~~was~~is due primarily to ~~a focus on development plans with emphasis~~higher gas content of the wells acquired in ~~our oilier northern and eastern portions of our acreage holdings.~~the Lonestar Acquisition.

Product Revenues and Prices

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


		Total Product Revenues						Product Revenues per Unit of Volume							Three Months Ended March 31,
						2021 vs. 2020						2021 vs. 2020
		Three Months Ended March 31,				Favorable		Three Months Ended March 31,				Favorable
		2021		2020		(Unfavorable)		2021		2020		(Unfavorable)
								($ per unit of volume)
Total Product Revenues														Total Product Revenues	2022		2021		Change		% Change
Crude oil	Crude oil	$	81,913	$	86,308	$	(4,395)	$	55.76	$	45.90	$	9.86	Crude oil	$	226,732	$	81,913	$	144,819	177	%
NGLs	NGLs	3,562		1,893		1,669		$	16.95	$	6.16	$	10.79	NGLs	16,740		3,562		13,178		370	%
Natural gas	Natural gas	2,833		2,690		143		$	2.80	$	1.83	$	0.97	Natural gas	12,127		2,833		9,294		328	%
Total	Total	$	88,308	$	90,891	$	(2,583)	$	47.79	$	37.35	$	10.44	Total	$	255,599	$	88,308	$	167,291	189	%

Product Revenues per Unit of														Product Revenues per Unit of	Three Months Ended March 31,
Volume ($ per unit of volume)														Volume ($ per unit of volume)	2022		2021		Change		% Change
Crude oil														Crude oil	$	93.38	$	55.76	$	37.62	67	%
NGLs														NGLs	$	33.40	$	16.95	$	16.45	97	%
Natural gas														Natural gas	$	4.32	$	2.80	$	1.52	54	%
Total														Total	$	75.23	$	47.79	$	27.44	57	%

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


		Three Months Ended March 31, 2021 vs. 2020			Three Months Ended March 31, 2022 vs. 2021
		Revenue Variance Due to			Revenue Variance Due to
			Volume			Price		Total			Volume		Price		Total
Crude oil	Crude oil		$	(18,880)		$	14,485	$	(4,395)	Crude oil	$	53,472	$	91,347	$	144,819
NGLs	NGLs		(598)			2,267		1,669		NGLs	4,934		8,244		13,178
Natural gas	Natural gas		(842)			985		143		Natural gas	5,029		4,265		9,294
			$	(20,320)		$	17,737	$	(2,583)		$	63,435	$	103,856	$	167,291

Our product revenues during the three month period in ~~2021 decreased~~2022 increased compared to the corresponding period in ~~2020 due primarily to 22 percent lower crude oil volume partially offset by 22 percent higher realized prices. NGL revenues increased in the three month period in~~ 2021 due to ~~175 percent~~significantly higher ~~realized~~ prices ~~partially offset by 32 percent lower volume. Natural gas revenues increased moderately due to 53 percent higher realized prices partially offset by 31 percent lower~~

~~volume. Total crude oil revenues were approximately 93 percent of our total product revenues during~~from continued economic recovery, as well as supply concerns resulting from the ~~three month period in 2021~~Russia-Ukraine conflict as compared to ~~95 percent during~~the prior year. These factors resulted in an increase to the NYMEX WTI benchmark price of 63% for the three ~~month~~months ended March 31, 2022, as compared to the corresponding period in ~~2020.~~2022. Also contributing to the higher product revenues was an increase in volumes across all commodities due to the Lonestar Acquisition, with an overall increase in Mboe of 84%.

Realized Differentials

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


					2021 vs. 2020
		Three Months Ended March 31,			Favorable		Three Months Ended March 31,
			2021		2020			(Unfavorable)			2022		2021		Change		% Change
Realized crude oil prices ($/bbl)	Realized crude oil prices ($/bbl)		$	55.76	$	45.90		$	9.86	Realized crude oil prices ($/bbl)	$	93.38	$	55.76	$	37.62	67	%
Weighted-average WTI prices			58.14		45.78			12.36
Average WTI prices										Average WTI prices	95.01		58.14		36.87		63	%
Realized differential to WTI	Realized differential to WTI		$	(2.38)	$	0.12		$	(2.50)	Realized differential to WTI	$	(1.63)	$	(2.38)	$	0.75	(32)	%

Realized natural gas prices ($/Mcf)	Realized natural gas prices ($/Mcf)		$	2.80	$	1.83		$	0.97	Realized natural gas prices ($/Mcf)	$	4.32	$	2.80	$	1.52	54	%
Weighted-average HH prices ($/MMBtu)			3.38		1.88			1.50
Average HH prices ($/MMBtu)										Average HH prices ($/MMBtu)	4.60		3.38		1.22		36	%
Realized differential to HH	Realized differential to HH		$	(0.58)	$	(0.05)		$	(0.53)	Realized differential to HH	$	(0.28)	$	(0.58)	$	0.30	(52)	%

The adverse impact of COVID-19 and instability in the global energy markets exacerbated a declining trend in realized prices that effectively eliminated our premium margin to the NYMEX WTI index price for crude oil. Our ~~less favorable~~ differential to NYMEX WTI for the three ~~month~~months ended March 31, 2022 improved by 32% compared to the corresponding period in 2021 ~~is primarily~~ due to ~~the change during 2020 from selling our production volumes based on LLS~~more favorable NYMEX Calendar Month Average contractual pricing component and ~~MEH~~more favorable pricing negotiated with certain new crude purchasers effective early in first quarter 2022. Our differential to ~~selling fully based on MEH pricing~~NYMEX HH also improved for the three ~~month period in 2021. While both LLS and MEH have historically been at a premium~~months ended March 31, 2022 due to ~~NYMEX WTI, MEH is less of a premium than LLS. NYMEX HH pricing was~~more favorable location basis differentials. See also ~~impacted by COVID-19 and the overall industry instability, as well as by the colder-than-normal weather during the winter of 2021. See~~ the discussion of Commodity Price and Other Economic Conditions in the Overview above.

Effects of Derivatives

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

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


							2021 vs. 2020			Three Months Ended March 31,
		Three Months Ended March 31,			Favorable
			2021		2020		(Unfavorable)
Crude oil revenues, as reported			$	81,913	$	86,308	$	(4,395)
Derivative settlements, net			(16,101)		15,527		(31,628)
Crude oil revenues, including effects of derivatives, net			$	65,812	$	101,835	$	(36,023)
										2022		2021		Change		% Change
Realized crude oil prices ($/bbl)	Realized crude oil prices ($/bbl)		$	55.76	$	45.90	$	9.86	Realized crude oil prices ($/bbl)	$	93.38	$	55.76	$	37.62	67	%
Effects of derivatives, net ($/bbl)	Effects of derivatives, net ($/bbl)		(10.96)		8.25		(19.21)		Effects of derivatives, net ($/bbl)	(19.38)		(10.96)		(8.42)		77	%
Crude oil realized prices, including effects of derivatives, net ($/bbl)	Crude oil realized prices, including effects of derivatives, net ($/bbl)		$	44.80	$	54.15	$	(9.35)	Crude oil realized prices, including effects of derivatives, net ($/bbl)	$	74.00	$	44.80	$	29.20	65	%

Natural gas revenues, as reported			$	2,833	$	2,690	$	143
Derivative settlements, net			$	42	$	104	(62)
Natural gas revenues, including effects of derivatives, net			$	2,875	$	2,794	$	81

Realized natural gas prices ($/Mcf)	Realized natural gas prices ($/Mcf)		$	2.80	$	1.83	$	0.97	Realized natural gas prices ($/Mcf)	$	4.32	$	2.80	$	1.52	54	%
Effects of derivatives, net ($/Mcf)	Effects of derivatives, net ($/Mcf)		$	0.04	$	0.07	(0.03)		Effects of derivatives, net ($/Mcf)	(0.36)		0.04		(0.40)		(1000)	%
Natural gas realized prices, including effects of derivatives, net ($/Mcf)	Natural gas realized prices, including effects of derivatives, net ($/Mcf)		$	2.84	$	1.90	$	0.94	Natural gas realized prices, including effects of derivatives, net ($/Mcf)	$	3.96	$	2.84	$	1.12	39	%

~~Derivative settlements, net and~~ 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 ~~Revenues,~~operating income, net

Other ~~revenues,~~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~~netted within this ~~caption as a contra-revenue item.~~caption.

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

2021 vs. 2020
Three Months Ended March 31, Favorable
2021 2020 (Unfavorable)
Other revenues, net $ 247 $ 488 $ (241)


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

Our ~~water disposal fees, net of operating costs, and~~ marketing ~~fees declined~~fee income increased in the three month period in 2022 as compared to the corresponding period in 2021 due primarily to ~~lower overall~~the higher commodity-based pricing and gain on sales ~~volume.~~of field materials.

Lease Operating Expenses

LOE includes costs that we incur to operate our producing wells and field operations. The most significant costs include compression and ~~gas-lift,~~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
		Three Months Ended March 31,			Favorable		Three Months Ended March 31,
			2021		2020			(Unfavorable)				2022		2021		Change		% Change
Lease operating	Lease operating		$	8,825	$	10,532		$	1,707		Lease operating	$	18,102	$	8,825	$	9,277	105	%
Per unit ($/boe)	Per unit ($/boe)		$	4.78	$	4.33		$	(0.45)		Per unit ($/boe)	$	5.33	$	4.78	$	0.55	12	%
% change per unit								(10.4)		%

LOE ~~decreased~~increased on an absolute basis and per unit basis during the three month period in ~~2021~~2022 when compared to the corresponding period in ~~2020. The absolute decrease was due primarily to lower sales volume in the three month period in~~ 2021 primarily resulting in lower chemical, water disposal, contract labor, environmental and utility costs. In addition, we experienced an overall higher level of efficiency attributable to a combination of cost-containment efforts and the application of operational improvements. These broad reductions were partially offset by higher gas lift costs due, in part, to the colder than usual months during the first quarter of 2021. The increase on a per unit basis is due primarily to the ~~decrease in~~impact of the Lonestar Acquisition, increased field labor and variable costs driven by higher sales ~~volumes.~~volume.

Gathering, Processing and Transportation

GPT expense includes costs that we incur to gather and aggregate our crude oil ~~NGL~~ 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
Three Months Ended March 31, Favorable
2021 2020 (Unfavorable)
Gathering, processing and transportation $ 4,674 $ 5,444 $ 770
Per unit ($/boe) $ 2.53 $ 2.24 $ (0.29)
% change per unit (12.9) %


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

GPT expense ~~declined~~increased on an absolute basis ~~during the three month period in 2021 as compared to the corresponding period in 2020~~ and ~~increased on a~~ per unit basis during the three month period in 2022 as compared to the corresponding period in 2021 due primarily to ~~lower~~the impact of the Lonestar Acquisition, which contributed to the 177% higher natural gas sales volumes ~~as well as~~and 65% higher crude oil sales volumes. Additionally, for certain of our crude oil volumes gathered, our rate includes an adjustment based on NYMEX WTI prices. As crude oil prices increase, up to a ~~decline~~cap of $90 per bbl, the gathering rate escalates. As such, with the higher prices during first quarter 2022 compared to first quarter 2021, we incurred higher gathering costs associated with these volumes. These unfavorable variances were partially offset by the effects of an increase in the mix of crude oil volume sold at the wellhead, including the majority of crude oil volumes from the acquired Lonestar wells, resulting in ~~higher~~reduced transportation ~~costs. In addition, we began incurring short-term rental charges to temporarily store a portion of our crude oil production during periods beginning after March 31, 2020 through to the current period.~~

costs and cost per unit.

Production and Ad Valorem Taxes

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

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


										2021 vs. 2020			Three Months Ended March 31,
		Three Months Ended March 31,				Favorable			2022				2021			Change			% Change
			2021			2020				(Unfavorable)
Production and ad valorem taxes
Production/severance taxes	Production/severance taxes		$	4,242		$	4,078			$	(164)	Production/severance taxes	$	11,570		$	4,242		$	7,328		173	%
Ad valorem taxes	Ad valorem taxes		1,271			2,076				805		Ad valorem taxes	1,570			1,271			299			24	%
			$	5,513		$	6,154			$	641		$	13,140		$	5,513		$	7,627		138	%
Per unit ($/boe)	Per unit ($/boe)		$	2.98		$	2.53			$	(0.45)	Per unit ($/boe)	$	3.87		$	2.98		$	0.89		30	%
Production/severance tax rate as a percent of product revenues	Production/severance tax rate as a percent of product revenues		4.8		%	4.5		%				Production/severance tax rate as a percent of product revenues	4.5		%	4.8		%	(0.3)		%	—	%

Production and Ad Valorem taxes increased on an absolute basis and per unit basis during the three month period in ~~2021~~2022 when compared to the corresponding period in ~~2020~~2021 due primarily to the ~~increases in~~impact of the Lonestar Acquisition. Additionally, Production taxes increased on an absolute and per unit basis due to higher aggregate commodity sales prices ~~of 28 percent in~~during the three month period in ~~2021. Our accruals for ad valorem taxes are based on our most recent estimates for assessments which reflect lower property values primarily due to the collapse of commodity prices during 2020.~~2022.

General and Administrative

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

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


								2021 vs. 2020			Three Months Ended March 31,
		Three Months Ended March 31,			Favorable		2022				2021		Change		% Change
			2021		2020			(Unfavorable)
Primary G&A			$	6,037	$	6,374		$	337
Primary G&A expenses										Primary G&A expenses	$	7,112	$	6,037	$	1,075	18	%
Share-based compensation	Share-based compensation		2,246		856			(1,390)		Share-based compensation	924		2,246		(1,322)
Significant special charges:	Significant special charges:									Significant special charges:							100	%
Organizational restructuring, including severance	Organizational restructuring, including severance		239		—			(239)		Organizational restructuring, including severance	—		239		(239)		(100)	%
Acquisition, divestiture and strategic transaction costs			4,655		—			(4,655)

Total G&A			$	13,177	$	7,230		$	(5,947)
Acquisition/integration and strategic transaction costs										Acquisition/integration and strategic transaction costs	1,743		4,655		(2,912)		(63)	%
Total G&A expenses										Total G&A expenses	$	9,779	$	13,177	$	(3,398)	(26)	%
Per unit ($/boe)	Per unit ($/boe)		$	7.13	$	2.97		$	(4.16)	Per unit ($/boe)	$	2.88	$	7.13	$	(4.25)	(60)	%
Per unit of excluding share-based compensation and other significant special charges identified above ($/boe)			$	3.27	$	2.62		$	(0.65)
Per unit ($/boe) excluding share-based compensation and other significant special charges identified above										Per unit ($/boe) excluding share-based compensation and other significant special charges identified above	$	2.09	$	3.27	$	(1.18)	(36)	%

Our ~~primary~~total G&A expenses ~~decreased~~were lower on an absolute ~~basis~~ and ~~increased on a~~ per unit basis during the three month period in ~~2021~~2022 when compared to the corresponding period in ~~2020. The absolute decrease is~~2021 due ~~primarily~~ to a lower ~~level of employee headcount resulting from reductions~~costs incurred in ~~force that occurred~~first quarter 2022 for the Lonestar Acquisition integration related costs than the costs incurred in first quarter 2021 associated with the Juniper Transactions, as well as lower share-based compensation cost due to the incremental $1.9 million charge during ~~the second half of 2020. The lower headcount also resulted in lower overall support costs. The decrease was~~first quarter 2021 discussed below. These decreases were partially offset by higher ~~incentive compensation accruals. The increase~~salaries and wages in ~~per unit costs was~~2022, primarily ~~due to the effect of lower overall production volume in~~driven by increased headcount.

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

Share-based compensation charges during the periods presented are attributable to the amortization of compensation cost, net of forfeitures, associated with the grants of time-vested restricted stock units (“RSUs”), and performance-based restricted stock units (“PRSUs”). The grants of RSUs and PRSUs are described in greater detail in Note 1412 to the ~~Condensed Consolidated Financial Statements~~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 Closing Date in accordance with their terms. This resulted in~~and an incremental charge of approximately $1.9 ~~million.~~million was recorded during the first quarter 2021. All of our share-based compensation represents non-cash expenses.

In connection with the restructuring and elimination of certain executive management positions, we incurred incremental G&A costs including severance costs and termination benefits. During the first quarter of 2021, we incurred certain professional fees and consulting costs, including certain success-based fees of approximately $4.7 million in connection with the Juniper Transactions.

Depreciation, Depletion and Amortization

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

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


								2021 vs. 2020
		Three Months Ended March 31,			Favorable		Three Months Ended March 31,
			2021		2020			(Unfavorable)			2022		2021		Change		% Change
DD&A expense	DD&A expense		$	23,884	$	40,718		$	16,834	DD&A expense	$	50,893	$	23,884	$	27,009	113	%
DD&A rate ($/boe)	DD&A rate ($/boe)		$	12.92	$	16.73		$	3.81	DD&A rate ($/boe)	$	14.98	$	12.92	$	2.06	16	%

DD&A ~~decreased~~expense increased on an absolute and a per unit basis during the three month period in ~~2021~~2022 when compared to the corresponding period in ~~2020. Lower~~2021. Higher production volume provided for ~~decreases~~an increase of ~~$9.8~~$20.0 million and ~~lower~~a higher DD&A ~~rates~~rate resulted in ~~decreases~~an increase of $7.0 million ~~in 2021.~~for first quarter 2022. The ~~lower~~higher DD&A ~~rates~~rate in ~~2021~~2022 is primarily ~~attributable~~due to the ~~effect of adding additional~~Lonestar Acquisition, which contributed to an increase in our total proved reserves inat a higher relative cost per boe as compared to the ~~fourth quarter of 2020 and~~ first quarter ~~of 2021 as well as the effect of the impairment recorded in the fourth quarter of 2020.~~2021.

Impairment of Oil and Gas Properties

We assess our oil and gas properties on a quarterly basis based on the results of a ~~Ceiling Test~~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. ~~During the first quarter of 2021, we recorded~~


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

We did not record an impairment of our oil and gas properties during the three month period in 2022, compared to an impairment of $1.8 million ~~due primarily to~~recorded in the corresponding period in 2021. The impairment in 2021 was the result of the decline in the twelve-month average prices of crude oil, NGLs and natural gas as indicated by ~~our~~the respective quarterly Ceiling Test under the full cost method of accounting for oil and gas properties. ~~No impairment was recorded during the first quarter of 2020.~~

Interest Expense

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

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

In addition, we are assessed certain fees for the overall credit commitments provided to us as well as fees for credit utilization and letters of credit. 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.

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


								2021 vs. 2020
		Three Months Ended March 31,			Favorable		Three Months Ended March 31,
			2021		2020			(Unfavorable)			2022		2021		Change		% Change
Interest on borrowings and related fees	Interest on borrowings and related fees		$	5,632	$	8,045		$	2,413	Interest on borrowings and related fees	$	10,957	$	5,632	$	5,325	95	%
Accretion of original issue discount	Accretion of original issue discount		105		196			91		Accretion of original issue discount	640		105		535		510	%
Amortization of debt issuance costs	Amortization of debt issuance costs		506		627			121		Amortization of debt issuance costs	160		506		(346)		(68)	%
Capitalized interest	Capitalized interest		(846)		(688)			158		Capitalized interest	(1,060)		(846)		(214)		25	%
			$	5,397	$	8,180		$	2,783
Total interest expense, net of capitalized interest										Total interest expense, net of capitalized interest	$	10,697	$	5,397	$	5,300	98	%

~~Interest~~The increase in interest expense ~~decreased~~ during the three month period in 2022 is primarily attributable to interest incurred in the amount of $8.8 million for the 9.25% Senior Notes due 2026 and $1.7 million for the Credit Facility compared to interest incurred in the corresponding period in 2021 of $3.5 million for the Second Lien Term Loan and $1.9 million for the Credit Facility as well as increased amortization of OID compared to the corresponding period in 2021. These increases are partially offset by decreased amortization of debt issuance costs during the three month period in 2022 when compared to the corresponding period in 2021 and increased capitalized interest during the three month period in 2022, driven by higher overall weighted-average interest rate in 2022 as compared to the corresponding period in 2020 due primarily to the effect of lower outstanding balances under the Credit Facility and Second Lien Facility during the three month period in 2021 and lower interest rates associated with the Credit Facility, due primarily to lower applicable margins resulting from lower utilization levels. The weighted-average balance under the Credit Facility was lower in the three month period in 2021 compared to the three month period in 2020 by approximately $132 million. The weighted-average interest rate was lower during the same period by 50 basis points. The weighted-average balance of the Second Lien Facility was lower in the three month period in 2021 compared to the three month period in 2020 by approximately $43 million while the weighted-average interest rate was higher during the same period by 33 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 month period 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.2021.

~~Loss on Extinguishment of Debt~~

In connection with the prepayments associated with the recent amendments to the Credit Facility and Second Lien Facility, we wrote-off $1.2 million of unamortized OID and debt issuance costs in proportion to the principal balances prior to the prepayments during the quarter ended March 31, 2021.

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 ~~rate swaps.~~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
Three Months Ended March 31, Favorable
2021 2020 (Unfavorable)
Commodity derivative gains (losses) $ (44,400) $ 157,802 $ (202,202)
Interest rate swap gains (losses) 32 (6,683) 6,715
$ (44,368) $ 151,119 $ (195,487)


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

In the three month period in ~~2021,~~2022, commodity prices ~~recovered to levels that~~ were ~~28 percent~~significantly higher on an average aggregate basis than those during the corresponding ~~period~~periods in ~~2020.~~ ~~Accordingly, the~~2021. The derivative losses in the three month ~~period~~periods in 2022 and 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 month period in 2020 was in the opposite direction as the market-to-market gains associated were attributable to the substantial collapse in prices~~positions for ~~the underlying commodities relative to our hedged positions.~~ both periods. Realized settlement payments, net for crude oil and natural gas derivatives were ~~$3.4~~$28.5 million and ~~$0.4~~$6.2 million during the three ~~months ended March 31,~~month periods in 2022 and 2021, ~~and 2020,~~ respectively. ~~In 2020, we began hedging~~We hedge a portion of our exposure to variable interest rates associated with our Credit Facility and, in first quarter 2021, our Second Lien ~~Facility.~~Term Loan. For both the three ~~months ended March 31,~~month periods in 2022 and 2021, we paid $0.9 million of net settlements from our interest rate ~~swaps while we received $0.1 million of net settlements during the three months ended March 31, 2020.~~

~~Other, net~~

Other, net includes interest income, non-service costs associated with our retiree benefit plans and miscellaneous items of income and expense that are not directly associated with our current operations, including certain recoveries and write-offs attributable to prior years and properties that have been divested.

~~The following table sets forth the other income (expense), net recognized for the periods presented:~~

2021 vs. 2020
Three Months Ended March 31, Favorable
2021 2020 (Unfavorable)
Other, net $ (6) $ (8) $ 2

Other, net expense decreased marginally during the three month period in 2021 as compared to the corresponding period in 2020 and was comprised entirely of costs associated with our retiree benefit plans for each of the three month periods in 2021 and 2020.

swaps.

Income Taxes

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

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


										2021 vs. 2020			Three Months Ended March 31,
		Three Months Ended March 31,				Favorable			2022				2021			Change			% Change
			2021			2020				(Unfavorable)
Income tax (expense) benefit			$	310		$	(1,138)			$	1,448
Income tax benefit												Income tax benefit	$	189		$	310		$	(121)		(39)	%
Effective tax rate	Effective tax rate		1.5		%	0.7		%				Effective tax rate	0.9		%	1.5		%	(0.6)		%	—	%

The income tax provision resulted in a benefit of $0.2 million for the three months ended March 31, ~~2021 resulted in a benefit of $0.3 million.~~2022. The federal portion was fully offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of ~~1.5%~~0.9%, which is fully attributable to the State of Texas. In connection with the Juniper Transactions, we recorded an adjustment of $0.7 million to “Paid-in capital” (see Note 3 to the Condensed Consolidated Financial Statements) attributable to certain state deferred income tax effects associated with the change in legal entity structure. Our net deferred income tax liability balance of ~~$0.4~~$2.1 million as of March 31, ~~2021~~2022 is also fully attributable to the State of Texas and primarily related to property.

~~We recognized a federal and state~~The income tax ~~expense~~provision resulted in a benefit of $0.3 million for the three months ended March 31, ~~2020 of $1.1 million. The feder~~al2021. The federal and state tax expense was fully offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of ~~0.7%~~1.5% 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.

~~Off Balance Sheet Arrangements~~Liquidity and Capital Resources

Liquidity

Our primary sources of liquidity include our cash on hand, cash provided by operating activities and borrowings under the Credit Facility. As of March 31, ~~2021,~~2022, we had ~~no off-balance sheet arrangements~~liquidity of $277.7 million, comprised of cash and cash equivalents of $6.4 million and availability under our Credit Facility of $271.3 million (factoring in letters of credit). The Credit Facility provides us up to $1.0 billion in borrowing commitments. The current borrowing base under the Credit Facility is $725.0 million with aggregate elected commitments of $400.0 million. The availability under the Credit Facility of $271.3 million remained unchanged as of April 28, 2022.

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

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

Capital Resources

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

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

Share Repurchase Program

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

Tax Distributions

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

Cash Flows

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


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

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

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

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


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

_______________________

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

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


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

_______________________

1 Includes purchases made in advance of drilling.

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

Capitalization

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


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

_______________________

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

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

Credit Facility. As of March 31, 2022, the Credit Facility had a $1.0 billion revolving commitment and a $725 million borrowing base, with aggregate elected commitments of $400 million and a $25 million sublimit for the issuance of letters of credit. The borrowing base under the Credit Facility is redetermined semi-annually, generally in the Spring and Fall of each year. Additionally, we and the Credit Facility lenders may, upon request, initiate a redetermination at any time during the six-month period between scheduled redeterminations. Our next borrowing base redetermination is scheduled in May 2022. The Credit Facility is available to us for general corporate purposes including working capital. We had $0.7 million and $0.9 million in letters of credit outstanding as of March 31, 2022 and December 31, 2021, respectively. The maturity date under the Credit Facility is October 6, 2025.

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

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


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

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

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

Covenant Compliance. The Credit Facility requires us to maintain (1) a minimum current ratio (as defined in the Credit Facility, which considers the unused portion of the total commitment as a current asset) of 1.00 to 1.00 and (2) a maximum leverage ratio (consolidated indebtedness to EBITDAX, each as defined in the Credit Facility), in each case measured as of the last day of each fiscal quarter of 3.50 to 1.00.

The Credit Facility and the indenture governing the 9.25% Senior Notes due 2026 contain customary affirmative and negative covenants as well as events of default and remedies. If we do not comply with the financial and other covenants in the Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Credit Facility.

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

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

Critical Accounting Estimates

The process of preparing financial statements in accordance with ~~accounting principles generally accepted in the United States of America (“GAAP”)~~GAAP requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Disclosure of our most critical accounting estimates that involve the judgment of our management can be found in our Annual Report on Form 10-K for the year ended December 31, ~~2020.~~2021.

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

impairment.

4038

Item 3. Quantitative and Qualitative Disclosures About Market ~~Risk.~~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

~~All of our long-term debt instruments are subject to variable interest rates.~~ As of March 31, ~~2021,~~2022, we had variable-rate borrowings of ~~$228.9~~$128.0 million under the Credit Facility and ~~$146.9~~fixed-rate borrowings of $400.0 million ~~under~~for the ~~Second Lien Facility~~9.25% Senior Notes due 2026 at interest rates of ~~3.11%~~3.02% and 9.25%, respectively. Assuming a constant borrowing level under the Credit ~~Facility and Second Lien~~ Facility, an increase (decrease) in the interest rate of one percent would result in an increase (decrease) in aggregate interest payments of approximately ~~$3.8~~$1.3 million on an annual basis, excluding the offsetting impact of our interest rate swap derivatives.

Commodity Price Risk

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

As of March 31, ~~2021,~~2022, our commodity derivative portfolio was in a net ~~liabilities~~liability position in the amount of ~~$36.5~~$178.6 million. The contracts associated with this position are with ~~seven~~eight counterparties, all of which are investment grade financial institutions. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We have neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. Furthermore, our derivative contracts are not subject to margin calls or similar accelerations. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.

During the three months ended March 31, ~~2021,~~2022, we reported a net commodity derivative loss of ~~$44.4~~$168.0 million. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our derivative instruments. Our results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which fluctuate with changes in crude oil, NGL and natural gas prices. These fluctuations could be significant in a volatile pricing environment. See Note 5 to the ~~Condensed Consolidated Financial Statements~~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 sets forth our commodity derivative positions as of March 31, 2021:~~

2Q2021 3Q2021 4Q2021 1Q2022 2Q2022 3Q2022 4Q2022 1Q2023 2Q2023
NYMEX WTI Crude Swaps
Average Volume Per Day (bbl) 3,297 815 815
Weighted Average Swap Price ($/bbl) $ 55.89 $ 45.54 $ 45.54
NYMEX WTI Crude Collars
Average Volume Per Day (bbl) 12,088 10,870 8,152 5,417 4,533 4,484 4,484 2,917 2,855
Weighted Average Purchased Put Price ($/bbl) $ 43.82 $ 41.80 $ 40.40 $ 40.00 $ 40.00 $ 40.00 $ 40.00 $ 40.00 $ 40.00
Weighted Average Sold Call Price ($/bbl) $ 54.67 $ 56.09 $ 52.10 $ 53.49 $ 52.47 $ 52.47 $ 52.47 $ 50.00 $ 50.00
NYMEX WTI Sold Puts
Average Volume Per Day (bbl) 4,945 5,707 5,707
Weighted Average Sold Put Price ($/bbl) $ 29.83 $ 35.14 $ 35.14
NYMEX WTI Crude CMA Roll Basis Swaps
Average Volume Per Day (bbl) 18,132 17,935 17,935
Weighted Average Swap Price ($/bbl) $ 0.17 $ 0.17 $ 0.17
NYMEX HH Collars
Average Volume Per Day (MMBtu) 9,890 9,783 9,783
Weighted Average Purchased Put Price ($/MMBtu) $ 2.607 $ 2.607 $ 2.607
Weighted Average Sold Call Price($/MMBtu) $ 3.117 $ 3.117 $ 3.117
NYMEX HH Sold Puts
Average Volume Per Day (MMBtu) 6,593 6,522 6,522
Weighted Average Sold Put Price ($/MMBtu) $ 2.000 $ 2.000 $ 2.000
OPIS Mt Belv Ethane Swaps
Average Volume per Day (gal) 36,264 35,870
Weighted Average Fixed Price ($/gal) $ 0.2263 $ 0.2288

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)					Change of 10% per bbl of Crude Oil ($ in millions)
		Increase		Decrease			Increase		Decrease
Effect on the fair value of crude oil derivatives 1	Effect on the fair value of crude oil derivatives 1	$	(27.5)	$	21.2	Effect on the fair value of crude oil derivatives 1	$	(66.4)	$	46.5
Effect of crude oil price changes for the remainder of 2021 on operating income, excluding derivatives 2		$	32.6	$	(32.6)
Effect of crude oil price changes for the remainder of 2022 on operating income, excluding derivatives 2						Effect of crude oil price changes for the remainder of 2022 on operating income, excluding derivatives 2	$	37.4	$	(38.3)

~~_____________________________~~_______________________

1Based on derivatives outstanding as of March 31, ~~2021.~~2022.

2 These sensitivities are subject to significant change.

Item 4. Controls and ~~Procedures.~~Procedures

(a) Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of March 31, ~~2021.~~2022. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported on a timely basis and that such information is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of March 31, ~~2021,~~2022, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

~~During~~Except as described below, during the quarter ended March 31, ~~2021,~~2022, there were no changes to our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

Part II. OTHER INFORMATION

Item 1. Legal ~~Proceedings.~~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~~Quarterly Report on Form 10-Q. See Note 1211 to our ~~Condensed Consolidated Financial Statements~~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.~~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.~~2021 except as follows:

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

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

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

(a) None.

(b) None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other ~~Information.~~Information

None.

4340

Item 6. ~~Exhibits.~~Exhibits


(~~10.1~~(31.1) )			~~Separation Agreement, dated as of January 4, 2021, by and between Penn Virginia Corporation and Benjamin A. Mathis.~~


(~~31.1~~) *			Certification Pursuant to Rule 13a-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

(~~32.1~~(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~~(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 ~~Penn Virginia~~Ranger Oil Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, ~~2021,~~2022, formatted in Inline XBRL (included within the Exhibit 101 attachments).

_____________________________

* Filed herewith.

† Furnished herewith.

4441

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.


	~~PENN VIRGINIA~~RANGER OIL CORPORATION

May ~~4, 2021~~5, 2022	By:	/s/ RUSSELL T KELLEY, JR.
		Russell T Kelley, Jr.
		Senior Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

May ~~4, 2021~~5, 2022	By:	/s/ KAYLA D. BAIRD
		Kayla D. Baird
		Vice President, Chief Accounting Officer and Controller
		(Principal Accounting Officer)

4542


Part I - Financial Information
Item		Page
1.	Financial Statements - unaudited.
	Condensed Consolidated Statements of Operations	3
	Condensed Consolidated Statements of Comprehensive Income	4
	Condensed Consolidated Balance Sheets	5
	Condensed Consolidated Statements of Cash Flows	6
	Notes to Condensed Consolidated Financial Statements:
	1. Nature of Operations	7
	2. Basis of Presentation	7
	3. Juniper Transactions	7
	4. Accounts Receivable and Revenues from Contracts with Customers	9
	5. Derivative Instruments	10
	6. Property and Equipment	13
	7. Long-Term Debt	13
	8. Income Taxes	15
	9. Leases	15
	10. Supplemental Balance Sheet Detail	17
	11. Fair Value Measurements	17
	12. Commitments and Contingencies	19
	13. Equity	19
	14. Share-Based Compensation and Other Benefit Plans	20
	15. Interest Expense	21
	16. Earnings per Share	22
Forward-Looking Statements		22
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.
	Overview and Executive Summary	24
	Key Developments	26
	Financial Condition	28
	Results of Operations	33
	Off Balance Sheet Arrangements	40
	Critical Accounting Estimates	40
3.	Quantitative and Qualitative Disclosures About Market Risk.	40
4.	Controls and Procedures.	42
Part II - Other Information
1.	Legal Proceedings.	43
1A.	Risk Factors.	43
5.	Other Information.	43
6.	Exhibits.	44
Signatures		45


	Mutual Operators		Large Partners		All Others		Total
Balance at beginning of period	$	9	$	87	$	101	$	197
Provision for expected credit losses	(7)		202		(28)		167
Write-offs and recoveries	0		0		0		0
Balance at end of period	$	2	$	289	$	73	$	364


	March 31, 2021				December 31, 2020
	Principal		Unamortized Discount and Deferred Issuance Costs 1, 2		Principal		Unamortized Discount and Deferred Issuance Costs 1, 2
Credit facility	$	228,900			$	314,400
Second lien term loan	146,860		$	4,698	200,000		$	4,903
Totals	375,760		$	4,698	514,400		$	4,903
Less: Unamortized discount 2	(1,096)				(1,604)
Less: Unamortized deferred issuance costs 1, 2	(3,602)				(3,299)
Totals, net	$	371,062			$	509,497
Less: Current portion	(7,500)				0
Long-term debt	$	363,562			$	509,497


	As of March 31, 2021
	Fair Value		Fair Value Measurement Classification
Description	Measurement		Level 1		Level 2		Level 3
Assets:


Commodity derivative assets – current	$	13,093	$	0	$	13,093	$	0
Commodity derivative assets – noncurrent	$	5,269	$	0	$	5,269	$	0
Liabilities:
Interest rate swap liabilities – current	$	(3,730)	$	—	$	(3,730)	$	—
Interest rate swap liabilities – noncurrent	$	(615)	$	—	$	(615)	$	—
Commodity derivative liabilities – current	$	(40,598)	$	0	$	(40,598)	$	0
Commodity derivative liabilities – noncurrent	$	(14,299)	$	0	$	(14,299)	$	0


	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	$	0	$	75,506	$	0
Commodity derivative assets – noncurrent	$	25,449	$	0	$	25,449	$	0
Liabilities:
Interest rate swap liabilities – current	$	(3,655)	$	—	$	(3,655)	$	—
Interest rate swap liabilities – noncurrent	$	(1,645)	$	—	$	(1,645)	$	—
Commodity derivative liabilities – current	$	(81,451)	$	0	$	(81,451)	$	0
Commodity derivative liabilities – noncurrent	$	(26,789)	$	0	$	(26,789)	$	0