rocc-20230331

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, 2023


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

For the transition period from to

Commission file number: 1-13283

RANGER OIL CORPORATION

(Exact name of registrant as specified in its charter)


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

16285 Park Ten Place, Suite 500

Houston, TX 77084

(Address of principal executive offices) (Zip Code)

(713) 722-6500

(Registrant’s telephone number, including area code)

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Class A Common Stock, $0.01 Par Value

ROCC

The Nasdaq Stock Market LLC

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

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

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

Large accelerated filer

☐

Accelerated filer

☒

Non-accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

As of May 3, 2023, there were 41,557,708 shares of common stock outstanding, including 19,008,710 shares of Class A Common Stock and 22,548,998 shares of Class B Common Stock.

RANGER OIL CORPORATION

QUARTERLY REPORT ON FORM 10-Q

For the Quarterly Period Ended March 31, 2023

Table of Contents


		Page
	Part I - Financial Information
Item 1.	Financial Statements - Unaudited	3
	Condensed Consolidated Statements of Operations - Unaudited	3
	Condensed Consolidated Statements of Comprehensive Income (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 – Basis of Presentation and Significant Accounting Policies	8
	Note 3 – Transactions	10
	Note 4 – Revenue Recognition	10
	Note 5 – Derivative Instruments	11
	Note 6 – Property and Equipment, Net	14
	Note 7 – Long-Term Debt	15
	Note 8 – Income Taxes	16
	Note 9 – Supplemental Balance Sheet Detail	17
	Note 10 – Fair Value Measurements	17
	Note 11 – Commitments and Contingencies	19
	Note 12 – Shareholders’ Equity	20
	Note 13 – Share-Based Compensation and Other Benefit Plans	21
	Note 14 – Earnings Per Share	23
	Note 15 – Subsequent Events	23
Forward-Looking Statements		24
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
	Overview and Executive Summary	25
	Results of Operations	28
	Liquidity and Capital Resources	36
	Critical Accounting Estimates	39
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40
Item 4.	Controls and Procedures	41
	Part II - Other Information
Item 1.	Legal Proceedings	41
Item 1A.	Risk Factors	41
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 3.	Defaults Upon Senior Securities	41
Item 4.	Mine Safety Disclosures	41
Item 5.	Other Information	41
Item 6.	Exhibits	42
Signatures		43

Part I. FINANCIAL INFORMATION

Item 1. Financial Statements

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – UNAUDITED

(in thousands, except per share data)


	Three Months Ended March 31,
	2023		2022
Revenues and other
Crude oil	$	236,932	$	226,732
Natural gas liquids	12,154		16,740
Natural gas	8,345		12,127
Other operating income, net	717		856
Total revenues and other	258,148		256,455
Operating expenses
Lease operating	29,990		18,102
Gathering, processing and transportation	10,180		9,040
Production and ad valorem taxes	16,042		13,140
General and administrative	12,668		9,779
Depreciation, depletion and amortization	85,303		50,893

Total operating expenses	154,183		100,954
Operating income	103,965		155,501
Other income (expense)
Interest expense, net of amounts capitalized	(14,718)		(10,697)
Gain on extinguishment of debt	—		2,157
Derivative gains (losses)	25,658		(167,887)
Other, net	(123)		76
Income (loss) before income taxes	114,782		(20,850)
Income tax (expense) benefit	(991)		189
Net income (loss)	113,791		(20,661)
Net (income) loss attributable to Noncontrolling interest	(61,792)		10,676
Net income (loss) attributable to Class A common shareholders	$	51,999	$	(9,985)

Net income (loss) per share attributable to Class A common shareholders:
Basic	$	2.74	$	(0.47)
Diluted	$	2.67	$	(0.47)

Weighted average shares outstanding – basic	18,975		21,107
Weighted average shares outstanding – diluted	19,623		21,107

See accompanying notes to condensed consolidated financial statements.

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) – UNAUDITED

(in thousands)


	Three Months Ended March 31,
	2023		2022
Net income (loss)	$	113,791	$	(20,661)
Other comprehensive income (loss):
Change in pension and postretirement obligations, net of tax ¹	32		—
Comprehensive income (loss)	113,823		(20,661)
Net (income) loss attributable to Noncontrolling interest	(61,792)		10,676
Other comprehensive income attributable to Noncontrolling interest ¹	(17)		—
Comprehensive income (loss) attributable to Class A common shareholders	$	52,014	$	(9,985)

___________________________________________

1 The amounts for 2022 are minimal and round down to zero.

See accompanying notes to condensed consolidated financial statements.

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS – UNAUDITED

(in thousands, except share data)


	March 31, 2023		December 31, 2022
Assets
Current assets
Cash and cash equivalents	$	12,354	$	7,592
Accounts receivable, net of allowance for credit losses	138,546		139,715
Derivative assets	23,756		29,714
Prepaid and other current assets	18,460		22,264
Assets held for sale	1,186		1,186
Total current assets	194,302		200,471
Property and equipment, net	1,874,836		1,809,000
Derivative assets	216		316
Other assets	17,278		4,420
Total assets	$	2,086,632	$	2,014,207

Liabilities and Equity
Current liabilities
Accounts payable and accrued liabilities	$	239,792	$	265,609
Derivative liabilities	32,286		67,933

Total current liabilities	272,078		333,542

Deferred income taxes	7,022		6,216
Derivative liabilities	1,320		3,416
Other non-current liabilities	13,131		9,934
Long-term debt, net	629,480		604,077

Commitments and contingencies (Note 11)

Equity
Preferred stock of $0.01 par value – 5,000,000 shares authorized; none issued as of March 31, 2023 and December 31, 2022	—		—
Class A common stock, $0.01 par value – 110,000,000 shares authorized; 18,982,425 and 19,074,864 issued and outstanding as of March 31, 2023 and December 31, 2022, respectively	190		190
Class B common stock, $0.01 par value – 30,000,000 shares authorized; 22,548,998 shares issued and outstanding as of March 31, 2023 and December 31, 2022	2		2
Paid-in capital	216,941		220,062
Retained earnings	314,801		264,256
Accumulated other comprehensive loss	(96)		(111)
Ranger Oil shareholders’ equity	531,838		484,399
Noncontrolling interest	631,763		572,623
Total equity	1,163,601		1,057,022
Total liabilities and equity	$	2,086,632	$	2,014,207

See accompanying notes to condensed consolidated financial statements.

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – UNAUDITED

(in thousands)


	Three Months Ended March 31,
	2023		2022
Cash flows from operating activities
Net income (loss)	$	113,791	$	(20,661)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Gain on extinguishment of debt	—		(2,157)
Depreciation, depletion and amortization	85,303		50,893

Derivative contracts:
Net (gains) losses	(25,658)		167,887
Cash settlements and premiums paid, net	(7,358)		(29,408)
Deferred income tax expense (benefit)	806		(721)
Non-cash interest expense	933		800
Share-based compensation	2,051		924
Other, net	349		(182)
Changes in operating assets and liabilities, net	(9,968)		(33,540)
Net cash provided by operating activities	160,249		133,835

Cash flows from investing activities
Capital expenditures	(171,464)		(71,173)
Proceeds from sales of assets and other, net	447		656

Net cash used in investing activities	(171,017)		(70,517)

Cash flows from financing activities
Proceeds from credit facility borrowings	156,000		50,000
Repayments of credit facility borrowings	(131,000)		(130,000)
Repayments of acquired and other debt	(238)		(83)
Payments for share repurchases	(4,816)		—
Distributions to Noncontrolling interest	(1,691)		—
Dividends paid	(1,438)		—
Withholding taxes for share-based compensation	(1,287)		(445)
Debt issuance costs paid	—		(113)
Net cash provided by (used in) financing activities	15,530		(80,641)
Net increase (decrease) in cash and cash equivalents	4,762		(17,323)
Cash and cash equivalents – beginning of period	7,592		23,681
Cash and cash equivalents – end of period	$	12,354	$	6,358

Supplemental disclosures:
Cash paid for:
Interest, net of amounts capitalized	$	22,997	$	20,214


Non-cash investing and financing activities:

Changes in accrued liabilities related to capital expenditures	$	(22,408)	$	9,361
ROU assets obtained in exchange for lease obligations:
Operating leases	$	15,865	$	—

See accompanying notes to condensed consolidated financial statements.

RANGER OIL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - UNAUDITED

(in thousands)


	Shares
	Preferred Shares Outstanding	Class A Common Shares	Class B Common Shares Outstanding	Preferred Stock		Class A Common Stock		Class B Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Loss		Noncontrolling Interest		Total Equity
Balance as of December 31, 2022	—	19,075	22,549	$	—	$	190	$	2	$	220,062	$	264,256	$	(111)	$	572,623	$	1,057,022
Net income	—	—	—	—				—		—		51,999		—		61,792		113,791
Repurchase of Class A common stock	—	(122)	—	—		(1)		—		(4,863)		—		—		—		(4,864)
Change in ownership, net	—	—	—	—				—		978		—		—		(978)		—
Distributions to Noncontrolling interest	—	—	—	—				—		—		—		—		(1,691)		(1,691)
Dividends declared ($0.075 per share of Class A common stock)	—	—	—	—				—		—		(1,454)		—		—		(1,454)
Common stock issued related to share-based compensation and other, net ¹	—	29	—	—		1		—		764				15		17		797
Balance as of March 31, 2023	—	18,982	22,549	$	—	$	190	$	2	$	216,941	$	314,801	$	(96)	$	631,763	$	1,163,601

1 Includes equity-classified share-based compensation of $2.1 million during the three months ended March 31, 2023. During the three months ended March 31, 2023, 29,418 of Class A common stock, par value $0.01 per share (“Class A Common Stock”) were issued in connection with the vesting of certain time-vested restricted stock units (“RSUs”) and performance-based restricted stock units (“PRSUs”), net of shares withheld for income taxes.


	Shares
	Preferred Shares Outstanding	Class A Common Shares	Class B Common Shares Outstanding	Preferred Stock		Class A Common Stock		Class B Common Stock		Paid-in Capital		Retained Earnings		Accumulated Other Comprehensive Loss		Noncontrolling Interest		Total Equity
Balance as of December 31, 2021	—	21,090	22,549	$	—	$	729	$	2	$	273,329	$	49,583	$	(111)	$	345,976	$	669,508
Net loss	—	—	—	—		—		—		—		(9,985)		—		(10,676)		(20,661)




Common stock issued related to share-based compensation and other, net ¹	—	56	—	—		—		—		478		—		—		—		478
Balance as of March 31, 2022	—	21,146	22,549	$	—	$	729	$	2	$	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, 55,971 of Class A Common Stock were issued in connection with the vesting of certain RSUs, net of shares withheld for income taxes. No shares of Class A Common Stock were issued in connection with the vesting of PRSUs during the three months ended March 31, 2022.

See accompanying notes to condensed consolidated financial statements.

RANGER OIL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – UNAUDITED

For the Quarterly Period Ended March 31, 2023

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

Note 1 – Organization and Description of Business

Ranger Oil Corporation (together with its consolidated subsidiaries, unless the context otherwise requires, “Ranger Oil,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company focused on the onshore development and production of oil, natural gas liquids (“NGLs”) and natural gas. Our current operations consist of drilling unconventional horizontal development wells and operating our producing wells in the Eagle Ford Shale (the “Eagle Ford”) in South Texas. We operate in and report our financial results and disclosures as one segment, which is the development and production of crude oil, NGLs and natural gas.

Juniper Capital Advisors, L.P. (“Juniper Capital”), through its affiliates, JSTX Holdings, LLC (“JSTX”) and Rocky Creek Resources, LLC (“Rocky Creek” and together with JSTX and Juniper Capital, “Juniper”), beneficially owned as of March 31, 2023 an approximate 54% equity interest in the Company through its ownership of 22,548,998 shares of our Class B common stock, par value of $0.01 per share (“Class B Common Stock”) and 22,548,998 common units (the “Common Units”) in our Up-C partnership subsidiary, ROCC Energy Holdings, L.P. (the “Partnership”). See Note 2 for further information.

Note 2 – Basis of Presentation and Significant Accounting Policies

Basis of Presentation

Our unaudited condensed consolidated financial statements include the accounts of Ranger Oil and all of our subsidiaries as of the relevant dates. Intercompany balances and transactions have been eliminated. A substantial noncontrolling interest in our subsidiaries is provided for in our condensed consolidated statements of operations and comprehensive income (loss) 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. 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, 2022 (“2022 Annual Report”). Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

Principles of Consolidation

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

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

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

Noncontrolling Interest

The noncontrolling interest percentage may be affected by the issuance of shares of Class A Common Stock, repurchases or cancellation of Class A Common Stock, the exchange of Class B Common Stock and the redemption of Common Units (and concurrent cancellation of Class B Common Stock), among other things. The percentage is based on the proportionate number of Common Units held by Juniper relative to the total Common Units outstanding. As of March 31, 2023, the Company owned 18,982,425 Common Units, representing a 45.7% limited partner interest in the Partnership, and Juniper owned 22,548,998 Common Units, representing the remaining 54.3% limited partner interest. As of December 31, 2022, the Company owned 19,074,864 Common Units, representing a 45.8% limited partner interest in the Partnership, and Juniper owned 22,548,998 Common Units, representing the remaining 54.2% limited partner interest. During the three months ended March 31, 2023, changes in the ownership interests were the result of share repurchases and issuances of Class A Common Stock in connection with the vesting of employees’ share-based compensation. See Note 12 for information regarding share repurchases and Note 13 for vesting of share-based compensation.

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

Significant Accounting Policies

The Company’s significant accounting policies are described in “Note 3 – Summary of Significant Accounting Policies” of the Notes to Consolidated Financial Statements in its 2022 Annual Report and are supplemented by the notes included in this Quarterly Report on Form 10-Q. The financial statements and related notes included in this report should be read in conjunction with the Company’s 2022 Annual Report.

Recent Accounting Pronouncements

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

Adoption of Recently Issued Accounting Pronouncements

Effective January 1, 2023, we adopted 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. As required, ASU 2021-08 will be applied prospectively to business combinations occurring on or after December 15, 2022. We adopted this update on January 1, 2023 and it did not have a material impact on our financial statements.

Note 3 – Transactions

Pending Baytex Merger

On February 27, 2023, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Baytex Energy Corp. (“Baytex”) pursuant to which, among other things, the Company will merge with and into a wholly-owned subsidiary of Baytex with the Company surviving the merger as a wholly-owned subsidiary of Baytex (the “Baytex Merger”). Subject to the terms and conditions of the Merger Agreement, each share of our Class A Common Stock issued and outstanding immediately prior to the effective time of the closing of the Baytex Merger (including shares of our Class A Common Stock to be issued in connection with the exchange of the Class B Common Stock and Common Units for Class A Common Stock), will be converted automatically into the right to receive: (i) 7.49 Baytex common shares and (ii) $13.31 in cash. The transaction was unanimously approved by the board of directors of each company and JSTX and Rocky Creek delivered a support agreement to vote their outstanding shares in favor of the Baytex Merger. The Baytex Merger is expected to close in late second quarter or early third quarter of 2023, subject to the satisfaction of customary closing conditions, including the requisite shareholder and regulatory approvals.

Note 4 – Revenue Recognition

Revenue from Contracts with Customers

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

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

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

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

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

Accounts Receivable from Contracts with Customers

Our accounts receivable consists mainly of trade receivables from commodity sales and joint interest billings due from partners on properties we operate. Our allowance for credit losses is entirely attributable to receivables from joint interest partners. We generally have the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, our oil, natural gas, and NGL receivables are collected within 30 to 60 days. The following table summarizes our accounts receivable by type as of the dates presented:


	March 31, 2023		December 31, 2022
Customers	$	111,726	$	109,149
Joint interest partners	26,501		30,730
Derivative settlements from counterparties 1	732		437
Other	132		114
Total	139,091		140,430
Less: Allowance for credit losses	(545)		(715)
Accounts receivable, net of allowance for credit losses	$	138,546	$	139,715

_______________________

1 See Note 5 for information regarding our derivative instruments.

Note 5 – Derivative Instruments

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

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

Commodity Derivatives 1

The following table sets forth our commodity derivative positions, presented on a net basis by period of maturity, as of March 31, 2023:


	2Q2023		3Q2023		4Q2023		1Q2024		2Q2024
NYMEX WTI Crude Swaps
Average Volume Per Day (bbl)	2,400		2,807		2,657		462		462
Weighted Average Swap Price ($/bbl)	$	54.26	$	54.92	$	54.93	$	58.75	$	58.75
NYMEX WTI Crude Collars
Average Volume Per Day (bbl)	23,214		16,304		8,967
Weighted Average Purchased Put Price ($/bbl)	$	67.81	$	72.50	$	72.27
Weighted Average Sold Call Price ($/bbl)	$	78.89	$	88.35	$	87.57






MEH WTI CMA Crude Differential Swaps
Average Volume Per Day (bbl)	13,187
Weighted Average Swap Price ($/bbl)	$	2.03
NYMEX HH Swaps
Average Volume Per Day (MMBtu)	7,500
Weighted Average Swap Price ($/MMBtu)	$	3.690
NYMEX HH Collars
Average Volume Per Day (MMBtu)	11,538		11,413		11,413		11,538		11,538
Weighted Average Purchased Put Price ($/MMBtu)	$	2.500	$	2.500	$	2.500	$	2.500	$	2.328
Weighted Average Sold Call Price ($/MMBtu)	$	2.682	$	2.682	$	2.682	$	3.650	$	3.000
HSC Basis Swaps
Average Volume Per Day (MMBtu)	19,038		11,413		11,413
HSC Basis Average Fixed Price ($/MMBtu)	$	(0.153)	$	(0.153)	$	(0.153)
HSC Index Swap
Average Volume Per Day (MMBtu)	6,319
HSC Index Average Fixed Price ($/MMBtu)	$	(0.045)
OPIS Mt. Belvieu Ethane Swaps
Average Volume per Day (gal)	98,901		34,239		34,239		34,615
Weighted Average Fixed Price ($/gal)	$	0.2288	$	0.2275	$	0.2275	$	0.2275

_______________________

1 NYMEX WTI refers to New York Mercantile Exchange West Texas Intermediate and MEH refers to Magellan East Houston that serve as benchmarks for crude oil. NYMEX HH refers to NYMEX Henry Hub that serves as the benchmark for natural gas. HSC refers to Houston Ship Channel that serves as another benchmark for natural gas. OPIS Mt. Belvieu refers to Oil Price Information Service Mt. Belvieu that serves as the benchmark for ethane which represents a commodity proxy for NGLs.

Interest Rate Derivatives

Through May 2022, we had a series of interest rate swap contracts (the “Interest Rate Swaps”) establishing fixed interest rates on a portion of our variable interest rate indebtedness. The notional amount of the Interest Rate Swaps totaled $300 million, with us paying a weighted average fixed rate of 1.36% on the notional amount, and the counterparties paying a variable rate equal to LIBOR. As of March 31, 2023, we did not have any interest rate derivatives.

Financial Statement Impact of Derivatives

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

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


	Three Months Ended March 31,
	2023		2022
Interest rate swap gains recognized in the condensed consolidated statements of operations	$	—	$	83
Commodity gains (losses) recognized in the condensed consolidated statements of operations	25,658		(167,970)
	$	25,658	$	(167,887)

Interest rate cash settlements recognized in the condensed consolidated statements of cash flows	$	—	$	(938)
Commodity cash settlements and premiums paid recognized in the condensed consolidated statements of cash flows	(7,358)		(28,470)
	$	(7,358)	$	(29,408)

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


		Fair Values
		March 31, 2023				December 31, 2022
Type	Balance Sheet Location	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities

Commodity contracts	Derivative assets/liabilities – current	$	23,756	$	32,286	$	29,714	$	67,933

Commodity contracts	Derivative assets/liabilities – non-current	216		1,320		316		3,416
		$	23,972	$	33,606	$	30,030	$	71,349

As of March 31, 2023, we reported net commodity derivative liabilities of $9.6 million. The contracts associated with these positions are with seven counterparties for commodity derivatives, all of which are investment grade financial institutions and are participants in our revolving credit facility (the “Credit Facility”). This concentration may impact our overall credit risk in that these counterparties may be similarly affected by changes in economic or other conditions. Non-performance risk is incorporated by utilizing discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is in a liability position.

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

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

Note 6 – Property and Equipment, Net

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


	March 31, 2023		December 31, 2022
Oil and gas properties (full cost accounting method):
Proved	$	3,163,277	$	3,013,854
Unproved	43,158		41,882
Total oil and gas properties	3,206,435		3,055,736
Other property and equipment 1	31,307		30,969
Total properties and equipment	3,237,742		3,086,705
Accumulated depreciation, depletion, amortization and impairments	(1,362,906)		(1,277,705)
Total property and equipment, net	$	1,874,836	$	1,809,000

_______________________

1 As of March 31, 2023 and December 31, 2022, we had $1.2 million classified as Assets held for sale excluded from above.

Unproved property costs of $43.2 million and $41.9 million have been excluded from amortization as of March 31, 2023 and December 31, 2022, respectively. We transferred $0.9 million and $0.7 million of unproved leasehold costs, including capitalized interest, associated with proved undeveloped reserves, and acreage unlikely to be drilled or expiring acreage, to the full cost pool during the three months ended March 31, 2023 and 2022, respectively. We capitalized internal costs of $1.6 million and $1.4 million and interest of $0.9 million and $1.1 million during the three months ended March 31, 2023 and 2022, respectively, in accordance with our accounting policies. Average depreciation, depletion and amortization per barrel of oil equivalent of proved oil and gas properties was $19.45 and $14.98 for the three months ended March 31, 2023 and 2022, respectively.

Ceiling Test

Throughout 2022 and into 2023, commodity prices remained volatile due to supply disruptions resulting from the Russia-Ukraine war and related sanctions that began in first quarter of 2022 as well as shifts in production levels by the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, “OPEC+”). Beginning with an announcement in April 2022 of production cuts which took effect in November 2022, OPEC+ changed its strategy from one which had seen gradually increasing production throughout most of 2022 to cutting production. Then in April 2023, OPEC+ announced a surprise oil output cut of approximately 1.16 million barrels of oil per day (“MMbbl/d”) bringing the total volume cuts by OPEC+ to over 3.66 MMbbl/d until the end of 2023. During 2022 and through the first quarter of 2023, WTI crude oil and natural gas prices ranged from over $120 per barrel (“bbl”) and over $9 per million British thermal units (“MMBtu”), respectively, to lows of approximately $67 per bbl and under $2 per MMBtu, respectively, due to factors discussed above.

At the end of each quarterly reporting period, the unamortized cost of our oil and gas properties, net of deferred income taxes, is limited to the sum of the estimated after-tax discounted future net revenues from proved properties adjusted for costs excluded from amortization (the “Ceiling Test”). The Ceiling Test utilizes an average of commodity prices based on the closing prices on the first day of each month for the previous 12 months. We did not record any impairments of our oil and gas properties during the three months ended March 31, 2023 or 2022.

Note 7 – Long-Term Debt

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


	March 31, 2023		December 31, 2022
Credit Facility	$	240,000	$	215,000
9.25% Senior Notes due 2026	400,000		400,000

Other	—		238
Total	640,000		615,238
Less: Unamortized discount ¹	(2,878)		(3,055)
Less: Unamortized deferred issuance costs 1, 2	(7,642)		(8,106)


Long-term debt	$	629,480	$	604,077

_______________________

¹ 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.

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

Credit Facility

As of March 31, 2023, the Credit Facility had a $1.0 billion revolving commitment and a $950 million borrowing base with aggregate elected commitments of $500 million, and a $25 million sublimit for the issuance of letters of credit. Availability under the Credit Facility may not exceed the lesser of the aggregate elected commitments or the borrowing base less outstanding advances and letters of credit. The borrowing base under the Credit Facility is redetermined semi-annually, generally in the Spring and Fall of each year. Additionally, we and the Credit Facility lenders may, upon request, initiate a redetermination at any time during the six-month period between scheduled redeterminations. The Credit Facility is available to us for general corporate purposes, including working capital.

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 term Secured Overnight Financing Rate (“SOFR”) reference 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 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. At March 31, 2023, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 7.67%. Unused commitment fees are charged at a rate of 0.50%.

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

The Credit Facility also contains other customary affirmative and negative covenants as well as events of default and remedies. If we do not comply with the financial and other covenants in the Credit Facility, the lenders may, subject to customary cure rights, require immediate payment of all amounts outstanding under the Credit Facility. As of March 31, 2023, we were in compliance with all debt covenants under the Credit Facility.

We had $240.0 million in outstanding borrowings and $1.0 million in outstanding letters of credit under the Credit Facility as of March 31, 2023. Factoring in the outstanding letters of credit, we had $259.0 million of availability under the Credit Facility as of March 31, 2023. During the three months ended March 31, 2022, we incurred and capitalized approximately $0.4 million of issue costs associated with amendments to the Credit Facility. We did not incur any issue costs associated with the Credit Facility during the three months ended March 31, 2023.

9.25% Senior Notes due 2026

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

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

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

As of March 31, 2023, we were in compliance with all debt covenants under the Indenture.

Other Debt

During the three months ended March 31, 2023, we settled $0.2 million of other debt. During the three months ended March 31, 2022, $2.2 million of other debt was extinguished and recorded as a gain on extinguishment of debt.

Note 8 – Income Taxes

The income tax provision resulted in an expense of $1.0 million for the three months ended March 31, 2023. 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 $7.0 million as of March 31, 2023 is also fully attributable to the State of Texas and primarily related to property.

The income tax provision resulted in a benefit of $0.2 million for the three months ended March 31, 2022. The federal portion was fully offset by an adjustment to the valuation allowance against our net deferred tax assets resulting in an effective tax rate of 0.9%, which was fully attributable to the State of Texas.

We had no liability for unrecognized tax benefits as of March 31, 2023 and December 31, 2022. There were no interest and penalty charges recognized during the three months ended March 31, 2023 and 2022. Tax years from 2018 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.

Note 9 – Supplemental Balance Sheet Detail

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


	March 31, 2023		December 31, 2022
Prepaid and other current assets:
Inventories 1	$	16,305	$	19,341
Prepaid expenses 2	2,155		2,923
	$	18,460	$	22,264
Other assets:
Deferred issuance costs of the Credit Facility, net of amortization	$	2,926	$	3,218
Right-of-use assets – operating leases 3	14,197		989

Other	155		213
	$	17,278	$	4,420
Accounts payable and accrued liabilities:
Trade accounts payable	$	50,366	$	58,592
Drilling and other lease operating costs	50,318		62,842
Revenue and royalties payable	101,418		104,512
Production, ad valorem and other taxes	11,764		10,547
Derivative settlements to counterparties	3,074		4,109
Compensation and benefits	3,197		6,927
Interest	5,432		14,655
Current operating lease obligations 3	11,043		907
Other	3,180		2,518
	$	239,792	$	265,609
Other non-current liabilities:
Asset retirement obligations	$	8,960	$	8,849
Non-current operating lease obligations 3	3,373		200
Postretirement benefit plan obligations	798		885
	$	13,131	$	9,934

_______________________

1 Includes tubular inventory and well materials of $15.7 million and $18.7 million as of March 31, 2023 and December 31, 2022, respectively, and crude oil volumes in storage of $0.6 million as of both March 31, 2023 and December 31, 2022.

2 The balances as of March 31, 2023 and December 31, 2022 include $0.5 million in each period for the prepayment of drilling and completion materials and services.

3 The balances as of March 31, 2023 primarily relate to an amended drilling rig lease contract.

Note 10 – Fair Value Measurements

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

Our financial instruments, including cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to their short-term maturities. As of March 31, 2023 and December 31, 2022, the carrying values of the borrowings outstanding under our Credit Facility approximate fair value as the borrowings bear interest at variables rates tied to current market rates and the applicable margins represent market rates. The fair value of our fixed rate 9.25% Senior Notes due 2026 is estimated based on the published market prices for issuances of similar risk and tenor and is categorized as Level 2 within the fair value hierarchy. As of March 31, 2023, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $640.0 million and $661.5 million, respectively. As of December 31, 2022, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $615.2 million and $616.4 million, respectively.

Recurring Fair Value Measurements

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


	As of March 31, 2023
	Level 1		Level 2		Level 3		Total
Financial assets:


Commodity derivative assets – current	$	—	$	23,756	$	—	$	23,756
Commodity derivative assets – non-current	—		216		—		216
Total financial assets	$	—	$	23,972	$	—	$	23,972
Financial liabilities:


Commodity derivative liabilities – current	$	—	$	32,286	$	—	$	32,286
Commodity derivative liabilities – non-current	—		1,320		—		1,320
Total financial liabilities	$	—	$	33,606	$	—	$	33,606


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


Commodity derivative assets – current	$	—	$	29,714	$	—	$	29,714
Commodity derivative assets – non-current	—		316		—		316
Total financial assets	$	—	$	30,030	$	—	$	30,030
Financial liabilities:


Commodity derivative liabilities – current	$	—	$	67,933	$	—	$	67,933
Commodity derivative liabilities – non-current	—		3,416		—		3,416
Total financial liabilities	$	—	$	71,349	$	—	$	71,349

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 and MEH crude oil, NYMEX HH natural gas, HSC natural gas and OPIS Mt. Belvieu Ethane natural gas liquids closing prices as of the end of the reporting periods. Each of these is a Level 2 input.

•Interest rate swaps: We determined the fair values of our interest rate swaps using an income approach valuation technique which discounts future cash flows back to a single present value. We estimated the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these was a Level 2 input. All interest rate swaps matured in May 2022, and as of March 31, 2023, we had not entered into any new interest rate derivative instruments.

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

Non-Recurring Fair Value Measurements

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

Note 11 – Commitments and Contingencies

Drilling and Completion Commitments

As of March 31, 2023, we had contracts for two drilling rigs with remaining terms of less than two years.

Gathering and Intermediate Transportation Commitments

We have long-term agreements that provide us with field gathering and intermediate pipeline transportation services for a majority of our crude oil and condensate production in Lavaca and Gonzales Counties, Texas. We also have volume capacity support for certain downstream intrastate pipeline transportation. The following table provides details on these contractual arrangements as of March 31, 2023:

Description of contractual arrangement