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:
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| | | | 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 | | | | | | | | | | | | | | | |
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| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| 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:
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| | | | 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 | | Expiration
of Contractual Arrangement | | Gross Minimum Volume
Commitment (MVC)
(bbl/d) | | Expiration of MVC |
| Field gathering agreement | | February 2041 | | 8,000 | | February 2031 |
| Intermediate pipeline transportation services | | February 2026 | | 8,000 | | February 2026 |
| Volume capacity support | | April 2026 | | 8,000 | | April 2026 |
Each of these arrangements also contain an obligation to deliver the first 20,000 gross barrels of oil per day produced from Gonzales, Lavaca and Fayette Counties, Texas. For certain of our crude oil volumes gathered under the field gathering agreement, our rate includes an adjustment based on NYMEX WTI prices. As crude oil prices increase, up to a cap of $90 per bbl, the gathering rate escalates pursuant to the field gathering agreement.
During the 12-month period ended March 31, 2023 and excluding 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 2023, approximately $13.9 million per year for 2024 through 2025, $7.8 million for 2026, $3.8 million per year for 2027 through 2030 and $0.6 million for 2031.
During the three months ended March 31, 2023 and 2022, we delivered more than the required 20,000 gross barrels of oil per day and recorded total expense of $10.0 million and $10.2 million, respectively, for contractual fees in connection with these arrangements.
Crude Oil Storage
As of March 31, 2023, we had access to up to approximately 180,000 barrels of dedicated tank capacity for no additional charge at the service provider’s CDP facility, in Lavaca County, Texas through February 2041. In addition, we had access for an additional 70,000 barrels of tank capacity at the CDP on a month-to-month basis, which can be terminated by either party with 45 days’ notice to the counterparty. Costs associated with this monthly agreement are in the form of a monthly fixed rate short-term lease and are charged as incurred on a monthly basis to GPT in our condensed consolidated statements of operations.
Other Agreements
We have a long-term dedication of certain specific leases under a crude purchase and throughput terminal agreement through 2032. Under the agreement, we have rights to transfer dedicated oil for delivery to a Gulf coast terminal in Point Comfort, Texas or oil may be transferred at alternate locations to third parties with a terminal fee.
We have agreements that provide us with field gathering, compression and short-haul transportation services for our natural gas production and gas lift for our hydrocarbon production under various terms through 2039.
We also have agreements that provide us with services to process our wet gas production into NGL products and dry, or residue, gas. Several agreements covering the majority of our wet gas production extend beyond three years, including one agreement that extends into 2029.
Legal, Environmental Compliance and Other
We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. As of March 31, 2023 and December 31, 2022, we had an estimated reserve of approximately $0.1 million for certain claims made against us regarding previously divested operations included in Accounts payable and accrued liabilities on our condensed consolidated balance sheets.
As of March 31, 2023 and December 31, 2022, we had AROs of approximately $9.0 million and $8.8 million, respectively, attributable to the plugging of abandoned wells.
Additionally, we have entered into certain contractual arrangements for other products and services and have commitments under information technology licensing and service agreements, among others.
Note 12 – Shareholders’ Equity
Capital Stock
As of March 31, 2023, the Company had two classes of common stock: Class A Common Stock and Class B Common Stock. The holders of record of Class A Common Stock and Class B Common Stock vote together as a single class on all matters on which holders of Class A Common Stock and Class B Common Stock are entitled to vote; except that certain directors are elected by holders of a majority of the shares of Class B Common Stock voting as a separate class.
The holders of Class A Common Stock have no preemptive rights to purchase shares of Class A Common Stock. Shares of Class A Common Stock are not subject to any redemption or sinking fund provisions and are not convertible into any of the Company’s other securities. In the event of the Company’s voluntary or involuntary liquidation, dissolution or winding up, holders of Class A Common Stock will share equally in the assets remaining after it pays its creditors and preferred shareholders. Holders of Class A Common Stock are entitled to receive dividends when and if declared by the Board of Directors.
Shares of Class B Common Stock are non-economic interests in the Company, and no dividends can be declared or paid on the Class B Common Stock. The holders of Class B Common Stock have no preemptive rights to purchase shares of Class B Common Stock. Shares of Class B common stock are not subject to any redemption or sinking fund provisions. In the event of the Company’s voluntary or involuntary liquidation, dissolution or winding up, after payment or provision for payment of its debts and other liabilities, the holders of Class B Common Stock will be entitled to receive, out of its assets or proceeds thereof available for distribution to our shareholders, before any distribution of such assets or proceeds is made to or set aside for the holders of Class A Common Stock and any other of the Company’s stock ranking junior to the Class B Common Stock as to such distribution, payment in full in an amount equal to $0.01 per share of Class B Common Stock. With the exception of the aforementioned distribution, the holders of shares of Class B Common Stock will not be entitled to receive any of the Company’s assets in the event of its voluntary or involuntary liquidation, dissolution or winding up.
The Company’s Class B Common Stock is not convertible into any of the Company’s other securities. However, if a holder exchanges one common unit of the Partnership for one share of the Company’s Class A Common Stock, it must also surrender to the Company a share of its Class B Common Stock for each common unit exchanged.
As of March 31, 2023, the Company had (i) 110,000,000 authorized shares of Class A Common Stock and 18,982,425 shares of Class A Common Stock issued and outstanding, (ii) 30,000,000 authorized shares of Class B Common Stock and 22,548,998 shares of Class B Common Stock issued and outstanding, and (iii) 5,000,000 authorized shares of preferred stock, par value $0.01 per share, and no shares of preferred stock issued or outstanding.
Dividends
On March 3, 2023, the Company’s Board of Directors declared a cash dividend of $0.075 per share of Class A Common Stock. The dividend was paid on March 30, 2023 to holders of record of Class A Common Stock as of the close of business on March 17, 2023. In connection with any dividend, Ranger’s operating subsidiary will also make a corresponding distribution to its common unitholders. During the first quarter of 2023, the dividend to the holders of our Class A Common Stock and distribution to common unitholders totaled $3.1 million in the aggregate. The Company’s Credit Facility and the Indenture have restrictive covenants that limit its ability to pay dividends. See Note 15 for details on dividends declared subsequent to March 31, 2023.
Share Repurchase Program
On April 13, 2022, our Board of Directors approved a share repurchase program that authorized the Company to repurchase up to $100 million of its outstanding Class A Common Stock. The share repurchase authorization was effective immediately and was valid through March 31, 2023. On July 7, 2022, the Board of Directors authorized an increase in the share repurchase program from $100 million to $140 million and extended the term of the program through June 30, 2023. We do not intend to repurchase additional shares pending closing of the Baytex Merger.
During the three months ended March 31, 2023, we repurchased 121,857 shares of our Class A Common Stock at a total cost of $4.8 million and an average purchase price of $39.52. The share repurchases were recorded to Class A common stock and Paid-in capital on our condensed consolidated balance sheets. As of March 31, 2023, the remaining authorized repurchase amount under the share repurchase program was $60.0 million.
On August 16, 2022, the Inflation Reduction Act was signed into law and imposes a 1% excise tax on the repurchase of stock by publicly traded U.S. corporations. The excise tax is effective for stock repurchases after December 31, 2022. Based on the total share repurchases during the three months ended March 31, 2023, we recognized less than $0.1 million of additional cost within Paid-in capital associated with the excise tax for these share repurchases.
Change in Ownership of Consolidated Subsidiaries
The following table summarizes changes in the ownership interest in consolidated subsidiaries during the periods presented:
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2023 | | 2022 | | | | |
| Net income (loss) attributable to Class A common shareholders | $ | 51,999 | | | $ | (9,985) | | | | | |
Transfers from the noncontrolling interest, net 1 | 978 | | | N/A | | | | |
| Change from Net income (loss) attributable to Class A common shareholders and net transfers from Noncontrolling interest | $ | 52,977 | | | $ | (9,985) | | | | | |
_____________________________________________
1 The three months ended March 31, 2023 includes a net transfer of $1.0 million from Noncontrolling interest for share repurchases and common stock issuances related to employees’ share-based compensation with a corresponding adjustment to Paid-in capital. This equity adjustment had no impact on earnings other than a resulting increase to the noncontrolling interest proportionate share of net income and a corresponding decrease to the proportionate share of net income attributable to Class A common shareholders.
As discussed above and in Note 13, in the three months ended March 31, 2023, we repurchased shares of our Class A Common Stock and issued shares of our Class A Common Stock related to the vesting of employees’ share-based compensation resulting in a change in the proportionate share of Common Units held by the Company relative to Juniper. As such, we recognized an adjustment to the carrying amount of noncontrolling interest and a corresponding adjustment to Class A common shareholders’ equity of $1.0 million for the three months ended March 31, 2023 to reflect the revised ownership percentage of total equity. See Note 2 for further discussion.
Note 13 – Share-Based Compensation and Other Benefit Plans
Share-Based Compensation
We reserved 4,424,600 shares of Class A Common Stock for issuance under the Ranger Oil Management Incentive Plan for share-based compensation awards. A total of 820,651 RSUs and 664,414 PRSUs have been granted to employees and directors through March 31, 2023.
We recognized expense attributable to the RSUs and PRSUs of $2.1 million and $0.9 million for the three months ended March 31, 2023 and 2022, respectively. We recognize share-based compensation expense as a component of general and administrative (“G&A”) expenses in our condensed consolidated statements of operations.
Time-Vested Restricted Stock Units
The table below summarizes activity for the three months ended March 31, 2023 with respect to awarded RSUs:
| | | | | | | | | | | |
| Time-Vested
Restricted Stock
Units | | Weighted-Average
Grant Date
Fair Value |
Balance at January 1, 2023 | 149,871 | | | $ | 17.51 | |
| Granted | 9,078 | | | $ | 38.68 | |
| Vested | (43,015) | | | $ | 4.72 | |
| Forfeited | (1,176) | | | $ | 42.81 | |
Balance at March 31, 2023 | 114,758 | | | $ | 23.72 | |
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 March 31, 2023, we had $1.6 million of unrecognized compensation cost attributable to RSUs. We expect that cost to be recognized over a weighted-average period of 1.49 years.
Performance-Based Restricted Stock Units
The table below summarizes activity for the three months ended March 31, 2023 with respect to awarded PRSUs:
| | | | | | | | | | | |
| Performance Restricted Stock
Units | | Weighted-Average
Grant Date
Fair Value |
Balance at January 1, 2023 | 440,100 | | | $ | 29.87 | |
| Granted | — | | | $ | — | |
| Vested | — | | | $ | — | |
| Forfeited | (1,177) | | | $ | 58.87 | |
Balance at March 31, 2023 | 438,923 | | | $ | 29.87 | |
Compensation expense for PRSUs with a market condition is being amortized ratably over three years for the 2022 and 2021 grants. For the 2020 and 2019 grants, compensation expense for the PRSUs with a market condition were amortized on a graded-vesting basis. The applicable period for the amortization of compensation ranges from less than one year to three years. Compensation expense for PRSUs with a performance condition is recognized ratably over three years when it is considered probable that the performance condition will be achieved and such grants are expected to vest. PRSUs with a market condition do not allow for the reversal of previously recognized expense, even if the market condition is not achieved and no shares ultimately vest.
The 2022 and 2021 PRSU grants contain performance measures of which 50% are based on the Company’s return on average capital employed (“ROCE”) relative to a defined peer group and 50% are based on the Company’s absolute total shareholder return and total shareholder return (“TSR”) relative to a defined peer group over the three-year performance period. The 2022 and 2021 PRSUs cliff vest from 0% to 200% of the original grant at the end of a three-year performance period based on satisfaction of the respective underlying conditions.
PRSUs granted in 2020 and 2019 vested at 92% of the original grant based on TSR relative to a defined peer group over the three-year performance period. As TSR is deemed a market condition, the grant-date fair value for the 2019, 2020 and a portion of the 2021 and 2022 PRSU grants was derived by using a Monte Carlo model. The table below presents ranges for the assumptions used in the Monte Carlo model for the PRSUs granted in the following periods:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2022 | | 2021 1 | | 2020 1 | | 2019 |
| | | | | | | | |
| Expected volatility | | 134.98% to 138.75% | | 131.74% to 134.74% | | 101.32% to 117.71% | | 49.9 | % |
| Dividend yield | | 0.0 | % | | 0.0 | % | | 0.0 | % | | 0.0 | % |
| Risk-free interest rate | | 2.59 | % | | 0.22% to 0.29% | | 0.18% to 0.51% | | 1.66 | % |
| Performance period | | 2022-2024 | | 2021-2023 | | 2020-2022 | | 2020-2022 |
_______________________
1 One executive officer’s inducement award originally granted in August 2020 was amended in April 2021 to conform vesting conditions to other PRSU awards granted in 2021. The Monte Carlo assumptions for both years are included above.
As of March 31, 2023, we had $6.5 million of unrecognized compensation cost attributable to PRSUs. We expect that cost to be recognized over a weighted-average period of 1.49 years.
Other Benefit Plans
We maintain the Ranger Oil Corporation and Affiliated Companies Employees 401(k) Plan (the “401(k) Plan”), a defined contribution plan, which covers substantially all of our employees. We recognized expense attributable to the 401(k) Plan of $0.3 million for the three months ended March 31, 2023 and $0.2 million for the three months ended March 31, 2022. The charges for the 401(k) Plan are included as a component of G&A expenses in our condensed consolidated statements of operations.
We maintain unqualified legacy defined benefit pension and defined benefit postretirement plans that cover a limited number of former employees that 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 months ended March 31, 2023 and 2022, and is included as a component of Other, net in our condensed consolidated statements of operations.
Note 14 – Earnings Per Share
Basic net earnings (loss) per share is calculated by dividing the net income (loss) available to Class A common shareholders, excluding net income or loss attributable to Noncontrolling interest, by the weighted average common shares outstanding for the period.
In computing diluted earnings (loss) per share, basic net earnings (loss) per share is adjusted based on the assumption that dilutive RSUs and PRSUs have vested and outstanding Common Units (and shares of Class B Common Stock) held by the Noncontrolling interest in the Partnership are exchanged for common shares. Accordingly, our reported net income (loss) attributable to Class A common shareholders is adjusted due to the elimination of the Noncontrolling interest assuming exchange of the Common Units (and shares of Class B Common Stock) 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, | | |
| | 2023 | | 2022 | | | | |
| Numerator: | | | | | | | |
| 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 for Basic EPS | 51,999 | | | (9,985) | | | | | |
| | | | | | | |
| Adjustment for assumed conversions and elimination of Noncontrolling interest net income (loss) | 429 | | | (10,676) | | | | | |
| Net income (loss) attributable to Class A common shareholders for Diluted EPS | $ | 52,428 | | | $ | (20,661) | | | | | |
| | | | | | | |
| Denominator: | | | | | | | |
| Weighted average shares outstanding used in Basic EPS | 18,975 | | | 21,107 | | | | | |
| Effect of dilutive securities: | | | | | | | |
Common Units and Class B Common Stock that are exchangeable for Class A Common Stock 1 | — | | | — | | | | | |
RSUs and PRSUs 1 | 648 | | | — | | | | | |
Weighted average shares outstanding used in Diluted EPS 1 | 19,623 | | | 21,107 | | | | | |
_______________________
1 For the three months ended March 31, 2023 and 2022, approximately 22.5 million potentially dilutive Common Units (and the associated 22.5 million Class B Common Stock) had the effect of being anti-dilutive and were excluded from the calculation of earnings per share. For the three months ended March 31, 2022, 0.6 million of RSUs and PRSUs had the effect of being anti-dilutive and were excluded from the calculation of earnings per share.
Note 15 – Subsequent Events
Dividends
On May 5, 2023, the Company’s Board of Directors declared a cash dividend of $0.075 per share of Class A Common Stock, payable on May 30, 2023 to holders of record of Class A Common Stock as of the close of business on May 22, 2023.
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, (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 and uncertainty related to our announced merger (the “Baytex Merger”) with Baytex Energy Corp. (“Baytex”), including the risk that the conditions to the closing of the transaction are not satisfied and the additional risks discussed in Part I, Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2022;
•risks related to completed acquisitions, including the risk that the benefits of the acquisitions may not be fully realized or may take longer to realize than expected, and that management attention will be diverted to integration-related issues;
•the sustained market uncertainty with respect to, and volatility of commodity prices for, crude oil, natural gas liquids (“NGLs”), and natural gas;
•general economic conditions, including as a result of governmental actions to address elevated inflation levels caused by labor shortages, supply shortages and increased demand, and other inflationary pressures;
•the impact of world health events, economic slowdown, governmental actions, stay-at-home orders and interruptions to our operations or our customer’s operations;
•our ability to satisfy our short-term and long-term liquidity needs, including our ability to generate sufficient cash flows from operations or to obtain adequate financing on favorable terms, including access to the capital markets, to fund our capital expenditures and meet working capital needs;
•our ability to access capital, including through lending arrangements and the capital markets, as and when desired;
•negative events or publicity adversely affecting our ability to maintain our relationships with our suppliers, service providers, customers, employees, and other third parties;
•plans, objectives, expectations and intentions contained in this report that are not historical;
•our ability to execute our business plan in volatile commodity price environments;
•our ability to develop, explore for, acquire and replace oil and gas reserves and sustain production;
•changes to our drilling and development program;
•our ability to generate profits or achieve targeted reserves in our development operations;
•our ability to meet guidance, market expectations and internal projections, including type curves;
•any impairments, write-downs or write-offs of our reserves or assets;
•the projected demand for and supply of oil, NGLs and natural gas;
•our ability to contract for drilling rigs, frac crews, materials, supplies and services at reasonable costs;
•our ability to declare dividends;
•our ability to renew or replace expiring contracts on acceptable terms;
•our ability to obtain adequate pipeline transportation capacity or other transportation for our oil and gas production at reasonable cost and to sell our production at, or at reasonable discounts to, market prices;
•the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from that estimated in our proved oil and gas reserves;
•use of new techniques in our development, including choke management and longer laterals;
•drilling, completion and operating risks, including adverse impacts associated with well spacing and a high concentration of activity;
•our ability to compete effectively against other oil and gas companies;
•leasehold terms expiring before production can be established and our ability to replace expired leases;
•environmental obligations, costs and liabilities that are not covered by an effective indemnity or insurance;
•the timing of receipt of necessary regulatory permits;
•the effect of commodity and financial derivative arrangements with other parties and counterparty risk related to the ability of these parties to meet their future obligations;
•the occurrence of unusual weather or operating conditions, including force majeure events;
•our ability to retain or attract senior management and key employees;
•our reliance on a limited number of customers and a particular region for substantially all of our revenues and production;
•compliance with and changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters;
•physical, electronic and cybersecurity breaches;
•uncertainties and economic events relating to general domestic and international economic and political conditions, including 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, 2022.
Additional information concerning these and other factors can be found in our press releases and public filings with the SEC. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable law.