Exhibit 99.1

BAYTEX ENERGY CORP.

business acquisition report

JUNE 27, 2023

BAYTEX ENERGY CORP.

FORM 51-102F4
BUSINESS ACQUISITION REPORT

Item 1 Identity of Company

1.1 Name and Address of Company

Baytex Energy Corp. ("Baytex") is a corporation existing under the Business Corporations Act (Alberta). The head and principal office of Baytex is located at Suite 2800, Centennial Place, East Tower, 520 – 3rd Avenue S.W., Calgary, Alberta, Canada, T2P 0R3 and its registered office is located at 2400, 525 – 8th Avenue S.W., Calgary, Alberta, Canada, T2P 1G1.

1.2 Executive Officer

James R. Maclean, Chief Legal Officer and Corporate Secretary of Baytex is knowledgeable about the significant acquisition and this Business Acquisition Report and his business telephone number is 587-952-3273.

Item 2 Details of Acquisition

2.1 Nature of Business Acquired

On June 20, 2023, Baytex completed the acquisition of Ranger Oil Corporation ("Ranger") pursuant to an agreement and plan of merger dated February 27, 2023, as amended by a joinder agreement dated May 3, 2023, among Baytex, Ranger and Nebula Merger Sub, LLC ("Merger Sub") a Delaware limited liability company that, prior to the Merger (as defined below), was an indirect wholly owned subsidiary of Baytex (collectively and as amended, the "Merger Agreement"). Pursuant to the Merger Agreement, Merger Sub merged with and into Ranger, with Ranger continuing its existence as the surviving corporation following the Merger as an indirect wholly owned subsidiary of Baytex (the "Merger"). Following completion of the Merger, Ranger, as the surviving corporation, was merged with a subsidiary of Baytex and ceased to exist as a separate entity. References in this Business Acquisition Report to 'Ranger' refer to Ranger prior to completion of the Merger. A copy of the Merger Agreement was filed and is available on Baytex's issuer profile on SEDAR at www.sedar.com and was furnished on EDGAR. The Merger is also described in further detail in Baytex's information circular and proxy statement dated April 3, 2023 (the "Information Circular"), which is available on Baytex's issuer profile on SEDAR at www.sedar.com and in Baytex’s registration statement on Form F-4 which was declared effective by the U.S. Securities Exchange Commission (the "Registration Statement"). The Information Circular and Registration Statement do not form part of, and are not incorporated by reference in, this Business Acquisition Report.

Ranger is an oil and gas company based in Houston, Texas, focused on the onshore development and production of crude oil, natural gas liquids, and natural gas in the Eagle Ford Shale in South Texas. Prior to completion of the Merger, Ranger's Class A common stock (the "Ranger Class A Common Stock") was listed and traded on the Nasdaq Stock Market (the "NASDAQ") under the ticker symbol "ROCC." The Ranger Class A Common Stock was delisted from the NASDAQ on June 20, 2023 in connection with the Merger. Further information regarding the business of Ranger can be found in its Annual Report on Form 10-K for the year ended December 31, 2022 (the "Ranger Annual Report"), which is available on Baytex's issuer profile on SEDAR at www.sedar.com and was filed by Ranger on EDGAR. The Ranger Annual Report does not form part of, and is not incorporated by reference in, this Business Acquisition Report. For information with respect to the reserves acquired by Baytex pursuant to the Merger, see Exhibit 1 to this Business Acquisition Report. See also: (i) the audited consolidated financial statements of Ranger for the years ended December 31, 2022, 2021 and 2020 together with the notes thereto and the auditor's report thereon attached to this Business Acquisition Report as Exhibit 2 (the "Ranger Annual Financial Statements"); and (ii) the unaudited condensed consolidated interim financial statements of Ranger as at and for the three-month periods ended March 31, 2023 and 2022, together with the notes thereto attached to this Business Acquisition Report as Exhibit 3 (the "Ranger Interim Financial Statements").

2

2.2 Date of Acquisition

The Merger was completed on June 20, 2023.

2.3 Consideration

Merger Consideration

Pursuant to the Merger Agreement, Ranger shareholders received 7.49 common shares of Baytex (the "Baytex Shares") plus US$13.31 cash, for each share of Ranger Class A Common Stock held immediately prior to the effective time (being such time as the Virginia State Corporation Commission issued the certificate of merger) (the "Effective Time"), other than certain excluded shares as described in the Merger Agreement. The total consideration paid by Baytex in connection with the Merger, including the assumption of net debt, was approximately US$2.2 billion (C$2.9 billion), consisting of an aggregate of 311,369,607 Baytex Shares and US$553,150,370.51 in cash.

Additionally, pursuant to the Merger Agreement, each award issued pursuant to Ranger's 2019 Management Incentive Plan or any inducement award agreement (collectively, the "Ranger Equity Plan") of: (i) restricted stock units subject to time-based vesting (the "Ranger TRSU Awards"), other than any Ranger TRSU Awards held by Ranger's non-employee directors (the "Ranger Director TRSU Awards"); and (ii) restricted stock units subject to performance-based vesting (the "Ranger PBRSU Awards" and collectively with the Ranger TRSU Awards (other than Ranger Director TRSU Awards), the "Ranger Convertible Awards"), in each case, that was outstanding immediately prior to the Effective Time, was converted into time-vested awards with respect to Baytex Shares (the "Converted Baytex TRSU Awards") at closing of the Merger and the other transactions contemplated by the Merger Agreement ("Closing"). Any dividend equivalents that were accrued with respect to Ranger Convertible Awards will become payable ratably if and when such underlying Converted Baytex TRSU Award vests. Each Ranger Director TRSU Award vested in full at the Effective Time and, by virtue of the occurrence of Closing, was cancelled and converted into the right to receive, at the Effective Time, without interest, the consideration with respect to each share of Ranger Class A Common Stock subject to such Ranger Director TRSU Award plus the amount of any dividend equivalents payable with respect to such Ranger Director TRSU Award that remained unpaid as of the Effective Time.

Note Offering and Merger Financing

In connection with the completion of the Merger, Baytex entered into new credit facilities with Canadian Imperial Bank of Commerce, Royal Bank of Canada and The Bank of Nova Scotia comprised of a US$1.1 billion revolving credit facility and a US$150 million term loan (collectively, the "Baytex credit facilities").

On April 27, 2023, Baytex completed the offering (the "Notes Offering") of US$800 million aggregate principal amount of senior unsecured notes due 2030 (the "Notes"). The Notes bear interest at a rate of 8.5% per annum and mature on April 30, 2030. The Notes were priced at 98.709% of par to yield 8.75% per annum. On closing of the Notes Offering, the gross proceeds were deposited into escrow pending satisfaction of certain escrow release conditions, including the consummation of the Merger. Such proceeds were released from escrow on Closing. Net proceeds from the Notes Offering, together with portions of borrowings under the Baytex credit facilities, were used to, inter alia, fund the cash portion of the consideration for the Merger, repay certain outstanding indebtedness of Ranger and pay fees and expenses in connection with the Merger.

2.4 Effect on Financial Position

There are presently no plans or proposals for material changes in Baytex's business affairs or the affairs of Ranger which may have a significant effect on the financial performance and financial position of Baytex. Pursuant to the Merger Agreement, Merger Sub merged with and into Ranger, with Ranger continuing its existence as the surviving corporation immediately following the Merger as an indirect wholly owned subsidiary of Baytex. The effect of the Merger on Baytex's financial performance and financial position is outlined in the financial statements (including pro forma financial statements) included in this Business Acquisition Report. See "Item 3 – Financial Statements" below.

3

In connection with the Merger, Baytex has announced the intention to increase share buybacks and introduce a quarterly dividend that is currently expected to be in the amount of $0.0225 per share ($0.09 per share annualized). Subject to approval of the board of directors of Baytex and satisfaction of the solvency tests imposed on Baytex under applicable corporate law, the initial dividend is expected to be paid in October 2023.

Effective on Closing, Jeffrey E. Wojahn and Tiffany Thom Cepak, each being prior members of Ranger's board of directors, were appointed to the board of directors of Baytex. In addition, Julia Gwaltney, former Senior Vice President and Chief Operating Officer of Ranger, was appointed as the Senior Vice President and General Manager, U.S. Eagle Ford Operations, of Baytex and Kayla Baird, former Vice President, Chief Accounting Officer and Controller of Ranger was appointed as the Vice President, U.S. Accounting and Corporate Services of Baytex.

2.5 Prior Valuations

Baytex was not required by securities legislation or a Canadian stock exchange to obtain a valuation opinion with respect to the Merger within the 12 months preceding the date of the Merger.

2.6 Parties to Transaction

The Merger did not involve an "informed person", "associate" or "affiliate" (as each term is defined in securities legislation) of Baytex.

2.7 Date of Report

The date of this Business Acquisition Report is June 27, 2023.

Item 3 Financial Statements

The Ranger Annual Financial Statements are attached as Exhibit 2 to this Business Acquisition Report.

The Ranger Interim Financial Statements are attached as Exhibit 3 to this Business Acquisition Report.

The unaudited pro forma consolidated financial statements of Baytex as at and for the three-month period ended March 31, 2023 and as at and for the year-ended December 31, 2022 after giving effect to the Merger, together with the notes thereto are attached as Exhibit 4 to this Business Acquisition Report (the "Pro Forma Financial Statements").

4

ADVISORIES

Pro Forma Financial Statements Advisory

The Pro Forma Financial Statements are not necessarily indicative of either the results of operations that would have occurred in the year ended December 31, 2022 and the three-month period ended March 31, 2023 had the Merger been effective January 1, 2022 or the results of operations in future years. The actual adjustments may differ from those reflected in such Pro Forma Financial Statements and such differences may be material.

The Pro Forma Financial Statements combine the historical financial information of Baytex and Ranger using the information from Baytex's and Ranger's unaudited historical interim financial statements as of the three-month period ended March 31, 2023 and the audited historical financial statements as of and for the year ended December 31, 2022. The Baytex unaudited historical interim financial statements as of the three-month period ended March 31, 2023 and the Baytex audited historical financial statements as of and for the year ended December 31, 2022, were prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board ("IFRS") and are presented in Canadian dollars ("CAD"). The Ranger unaudited historical interim financial statements as of the three-month period ended March 31, 2023 and the Ranger audited historical financial statements as of and for the year ended December 31, 2022 were prepared in accordance with generally accepted accounting principles in the United States and are presented in U.S. dollars. The Pro Forma Financial Statements are presented in CAD and in accordance with IFRS.

Forward-Looking Information Advisory

Certain statements and other information in this Business Acquisition Report are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities laws (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. No assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this Business Acquisition Report should not be unduly relied upon. These statements speak only as of the date of this Business Acquisition Report.

In particular and without limitation, this Business Acquisition Report contains forward-looking statements pertaining to Baytex's intention to institute a dividend and increase share buybacks, including the anticipated introduction of a quarterly dividend and the expected amount and timing of such. Additionally, statements relating to "reserves" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future.

5

Forward-looking statements are subject to risks, uncertainties and assumptions, including those discussed below and elsewhere in this Business Acquisition Report. Although Baytex believes that the expectations represented in such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Some of the risks which could affect future results and could cause results to differ materially from those expressed in the forward-looking statements contained herein include the following:

· Baytex may fail to realize the anticipated benefits of the Merger;

· the success of integration plans and the time it takes to implement such integration plans;

· changes in business strategies, plans and objectives;

· changes in intentions of allocating annual free cash flow to shareholder returns through dividends, share buybacks and debt reduction;

· Baytex’s goal of building value by developing assets and completing selective acquisitions;

· risks relating to any unforeseen liabilities of Ranger and/or Baytex;

· declines in oil or natural gas prices;

· the level of success in exploration, development and production activities;

· adverse weather conditions that may negatively impact development or production activities;

· the timing and costs of exploration and development expenditures;

· inaccuracies of reserve estimates or assumptions underlying them;

· revisions to reserve estimates as a result of changes in commodity prices;

· impacts to financial statements as a result of impairment write-downs;

· general fluctuations in stock markets;

· the ability to generate cash flows that, along with cash on hand, will be sufficient to support operations, shareholder returns and cash requirements;

· currency exchange rates and regulations;

· actions by joint venture co-owners;

· hedging decisions, including whether or not to enter into derivative financial instruments;

· international, federal, state and provincial initiatives relating to the regulation of hydraulic fracturing;

· failure of assets to yield oil or gas in commercially viable quantities;

· uninsured or underinsured losses resulting from oil and gas operations;

· inability to access oil and gas markets due to market conditions or operational impediments;

· general economic conditions in Canada and globally;

· interest rate fluctuations and inflation rate fluctuations;

· the impact and costs of compliance with laws and regulations governing oil and gas operations;

· the ability to replace oil and natural gas reserves;

· any loss of senior management or technical personnel;

· competition in the oil and gas industry; and

· the risk that the Merger may not increase Baytex's relevance to investors in the international exploration and production industry, increase capital market access through scale and diversification or provide liquidity benefits for stockholders.

6

With respect to forward-looking statements contained in this Business Acquisition Report, Baytex has made assumptions regarding, among other things: the effects of the Merger on Baytex and Ranger; commodity prices, differentials and royalty regimes; timing of production curtailments; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; availability of transportation; the impact of increasing competition; conditions in general economic and financial markets; access to capital; availability of drilling and related equipment; effects of regulation by governmental agencies; royalty rates; and future operating costs.

The above summary of assumptions and risks related to forward-looking statements has been included in this Business Acquisition Report in order to provide investors with a more complete perspective of the Merger and the current and future operations of Baytex and such information may not be appropriate for other purposes.

Readers are cautioned that the foregoing lists of factors are not exhaustive and are made as of the date hereof. The forward-looking statements contained in this Business Acquisition Report are expressly qualified by this cautionary statement. Except as required by law, Baytex does not undertake any obligation to publicly update or revise any forward-looking statements. Readers should also carefully consider the matters discussed under the heading "Risk Factors" in the Information Circular, the Registration Statement and the documents incorporated by reference in the Information Circular and the Registration Statement, including Appendix F – Information Concerning Baytex Energy Corp., Appendix I – Information Concerning Ranger Oil Corporation and the annual information form of Baytex in respect of the year ended December 31, 2022 dated February 23, 2023 (the "Baytex AIF"), which is incorporated by reference in the Information Circular. The Information Circular and the Baytex AIF do not form part of, and are not incorporated by reference in, this Business Acquisition Report.

The future acquisition by Baytex of the Baytex Shares pursuant to a share buyback program, if any, and the level thereof is uncertain. Any decision to acquire Baytex Shares will be subject to the discretion of the board of directors of Baytex and may depend on a variety of factors, including, without limitation, Baytex's business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions, satisfaction of the solvency tests imposed on Baytex under applicable corporate law and receipt of regulatory approvals. There can be no assurance that Baytex will buyback any Baytex Shares in the future.

Dividend Advisory

Baytex's future shareholder distributions, including but not limited to the payment of dividends, if any, and the level thereof is uncertain. Any decision to pay dividends on the Baytex Shares (including the actual amount, the declaration date, the record date and the payment date in connection therewith and any special dividends) will be subject to the discretion of the board of directors of Baytex and may depend on a variety of factors, including, without limitation, Baytex's business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions and satisfaction of the solvency tests imposed on Baytex under applicable corporate law. Further, the actual amount, the declaration date, the record date and the payment date of any dividend are subject to the discretion of the board of directors of Baytex. There can be no assurance that Baytex will pay dividends in the future.

Advisory Regarding Oil and Gas Information

The reserves data in respect of Ranger contained in this Business Acquisition Report has been extracted from the report entitled Evaluation of Ranger Oil Corporation's Petroleum Reserves Based on Forecast Prices and Costs as of December 31, 2022, dated February 24, 2023 (the "McDaniel Ranger Reserves Report"), prepared by McDaniel & Associates Consultants Ltd. ("McDaniel") in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook "COGE Handbook"), which was prepared for use by Baytex in its evaluation of Ranger and for the purpose of making an offer to acquire Ranger. The estimates contained in the McDaniel Ranger Reserves Report differ from the estimates contained in the independent engineering evaluations of Ranger's oil and natural gas reserves prepared by DeGolyer and MacNaughton effective December 31, 2022 (the "Ranger Reserves Report"). The differences are primarily due to differences in Canadian to U.S. reserves disclosure. See "Summary of Significant Canadian to U.S. Reserves Disclosure Differences" contained in this Business Acquisition Report.

7

Listed below are cautionary statements that are specifically required by NI 51-101:

· The terms "boe" and "mcf" may be misleading, particularly if used in isolation. A boe conversion rate of six thousand cubic feet of natural gas per barrel of oil (6 mcf:1 bbl) and an mcf conversion rate of one barrel of oil per six thousand cubic feet of natural gas (1 bbl:6 mcf) are each based on an energy equivalency conversion method primarily applicable at the burner tip and do not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from an energy equivalency of 6:1, utilizing a conversion ratio of 6:1 may be misleading as an indication of value.

· Where any disclosure of reserves data is made in this Business Acquisition Report that does not reflect all reserves of Ranger, the reader should note that estimates of reserves for individual properties or groups of properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.

· The recovery and reserves estimates described herein are estimates only and there is no guarantee that the estimated reserves will be recovered. There are numerous uncertainties inherent in estimating quantities of crude oil, reserves and the future cash flows attributed to such reserves. Actual reserves and future production from such reserves may be greater or less than the estimates provided herein. It should not be assumed that the estimates of future net revenues presented herein represent the fair market value of the reserves.

Certain terms used in this Business Acquisition Report are defined below. Certain other terms used herein but not defined herein are defined in NI 51-101 and Staff Notice 51 324 – Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Administrators ("CSA 51-324") and, unless the context otherwise requires, have the same meanings herein as in NI 51-101 and CSA 51-324.

The qualitative certainty levels referred to in the reserves definitions below are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions: (a) at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and (b) at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is

desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

"Developed non-producing reserves" are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

"Developed producing reserves" are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

"Developed reserves" are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

8

"Forecast prices and costs" means future prices and costs that are: (a) generally acceptable as being a reasonable outlook of the future; and (b) if and only to the extent that, there are fixed or presently determinable future prices or costs to which Ranger is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

"Probable reserves" are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

"Proved reserves" are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

"Reserves" are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on (a) analysis of drilling, geological, geophysical and engineering data; (b) the use of established technology; and (c) specified economic conditions. Reserves are classified according to the degree of certainty associated with the estimates.

"Undeveloped reserves" are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.

Abbreviations

Oil and Natural Gas Liquids		Natural Gas
bbl	barrel	Mcf	thousand cubic feet
Mbbl	thousand barrels	MMcf	million cubic feet
NGL	natural gas liquids	Mcf/d	thousand cubic feet per day
		MMbtu	million British Thermal Units
Other
BOE or boe	barrel of oil equivalent, using the conversion factor of six Mcf of natural gas being equivalent to one bbl of oil. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
boe/d	barrels of oil equivalent per day
mboe	thousand barrels of oil equivalent
WTI	West Texas Intermediate
$000s	thousands of dollars

Conversions

The following table sets forth certain standard conversions between Standard Imperial Units and the International System of Units (or metric units).

To Convert From	To	Multiply By
Mcf	Cubic metres	28.174
Cubic metres	Cubic feet	35.494
Bbls	Cubic metres	0.159
Cubic metres	Bbls	6.290
Feet	Metres	0.305
Metres	Feet	3.281

9

Summary of Significant Canadian to U.S. Reserves Disclosure Differences

Baytex's reserves information and the information included in the McDaniel Ranger Reserves Report has been prepared in accordance with guidelines specified in NI 51-101 and the COGE Handbook. There are significant differences in the type of volumes disclosed and the basis from which reserve volumes are economically determined under the SEC disclosure requirements set forth in Subpart 1200 of Regulation S-K (the “U.S. Standards”) and NI 51-101, and the difference between the reported reserves under the two disclosure standards can, therefore, be material. For example, the U.S. Standards require United States oil and gas reporting companies, in their filings with the SEC, to disclose only proved reserves after the deduction of royalties and production due to others but permits the optional disclosure of probable and possible reserves in accordance with the SEC's definitions, whereas NI 51-101 requires disclosure of proved and probable reserves and permits optional disclosure of possible reserves. Additionally, NI 51-101 defines "proved reserves" and "probable reserves" differently from the SEC rules. Accordingly, proved and probable reserves disclosed in this Business Acquisition Report may not be comparable to United States standards. Probable reserves are higher risk and are generally believed to be less likely to be accurately estimated or recovered than proved reserves. Additionally, the COGE Handbook and NI 51-101 require disclosure of reserves and related future net revenue estimates based on forecast prices and costs, whereas the U.S. Standards require that reserves and related future net revenue be estimated using average prices for the previous twelve months (constant prices) and that the standardized measure reflect discounted future net income taxes related to a company's operations. In addition, the COGE Handbook and NI 51-101 requires the presentation of reserves estimates on a "company gross" basis (representing a company's working interest share before deduction of royalties) and "company net" basis (after the deduction of royalties and similar payments), whereas the U.S. Standards require the presentation of net reserve estimates after the deduction of royalties and similar payments only. There are also differences in the technical reserves estimation standards applicable under NI 51-101 and, pursuant thereto, the COGE Handbook, and those applicable under the U.S. Standards, along with NI 51-101 requiring a more granular product type classification than required by U.S. Standards. NI 51-101 also requires that proved undeveloped reserves be reviewed annually for retention or reclassification if development has not proceeded as previously planned, while the U.S. Standards specify a five-year limit after initial booking for the development of proved undeveloped reserves. Finally, the SEC prohibits disclosure of oil and gas resources in SEC filings, including contingent resources, whereas Canadian securities regulators allow disclosure of oil and gas resources. Resources are different than, and should not be construed as, reserves. The foregoing is not an exhaustive summary of Canadian or U.S. reserves reporting requirements.

The supplemental reserve information and standardized measure of discounted future net cash flows included in Ranger’s audited financial statements for the year ended December 31, 2022, are presented in accordance with the provisions of the Financial Accounting Standards Board’s ASC Topic 932 Extractive Activities - Oil and Gas, which generally utilize definitions and estimations of proved reserves that are consistent with Rule 4-10 of Regulation S-X promulgated by the SEC, but do not necessarily include all of the disclosure required by the U.S. Standards.

EXHIBIT 1

RANGER RESERVES INFORMATION

The reserves data in respect of Ranger set out below has been extracted from the McDaniel Ranger Reserves Report, prepared by McDaniel in accordance with NI 51-101 and the COGE Handbook, which was prepared for use by Baytex in its evaluation of Ranger and for the purpose of making an offer to acquire Ranger. The estimates contained in the McDaniel Ranger Reserves Report differ from the estimates contained in the Ranger Reserves Report. The differences are primarily due to differences in Canadian to U.S. reserves disclosure. See "Summary of Significant Canadian to U.S. Reserves Disclosure Differences" contained in this Business Acquisition Report.

The McDaniel Ranger Reserves Report was prepared using the average commodity price forecasts and inflation rates of McDaniel, GLJ Petroleum Consultants Ltd. and Sproule Associates Limited as of January 1, 2023.

The following tables are a summary as at December 31, 2022 of Ranger's proved and probable tight oil, NGL, and shale gas reserves and the net present value of the future net revenue attributable to such reserves, as evaluated in the McDaniel Ranger Reserves Report. All of Ranger's reserves are located in the United States (Texas).

As at December 31, 2022, Ranger held 46% of the interests in a successor to ROCC Energy Holdings, L.P., a Delaware limited partnership ("Opco"). The McDaniel Ranger Reserves Report evaluated 100% of the reserves attributable the assets owned by Opco as at December 31, 2022. References to 'Ranger' in this Exhibit 1 refer to Ranger and its direct and indirect subsidiaries on a consolidated basis as at December 31, 2022, including 100% of the assets and reserves of Opco.

All evaluations of future net revenue are after the deduction of future income tax expenses (unless otherwise noted in the tables), royalties, development costs, production costs and well abandonment costs but before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses. The estimated future net revenue contained in the following tables does not necessarily represent the fair market value of Ranger's reserves. There is no assurance that the forecast price and cost assumptions contained in the McDaniel Ranger Reserves Report will be attained and variations could be material. The tables summarize the data contained in the McDaniel Ranger Reserves Report and, as a result, may contain slightly different numbers and columns in the tables may not add due to rounding. Other assumptions and qualifications relating to costs and other matters are summarized in the notes to or following the tables below. The recovery and reserves estimates described herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Readers should review the definitions and information contained in this Business Acquisition Report in conjunction with the following tables and notes.

In certain of the tables set forth below, the columns may not add due to rounding. All dollar amounts in the tables below are expressed in Canadian dollars.

Reserves Data (Forecast Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES

AS OF DECEMBER 31, 2022

FORECAST PRICES AND COSTS

	RESERVES SUMMARY
	Tight Oil				Shale Gas				NGL(3)				Total
Reserve Category	Gross(1) (Mbbl)		Net(2) (Mbbl)		Gross(1) (MMcf)		Net(2) (MMcf)		Gross(1) (Mbbl)		Net(2) (Mbbl)		Gross (mboe)		Net (mboe)
PROVED
Developed Producing		53,851.2		41,630.6		68,144.2		52,307.2		12,266.0		9,415.3		77,474.5		59,763.8
Developed Non-Producing		92.3		72.6		67.4		52.9		12.1		9.5		115.7		90.9
Undeveloped		66,407.8		50,624.4		94,108.6		71,997.9		14,788.5		11,297.9		96,881.1		73,922.0
TOTAL PROVED		120,351.3		92,327.7		162,320.2		124,358.0		27,066.6		20,722.7		174,471.3		133,776.7
PROBABLE		59,965.0		45,994.1		69,853.8		53,513.1		12,008.4		9,195.6		83,615.7		64,108.5
TOTAL PROVED PLUS PROBABLE		180,316.3		138,321.8		232,174.0		177,871.2		39,075.0		29,918.3		258,087.0		197,885.3

Notes:

(1) Gross reserves are working interest reserves before royalty deductions.

(2) Net reserves are working interest reserves after royalty deductions plus royalty interest reserves.

(3) NGL include condensate volumes.

SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE

AS OF DECEMBER 31, 2022

FORECAST PRICES AND COSTS

	Before Income Taxes Discounted at (%/year)										After Income Taxes Discounted at (%/year)										Unit Value Before Income Tax Discounted at 10%/ year(1)
Reserves Category	0 (M$)		5 (M$)		10 (M$)		15 (M$)		20 (M$)		0 (M$)		5 (M$)		10 (M$)		15 (M$)		20 (M$)		($/boe)
PROVED
Developed Producing		3,090,062		2,584,308		2,234,114		1,982,252		1,793,694		2,918,806		2,460,719		2,140,284		1,907,817		1,732,301		37.38
Developed Non-Producing		4,073		3,399		2,880		2,483		2,175		3,164		2,676		2,288		1,989		1,756		31.67
Undeveloped		2,012,368		1,349,507		922,852		636,624		436,784		1,566,858		1,020,380		669,723		436,993		276,943		12.48
TOTAL PROVED		5,106,503		3,937,214		3,159,846		2,621,359		2,232,654		4,488,827		3,483,774		2,812,294		2,346,799		2,011,000		23 62
PROBABLE		3,234,806		1,867,125		1,184,796		811,750		590,797		2,533,098		1,433,966		888,962		595,294		424,709		18.48
TOTAL PROVED PLUS PROBABLE		8,341,309		5,804,338		4,344,641		3,433,109		2,823,451		7,021,926		4,917,740		3,701,256		2,942,093		2,435,709		21.96

Notes:

(1) The unit values are based on net reserve volumes.

(2) Net present values prepared by McDaniel in the evaluation of Ranger's oil and gas properties are calculated by considering sales of oil, gas and by-product reserves, processing of third party reserves and other income. After tax net present values prepared by McDaniel in the evaluation of Ranger's oil and gas properties are calculated by considering the foregoing factors and incorporating the appropriate income tax calculations, current federal tax regulations and including prior tax pools available for deduction against income from Ranger's oil and gas properties, as supplied by Baytex.

(3) For U.S. federal and applicable state and local income tax purposes, the Merger and the other transactions contemplated by the Merger Agreement are intended to result in a step-up in basis in respect of a portion of the assets of Opco. Had the Merger and the other transactions contemplated by the Merger Agreement occurred on December 31, 2022 we estimate that undiscounted after tax Total Proved Reserves reported in the McDaniel Ranger Reserves Report would increase by $217 million and after tax Total Proved Reserves discounted at ten percent would increase by $123 million.

3

TOTAL FUTURE NET REVENUE (UNDISCOUNTED)

AS OF DECEMBER 31, 2022

FORECAST PRICES AND COSTS

Reserves Category	Revenue(1) (M$)		Royalties(2) (M$)		Operating Costs (M$)		Development Costs (M$)		Abandonment and Reclamation Costs (M$)		Future Net Revenue Before Income Taxes (M$)		Income Taxes (M$)		Future Net Revenue After Income Taxes (M$)
Proved Reserves		14,283,074		4,015,867		2,383,095		2,590,500		187,109		5,106,503		617,676		4,488,827
Proved Plus Probable Reserves		22,088,430		6,213,250		3,671,882		3,633,368		228,620		8,341,309		1,319,383		7,021,926

Notes:

(1) Includes all product revenues and other revenues as forecast.

(2) Royalties include any net profits interests paid, ad valorem or severance tax.

FUTURE NET REVENUE

BY PRODUCT TYPE

AS OF DECEMBER 31, 2022

FORECAST PRICES AND COSTS

Reserves Category	Production Group	Future Net Revenue Before Income Taxes (Discounted At 10%/Year) (M$)		Unit Value(1) ($/mcf, $/bbl)
Proved Reserves	Tight Oil(2)		2,955,436		33.05
	Shale Gas(3)		204,409		8.87
	TOTAL		3,159,846
Proved Plus Probable Reserves	Tight Oil(2)		4,109,920		30.49
	Shale Gas(3)		235,352		8.22
	TOTAL		4,344,641

Notes:

(1) Unit values are calculated using the 10% discount rate divided by the major product type net reserves for each group.

(2) Includes solution gas and by-products.

(3) Includes by-products.

Pricing Assumptions

The forecast cost and price assumptions assume increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs. The forecast cost and price assumptions utilized in the McDaniel Ranger Reserves Report were as follows:

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS⁽¹⁾

AS OF DECEMBER 31, 2022

FORECAST PRICES AND COSTS⁽¹⁾

Crude Oil					Gas
Year	WTI Crude Oil ($US/bbl)	Brent Crude Oil ($US/bbl)	Inflation(2) %	Exchange Rate(3) $US/$CAN	U.S. Henry Hub Gas Price ($US/MMBtu)
2022	94.65	100.75	6 .85	0.77	6.40
Forecast(1)
2023	80.33	84.67	0.0	0.75	4.74
2024	78.50	82.69	2.3	0.77	4.50
2025	76.95	81.03	2.0	0.77	4.31
2026	77.61	81.39	2.0	0.77	4.40
2027	79.16	82.65	2.0	0.78	4.49
2028	80.74	84.29	2.0	0.78	4.58
2029	82.36	85.98	2.0	0.78	4.67
2030	84.00	87.71	2.0	0.78	4.76
2031	85.69	89.46	2.0	0.78	4.86
2032	87.40	91.25	2.0	0.78	4.95
2033	89.15	93.07	2.0	0.78	5.05
2034	90.93	94.93	2.0	0.78	5.15
2035	92.75	96.83	2.0	0.78	5.26
2036	94.61	98.77	2.0	0.78	5.36
2037	96.50	100.74	2.0	0.78	5.47
Thereafter	Escalation Rate 2%/yr

Notes:

(1) As January 1, 2023.

(2) Inflation rates for costs.

(3) The exchange rate used to generate the benchmark reference prices in this table.

EXHIBIT 2

RANGER ANNUAL FINANCIAL STATEMENTS

See attached.

Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

Ranger Oil Corporation

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Ranger Oil Corporation (a Virginia corporation) and subsidiaries (the “Company”) as of December 31, 2022 and 2021, the related consolidated statements of operations, comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2022, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated March 9, 2023 expressed an unqualified opinion.

Basis for opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical audit matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The development of estimated proved reserves used in the calculation of depletion, depreciation, and amortization expense under the full cost method of accounting.

As described further in note 3 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future net revenues to record depletion, depreciation, and amortization expense. To estimate the volume of proved reserves and future net revenue, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the estimation of depletion, depreciation and amortization expense. We identified the estimation of proved reserves of oil and gas properties as a critical audit matter.

2

The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions necessary to estimate the volumes and future net revenues of the Company’s proved reserves require a high degree of subjectivity and could have a significant impact on the measurement of depletion, depreciation, and amortization expense. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.

Our audit procedures related to the estimation of proved reserves included the following, among others.

· We tested the design and operating effectiveness of controls relating to management’s estimation of proved reserves for the purpose of measuring depletion, depreciation, and amortization expense.

· We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists.

· To the extent key inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, including, but not limited to historical pricing differentials, operating costs, estimated capital costs, and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis. Specifically, our audit procedures involved testing management’s assumptions by performing the following:

– We compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials.

– We tested models used to estimate the future operating costs in the reserve report and compared amounts to historical operating costs.

– We evaluated the method used to determine the future capital costs and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells to ascertain its reasonableness.

– We tested the working and net revenue interests used in the reserve report by inspecting land and division order records.

– We evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability and intent to develop the proved undeveloped properties.

– We applied analytical procedures to the forecasted reserve report production by comparing to historical actual results and to the prior year reserve report.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2016.

Houston, Texas 

March 9, 2023

3

Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders
Ranger Oil Corporation

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of Ranger Oil Corporation (a Virginia corporation) and subsidiaries (the “Company”) as of December 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2022, and our report dated March 9, 2023 expressed an unqualified opinion on those financial statements.

Basis for opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP

Houston, Texas
March 9, 2023

4

RANGER OIL CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS 

(in thousands, except per share data)

	Year Ended December 31,
	2022			2021			2020
Revenues and other
Crude oil	$	1,003,255		$	517,301		$	251,741
Natural gas liquids		67,453			33,443			8,948
Natural gas		70,895			26,080			10,103
Other operating income, net		3,586			2,667			2,476
Total revenues and other		1,145,189			579,491			273,268
Operating expenses
Lease operating		85,792			45,402			37,463
Gathering, processing and transportation		36,698			23,647			22,050
Production and ad valorem taxes		61,377			31,041			16,619
General and administrative		40,972			66,529			33,789
Depreciation, depletion and amortization		244,455			131,657			140,673
Impairments of oil and gas properties		—			1,811			391,849
Total operating expenses		469,294			300,087			642,443
Operating income (loss)		675,895			279,404			(369,175	)
Other income (expense)
Interest expense, net of amounts capitalized		(48,931	)		(33,161	)		(31,257	)
Gain (loss) on extinguishment of debt		2,157			(8,860	)		—
Derivatives gains (losses)		(162,672	)		(136,999	)		88,422
Other, net		2,255			94			(850	)
Income (loss) before income taxes		468,704			100,478			(312,860	)
Income tax (expense) benefit		(4,186	)		(1,560	)		2,303
Net income (loss)		464,518			98,918			(310,557	)
Net income attributable to Noncontrolling interest		(246,825	)		(58,689	)		—
Net income (loss) attributable to Class A common shareholders	$	217,693		$	40,229		$	(310,557	)
Net income (loss) per share attributable to Class A common shareholders:
Basic	$	10.77		$	2.41		$	(20.46	)
Diluted	$	10.53		$	2.34		$	(20.46	)
Weighted average shares outstanding – basic		20,205			16,695			15,176
Weighted average shares outstanding – diluted		20,826			17,165			15,176

See accompanying notes to consolidated financial statements.

5

RANGER OIL CORPORATION 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) 

(in thousands)

	Year Ended December 31,
	2022			2021			2020
Net income (loss)	$	464,518		$	98,918		$	(310,557	)
Other comprehensive income (loss):
Change in pension and postretirement obligations, net of tax 1		—			20			(72	)
Comprehensive income (loss)		464,518			98,938			(310,629	)
Net income attributable to Noncontrolling interest		(246,825	)		(58,689	)		—
Other comprehensive income attributable to Noncontrolling interest 1		—			(23	)		—
Comprehensive income (loss) attributable to Class A common shareholders	$	217,693		$	40,226		$	(310,629	)

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

See accompanying notes to consolidated financial statements.

6

RANGER OIL CORPORATION
CONSOLIDATED BALANCE SHEETS 

(in thousands, except share data)

	December 31,
	2022			2021
Assets
Current assets
Cash and cash equivalents	$	7,592		$	23,681
Accounts receivable, net of allowance for credit losses		139,715			118,594
Derivative assets		29,714			11,478
Prepaid and other current assets		22,264			20,998
Assets held for sale		1,186			11,400
Total current assets		200,471			186,151
Property and equipment, net		1,809,000			1,383,348
Derivative assets		316			2,092
Other assets		4,420			5,017
Total assets	$	2,014,207		$	1,576,608
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	265,609		$	214,381
Derivative liabilities		67,933			50,372
Current portion of long-term debt		—			4,129
Total current liabilities		333,542			268,882
Deferred income taxes		6,216			2,793
Derivative liabilities		3,416			23,815
Other non-current liabilities		9,934			10,358
Long-term debt, net		604,077			601,252
Commitments and contingencies (Note 14)
Equity
Preferred stock of $0.01 par value – 5,000,000 shares authorized; none issued as of December 31, 2022 and 2021		—			—
Class A common stock of $0.01 par value – 110,000,000 shares authorized; 19,074,864 and 21,090,259 shares issued and outstanding as of December 31, 2022 and 2021, respectively		190			729
Class B common stock of $0.01 par value – 30,000,000 shares authorized; 22,548,998 shares issued and outstanding as of December 31, 2022 and 2021		2			2
Paid-in capital		220,062			273,329
Retained earnings		264,256			49,583
Accumulated other comprehensive loss		(111	)		(111	)
Ranger Oil shareholders’ equity		484,399			323,532
Noncontrolling interest		572,623			345,976
Total equity		1,057,022			669,508
Total liabilities and equity	$	2,014,207		$	1,576,608

See accompanying notes to consolidated financial statements.

7

RANGER OIL CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

		Year Ended December 31,
		2022			2021			2020
Cash flows from operating activities
Net income (loss)	$	464,518		$	98,918		$	(310,557	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
(Gain) loss on extinguishment of debt		(2,157	)		8,860			—
Depreciation, depletion and amortization		244,455			131,657			140,673
Impairments of oil and gas properties		—			1,811			391,849
Derivative contracts:
Net losses (gains)		162,672			136,999			(88,422	)
Cash settlements and premiums (paid) received, net		(183,378	)		(130,475	)		78,087
Deferred income tax expense (benefit)		3,422			1,249			(1,424	)
Non-cash interest expense		3,404			2,735			4,150
Share-based compensation		5,554			15,589			3,284
Other, net		(361	)		19			13
Changes in operating assets and liabilities:
Accounts receivable, net		(21,721	)		(38,676	)		28,078
Accounts payable and accrued expenses		6,528			60,338			(24,244	)
Other assets and liabilities		(7,506	)		1			778
Net cash provided by operating activities		675,430			289,025			222,265
Cash flows from investing activities
Capital expenditures		(481,486	)		(256,343	)		(168,565	)
Acquisitions of oil and gas properties		(137,532	)		—			—
Cash acquired in Lonestar Acquisition		—			11,009			—
Proceeds from sales of assets, net		12,420			160			87
Net cash used in investing activities		(606,598	)		(245,174	)		(168,478	)
Cash flows from financing activities
Proceeds from credit facility borrowings		610,000			70,000			51,000
Repayments of credit facility borrowings		(603,000	)		(176,400	)		(99,000	)
Repayments of second lien term loan		—			(200,000	)		—
Proceeds from 9.25% Senior Notes due 2026, net of discount		—			396,072			—
Repayments of acquired debt		(8,559	)		(249,700	)		—
Payments for share repurchases		(75,203	)		—			—
Distributions to Noncontrolling interest		(3,382	)		—			—
Dividends paid		(2,921	)		—			—
Proceeds from redeemable common units		—			151,160			—
Proceeds from redeemable preferred stock		—			2			—
Transaction costs paid on behalf of Noncontrolling interest		—			(5,543	)		—
Issuance costs paid for Noncontrolling interest securities		—			(3,758	)		—
Withholding taxes for share-based compensation		(954	)		(656	)		(487	)
Debt issuance costs paid		(902	)		(14,367	)		(78	)
Net cash used in financing activities		(84,921	)		(33,190	)		(48,565	)
Net increase (decrease) in cash and cash equivalents		(16,089	)		10,661			5,222
Cash and cash equivalents – beginning of period		23,681			13,020			7,798
Cash and cash equivalents – end of period	$	7,592		$	23,681		$	13,020
Supplemental disclosures:
Cash paid for:
Interest, net of amounts capitalized	$	46,071		$	15,609		$	27,333
Income tax refunds, net of payments	$	—		$	288		$	(2,471	)
Non-cash investing and financing activities:
Changes in property and equipment related to capital contributions	$	—		$	(38,561	)	$	—
Changes in accrued liabilities related to capital expenditures	$	46,616		$	16,726		$	(18,671	)
Change in property and equipment related to acquisitions	$	—		$	(480,563	)	$	—
Equity and replacement awards issued as consideration in the Lonestar Acquisition	$	—		$	173,576		$	—

See accompanying notes to consolidated financial statements.

8

RANGER OIL CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY 

(in thousands)

	Shares 1
				Class A
				Common								Class A
				Shares /			Class B					Common											Accumulated
	Preferred			Common			Common					Stock /			Class B								Other
	Shares			Shares			Shares		Preferred			Common			Common		Paid-in			Retained			Comprehensive			Noncontrolling			Total
	Outstanding			Outstanding			Outstanding		Stock			Stock			Stock		Capital			Earnings			Loss			Interest			Equity
Balance as of December 31, 2019		—			15,136			—	$	—		$	151		$	—	$	200,666		$	319,987		$	(59	)	$	—		$	520,745
Net loss		—			—			—		—			—			—		—			(310,557	)		—			—			(310,557	)
Restricted stock unit vesting		—			64			—		—			1			—		(487	)		—			—			—			(486	)
Cumulative effect of change in accounting principle		—			—			—		—			—			—		—			(76	)		—			—			(76	)
Common stock issued related to share-based compensation and other, net		—			—			—		—			—			—		3,284			—			(72	)		—			3,212
Balance as of December 31, 2020		—			15,200			—		—			152			—		203,463			9,354			(131	)		—			212,838
Net income		—			—			—		—			—			—		—			40,229			—			58,689			98,918
Issuance of preferred stock		225			—			—		2			—			—		—			—			—			—			2
Issuance of Noncontrolling interest		—			—			—		—			—			—		(50,068	)		—			—			229,620			179,552
Conversion of preferred stock into common stock 1		(225	)		—			22,549		(2	)		—			2		—			—			—			—			—
Issuance of common stock related to the Lonestar Acquisition 2		—			5,750			—		—			575			—		162,607			—			—			—			163,182
Change in ownership related to the Lonestar Acquisition		—			—			—		—			—			—		(57,604	)		—			—			57,644			40
Common stock issued related to share-based compensation and other, net		—			140			—		—			2			—		14,931			—			20			23			14,976
Balance as of December 31, 2021		—			21,090			22,549		—			729			2		273,329			49,583			(111	)		345,976			669,508
Net income		—			—			—		—			—			—		—			217,693			—			246,825			464,518
Repurchase of Class A Common Stock		—			(2,150	)		—		—			(22	)		—		(75,181	)		—			—			—			(75,203	)
Change in ownership, net		—			—			—		—			—			—		16,796			—			—			(16,796	)		—
Distributions to Noncontrolling interest		—			—			—		—			—			—		—			—			—			(3,382	)		(3,382	)
Dividends declared ($0.075 per share of Class A common stock)		—			—			—		—			—			—		—			(3,020	)		—			—			(3,020	)
Common stock issued related to share-based compensation and other, net		—			135			—		—			(517	)		—		5,118			—			—			—			4,601
Balance as of December 31, 2022		—			19,075			22,549	$	—		$	190		$	2	$	220,062		$	264,256		$	(111	)	$	572,623		$	1,057,022

¹  In October 2021, the Company effected a recapitalization, pursuant to which, among other things, the Company’s common stock was renamed and reclassified as Class A common stock, par value $0.01 per share (“Class A Common Stock”), a new class of capital stock of the Company, Class B Common Stock, par value $0.01 per share (“Class B Common Stock”) was authorized, and the designation of the Series A Preferred Stock was cancelled. See Note 15 in the notes to the consolidated financial statements for further details.

²  Includes $4.5 million attributed to pre-combination services for replacement awards issued in connection with the Lonestar Acquisition. See Note 4 and Note 16 for further details.

See accompanying notes to consolidated financial statements.

9

RANGER OIL CORPORATION 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 

(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.

On January 15, 2021 (the “Juniper Closing Date”), the Company consummated the transactions (collectively, the “Juniper Transactions”) contemplated by: (i) the Contribution Agreement, dated November 2, 2020, by and among the Company, ROCC Energy Holdings, L.P. (formerly PV Energy Holdings, L.P., the “Partnership”) and JSTX Holdings, LLC (“JSTX”), an affiliate of Juniper Capital Advisors, L.P. (“Juniper Capital” and, together with JSTX and Rocky Creek Resources, LLC, “Juniper”); and (ii) the Contribution Agreement, dated November 2, 2020 (the “Contribution Agreement”), by and among Rocky Creek Resources, LLC, an affiliate of Juniper Capital (“Rocky Creek”), the Company and the Partnership pursuant to which Juniper contributed $150 million in cash and certain oil and gas assets in South Texas in exchange for equity. See Note 3 and Note 4 for further discussion.

Note 2 – Basis of Presentation

Our 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 consolidated statements of operations and comprehensive income (loss) and our consolidated balance sheets as of and for the periods ended December 31, 2022 and 2021. Our 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 and 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 consolidated financial statements have been included. Certain reclassifications have been made to prior period amounts to conform to the current period presentation. Such reclassifications did not have a material impact on prior period financial statements.

Note 3 – Summary of Significant Accounting Policies

Principles of Consolidation

In January 2021, Ranger Oil completed a reorganization into an Up-C structure with JSTX and Rocky Creek. Under the Up-C structure, Juniper owns all of the shares of the Company’s Class B Common Stock which 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 (formerly, PV Energy Holdings GP, LLC, the “GP”), is the general partner of the Partnership. Subsidiaries of the Partnership own and operate all our oil and gas assets. Ranger Oil and the Partnership are holding companies with no other operations, material cash flows, or material assets or liabilities other than the equity interests in their subsidiaries.

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.

10

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 consolidated financial statements. The Company reflects the noncontrolling interest in the 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 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 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. As of December 31, 2021, the Company owned 21,090,259 Common Units, representing a 48.3% limited partner interest in the Partnership, and Juniper owned 22,548,998 Common Units, representing the remaining 51.7% limited partner interest. During the year ended December 31, 2022, 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 15 for information regarding share repurchases and Note 16 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 (“ASC”) 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 the Noncontrolling interest pro rata based on ownership interests in the Partnership.

Use of Estimates

Preparation of our consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities in our consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Such estimates include certain asset and liability valuations as further described in these notes. Actual results could differ from those estimates.

Cash and Cash Equivalents

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. Some of our account balances exceed the FDIC coverage limits. We believe our cash and cash equivalents are not subject to any material interest rate risk, equity price risk, credit risk or other market risk.

Derivative Instruments

We utilize derivative instruments, which are placed with financial institutions that we believe are of acceptable credit risk, to mitigate our financial exposure to commodity price and interest rate volatility. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by our board of directors.

All derivative instruments are recognized in our consolidated financial statements at fair value. We have elected to report all of our derivative asset and liability positions on a gross basis on our consolidated balance sheets and not net the positions, even when a legal right-of-setoff exists. Our derivative instruments are not formally designated as hedges in the context of GAAP. In accordance with our internal policies, we do not utilize derivative instruments for speculative purposes. We recognize changes in fair value in income within Derivatives gains (losses) in our consolidated statements of operations. See Note 6 for further information on our derivatives.

11

Inventory

Inventory is stated at the lower of cost and net realizable value using the average cost method. Our inventory consists of tubular goods and equipment that are primarily comprised of oil and natural gas drilling and repair items such as tubing, casing and pumping units.

Property and Equipment

Oil and Gas Properties

We apply the full cost method of accounting for our oil and gas properties. Under this method, all productive and nonproductive costs incurred in the exploration, development and acquisition of oil and gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical, or seismic, drilling, completion and equipment costs. Internal costs incurred that are directly attributable to exploration, development and acquisition activities undertaken by us for our own account, and which are not attributable to production, general corporate overhead or similar activities are also capitalized. Future development costs are estimated on a property-by-property basis based on current economic conditions and are amortized as a component of depreciation, depletion and amortization (“DD&A”).

Unproved properties not being amortized include unevaluated leasehold costs and associated capitalized interest. These costs are reviewed quarterly to determine whether or not and to what extent proved reserves have been assigned to a property or if an impairment has occurred due to lease expirations, general economic conditions and other factors, in which case the related costs along with associated capitalized interest are reclassified to the proved oil and gas properties subject to DD&A.

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 estimated after-tax discounted future net revenues are determined using the prior 12-month’s average commodity prices based on closing prices on the first day of each month, adjusted for differentials, discounted at 10%. The calculation of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are significant uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production, timing and plan of development.

DD&A of our oil and gas properties is computed using the units-of-production method. We apply this method by multiplying the unamortized cost of our proved oil and gas properties, net of estimated salvage plus future development costs, by a rate determined by dividing the physical units of oil and gas produced during the period by the total estimated units of proved oil and gas reserves at the beginning of the period.

Other Property and Equipment

Other property and equipment consists primarily of gathering systems and related support equipment, vehicles, leasehold improvements, information technology hardware and capitalized software costs. Other property and equipment are carried at cost and include expenditures for additions and improvements which increase the productive lives of existing assets. Renewals and betterments, which extend the useful life of the properties, are also capitalized. Maintenance and repair costs are charged to expense as incurred. We compute depreciation and amortization of property and equipment using the straight-line method over the estimated useful life of each asset as follows: Gathering systems – 15 to 20 years and Other property and equipment – three to 20 years.

Leases

We determine if a contractual arrangement is a lease at inception and whether it is classified as operating or financing based on whether that contract conveys the right to control the use of an identified asset in exchange for consideration for a period of time. Leases are included in Other assets, Accounts payable and accrued liabilities and Other liabilities on our consolidated balance sheets and are identified as Right-of-use (“ROU”) assets, Current lease obligations and Noncurrent lease obligations, respectively, in Note 11 and Note 12.

ROU assets represent our right to use an underlying asset for the lease term and lease obligations represent our obligation to make lease payments arising from the underlying contractual arrangement. Operating lease ROU assets and obligations are recognized at the commencement date based on the present value of lease payments over the lease term. The operating lease ROU assets include any lease payments made in advance and excludes lease incentives. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise such options. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.

12

Most of our leasing arrangements do not identify or otherwise provide for an implicit interest rate. Accordingly, we utilize a secured incremental borrowing rate based on information available at the commencement date in the determination of the present value of the lease payments. As most of our lease arrangements have terms ranging from two to five years, our secured incremental borrowing rate is primarily based on the rates applicable to our Credit Facility.

We have lease arrangements that include lease and certain non-lease components, including amounts for related taxes, insurance, common area maintenance and similar terms. We apply a practical expedient provided in Accounting Standards Codification (“ASC”) Topic 842, Leases, to not separate the lease and non-lease components. Accordingly, the ROU assets and lease obligations for such leases will include the present value of the estimated payments for the non-lease components over the lease term.

Certain of our lease arrangements with contractual terms of 12 months or less are classified as short-term leases and are recognized on a straight-line basis over the lease term. Accordingly, we do not include the underlying ROU assets and lease obligations on our consolidated balance sheets. The associated costs are aggregated with all of our other lease arrangements and are disclosed in the tables in Note 11.

Certain of our lease arrangements result in variable lease payments which, in accordance with ASC Topic 842, do not give rise to lease obligations. Rather, the basis and terms and conditions upon which such variable lease payments are determined are disclosed in Note 11.

Asset Retirement Obligations

We recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. Associated asset retirement costs are capitalized as part of the carrying cost of the asset. Our AROs relate to the plugging and abandonment of oil and gas wells and the associated asset is recorded as a component of oil and gas properties. After recording these amounts, the ARO is accreted to its future estimated value, and the additional capitalized costs are depreciated over the productive life of the assets. Both the accretion of the ARO and the depreciation of the related long-lived assets are included in the DD&A expense caption in our consolidated statements of operations.

Income Taxes

We recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company’s financial statements or tax returns. Using this method, deferred tax assets and liabilities are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates. In assessing our deferred tax assets, we consider whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is assessed at each reporting period and is dependent upon the generation of future taxable income and our ability to utilize operating loss carryforwards during the periods in which the temporary differences become deductible. We also consider the scheduled reversal of deferred tax liabilities and available tax planning strategies. We recognize interest attributable to income taxes, to the extent it may be incurred, as a component of interest expense and penalties as a component of income tax expense.

We are subject to ongoing tax examinations in numerous domestic jurisdictions. Accordingly, we may record incremental tax expense based upon the more-likely-than-not outcomes of uncertain tax positions. In addition, when applicable, we adjust the previously recorded tax expense to reflect examination results when the position is effectively settled. Our ongoing assessments of the more-likely- than-not outcomes of the examinations and related tax positions require judgment and can increase or decrease our effective tax rate, as well as impact our operating results. The specific timing of when the resolution of each tax position will be reached is uncertain.

Revenue Recognition and Associated Costs

The Company recognizes revenue in accordance with ASC Topic 606, Revenue from Contracts with Customers, which includes a five- step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services.

We record revenue in the month that our oil and gas production is delivered to our customers. As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, we make accruals for revenues and accounts receivable based on estimates of our share of production. We record any differences, which historically have not been significant, between the actual amounts ultimately received and the original estimates in the period they become finalized. See Note 5 for further discussion.

13

Substantially all of our commodity product sales are short-term in nature with contract terms of one year or less. 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 material contract assets or liabilities.

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

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 expenses in our consolidated financial statements.

Marketing and water disposal services. We provide marketing and water disposal services to certain of our joint venture partners and other third parties with respect to oil and gas production for which we are the operator. Pricing for such services represents a fixed rate fee based, in the case of marketing services, on the sales price of the underlying oil and gas products and, in the case of water services, on the quantity of water volume processed. Marketing revenue is recognized simultaneously with the sale of our commodity production to our customers while water service revenue is recognized in the month that the service is rendered. Direct costs associated with our marketing efforts are included in General and administrative expenses (“G&A”) and direct costs associated with our water service efforts are netted against the underlying revenue.

Credit Losses

We monitor and assess our portfolio of accounts receivable, including those from our customers, our joint interest partners and others, when applicable, for credit losses on a monthly basis as we originate the underlying financial assets. Our review process and related internal controls take into appropriate consideration (i) past events and historical experience with the identified portfolio segments, (ii) current economic and related conditions within the broad energy industry as well as those factors with broader applicability and (iii) reasonable supportable forecasts consistent with other estimates that are inherent in our financial statements. In order to facilitate our processes for the review and assessment of credit losses, we have identified the following portfolio segments: (i) customers for our commodity production and (ii) joint interest partners which are further stratified into the following sub-segments: (a) mutual operators which includes joint interest partners with whom we are a non-operating joint interest partner in properties for which they are the operator, (b) large partners consisting of those legal entities that maintain a working interest of at least 10% in properties for which we are the operator and (c) all others which includes legal entities that maintain working interests of less than 10% in properties for which we are the operator as well as legal entities with whom we no longer have an active joint interest relationship, but continue to have transactions, including joint venture audit settlements, that from time-to-time give rise to the origination of new accounts receivable.

14

Share-Based Compensation

Our stock compensation plans permit the grant of incentive and nonqualified stock options, common stock, deferred common stock units, restricted stock and restricted stock units to our employees and directors. We measure the cost of employee services received in exchange for an award of equity-classified instruments based on the grant-date fair value of the award. Compensation cost associated with equity-classified awards are generally amortized on a straight-line basis over the applicable vesting period. Awards that are based on performance are amortized either on a graded basis over the term of the applicable performance periods for awards that represent in- substance multiple awards or ratably over the requisite service period for awards that cliff vest. Compensation cost associated with liability-classified awards is measured at the end of each reporting period and recognized based on the period of time that has elapsed during the applicable performance period. We recognize forfeitures as they occur. We recognize share-based compensation expense related to our share-based compensation plans as a component of G&A expenses in our consolidated statements of operations.

Recent Accounting Pronouncements

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

Recently Issued Accounting Pronouncements Not Yet Adopted

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

Note 4 – Transactions

2022

Asset Acquisitions

In 2022, we completed acquisitions of additional working interests in Ranger-operated wells along with certain contiguous oil and gas producing assets and undeveloped acreage in the Eagle Ford shale. The aggregate cash consideration for these acquisitions was $137.5 million, including customary post-closing adjustments. These transactions were accounted for as asset acquisitions.

Asset Disposition

On July 22, 2022, we closed on the sale of the corporate office building and related assets acquired in connection with the Lonestar Acquisition (defined below) that were classified as Assets held for sale on the consolidated balance sheet as of December 31, 2021. Gross proceeds were $11.0 million and total net proceeds were $1.8 million after netting costs to sell of approximately $0.8 million and payoff of the related mortgage debt and accrued interest of $8.4 million.

2021

Acquisition of Lonestar Resources

On October 5, 2021 (the “Closing Date”), the Company acquired Lonestar Resources US Inc., a Delaware corporation (“Lonestar”), as a result of which Lonestar and its subsidiaries became wholly-owned subsidiaries of the Company (the “Lonestar Acquisition”). The Lonestar Acquisition was effected pursuant to the Agreement and Plan of Merger (the “Merger Agreement”), dated July 10, 2021, by and between the Company and Lonestar. In accordance with the terms of the Merger Agreement, Lonestar shareholders received 0.51 shares of the Company’s common stock for each share of Lonestar common stock held immediately prior to the effective time of the Lonestar Acquisition. Based on the closing price of the Company’s common stock on October 5, 2021 of $30.19, the total value of the Company’s common stock issued to holders of Lonestar common stock, warrants and restricted stock units as applicable, was approximately $173.6 million.

The Lonestar Acquisition constituted a business combination and was accounted for using the acquisition method of accounting, with Ranger Oil being treated as the accounting acquirer. Under the acquisition method of accounting, the assets and liabilities of Lonestar and its subsidiaries were recorded at their respective fair values as of the date of completion of the Lonestar Acquisition. The Company completed the purchase price allocation during the third quarter of 2022.

15

The following table sets forth the Company’s final allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Final Purchase Price Allocation
Consideration:
Fair value of the Company’s common stock issued 1	$	173,576
Less: Replacement awards attributable to post-combination compensation cost 2		(10,394	)
Total consideration transferred	$	163,182
Assets:
Other current assets	$	50,044
Proved oil and gas properties		476,743
ARO asset		1,239
Corporate office building and related assets 3		11,400
Other property and equipment		2,582
Other non-current assets		37
Total assets acquired	$	542,045
Liabilities:
Current portion of long-term debt	$	24,187
Other current liabilities		66,150
Derivative liabilities 4		49,554
Asset retirement obligations		2,494
Long-term debt		236,478
Total liabilities assumed	$	378,863
Net Assets Acquired	$	163,182

¹  Includes the fair value of the replacement equity awards to the extent services were provided by employees of Lonestar prior to closing of $4.5 million. See Note 16 for additional information about the replacement equity awards.

²  Represents the fair value of the replacement equity awards considered post-combination services. See Note 16 for further details.

3 As of December 31, 2021, these assets met the held for sale criteria and were classified as Assets held for sale on the respective consolidated balance sheet.

⁴  Immediately following the Lonestar Acquisition, we paid approximately $50 million to restructure certain of Lonestar’s derivatives which were novated or terminated. We reset the majority of the swaps to reflect then current market pricing.

For the period from the closing date of the Lonestar Acquisition on October 5, 2021 through December 31, 2021, approximately $62.5 million of revenues and $34.0 million of direct operating expenses were included in the Company’s consolidated statement of operations for the year ended December 31, 2021.

Lonestar Acquisition-Related Expenses

The following table summarizes expenses related to the Lonestar Acquisition incurred for the year ended December 31, 2021:

	Year Ended December 31, 2021
Bank, legal and consulting fees	$	9,856
Employee severance and related costs		7,563
Replacement awards stock-based compensation costs		10,394
Integration and rebranding costs		1,746
Total acquisition-related expenses	$	29,559

Employee severance and related costs primarily related to one-time severance and change-in-control compensation costs. Replacement awards stock-based compensation costs related to the accelerated vesting of certain Lonestar share-based awards for former Lonestar employees and directors based on the terms of the Merger Agreement and change-in-control provisions within the former Lonestar employment agreements.

16

Pro Forma Operating Results (Unaudited)

The following unaudited pro forma condensed financial data for the years ended December 31, 2021 and 2020 was derived from the historical financial statements of the Company giving effect to the Lonestar Acquisition, as if it had occurred on January 1, 2020. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Lonestar’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Lonestar’s outstanding shares of common stock and equity awards as of the closing date of the Lonestar Acquisition, (ii) the depletion of Lonestar’s fair-valued proved oil and natural gas properties under the full cost accounting method as well as other impacts of converting Lonestar from successful efforts to the full cost accounting method and (iii) the estimated tax impacts of the pro forma adjustments. The pro forma results of operations do not include any cost savings or other synergies that may result from the Lonestar Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the Lonestar assets.

The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Lonestar Acquisition taken place on January 1, 2020 and is not intended to be a projection of future results.

	December 31,
	2021		2020
Total revenues	$	729,026	$	389,495
Net income (loss) attributable to Class A common shareholders	$	74,355	$	(321,951	)

Juniper Transactions

On the Juniper Closing Date, (i) pursuant to the terms of the Contribution Agreement, JSTX contributed to the Partnership, as a capital contribution, $150 million in cash in exchange for 17,142,857 newly issued Common Units and the Company issued to JSTX 171,428.57 shares of Series A Preferred Stock, par value $0.01 per share, of the Company (“Series A Preferred Stock”) (now Class B Common Stock as discussed below) at a price equal to the par value of the shares acquired, and (ii) pursuant to the terms of the Asset Agreement, including certain closing adjustments based on a September 1, 2020 effective date (the “Effective Date”), Rocky Creek contributed to our operating subsidiary certain oil and gas assets in exchange for 5,405,252 newly issued Common Units and the Company issued to Rocky Creek 54,052.52 shares of Series A Preferred Stock (5,406,141 Common Units and 54,061.41 shares of Series A Preferred Stock after post-closing adjustments) at a price equal to the par value of the shares acquired, including 495,900 Common Units and 4,959 shares of Series A Preferred Stock placed in a restricted account to support post-closing indemnification claims, 50% of such amount of which was disbursed 180 days after the Juniper Closing Date and the remainder was disbursed one year after the Juniper Closing Date. In connection with the contribution of the oil and gas assets under the Asset Agreement, we received $1.2 million of revenues attributable to production from the Rocky Creek assets for the period from December 1, 2020 through the Juniper Closing Date.

We incurred a total of $19.0 million of professional fees, including advisory, legal, consulting fees and other costs in connection with the Juniper Transactions. A total of $5.0 million were attributable to services and costs incurred and recognized in 2020 as G&A. The remaining $14.0 million of costs were incurred in January 2021 or otherwise incurred contingent upon the closing of the Juniper Transactions, including $5.5 million of transaction costs incurred by Juniper that were required to be paid by the Company under the Juniper Transaction Agreements as well as $3.8 million of costs incurred by us related to the issuance of the Series A Preferred Stock and Common Units. Collectively, these amounts were classified as a reduction to the capital contribution on our consolidated balance sheets. The remainder of $4.7 million, representing professional fees and other costs, was recognized as a component of G&A in the quarter ended March 31, 2021.

On October 6, 2021, the Company, JSTX and Rocky Creek entered into a Contribution and Exchange Agreement, whereby all outstanding shares of the Series A Preferred Stock were exchanged for newly issued shares of Class B Common Stock (“Class B Common Stock”), at a ratio of one share of Class B Common Stock for each 1/100th of a share of Series A Preferred Stock and the designation of the Series A Preferred Stock was cancelled. See Note 15 for additional information.

17

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

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

Due to the Lonestar Acquisition in October 2021, a change in ownership of the Noncontrolling interest occurred. Refer to Note 15 for additional information.

Note 5 – Revenue Recognition

The Company’s revenues are derived from contracts for crude oil, natural gas and NGL sales and other services, as described in Note 3.

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

	December 31,
	2022			2021
Customers	$	109,149		$	96,195
Joint interest partners		30,730			21,755
Derivative settlements from counterparties 1		437			1,037
Other		114			18
Total		140,430			119,005
Less: Allowance for credit losses		(715	)		(411	)
Accounts receivable, net of allowance for credit losses	$	139,715		$	118,594

¹ See Note 6 for information regarding our derivative instruments.

Major Customers

For the year ended December 31, 2022, two customers accounted for 43% of our consolidated product revenues, of which 27%, and 16% of the consolidated revenues were generated from these customers, respectively. For the year ended December 31, 2021, three customers accounted for 48% of our consolidated product revenues, of which 22%, 14%, and 12% of the consolidated revenues were generated from these customers, respectively. For the year ended December 31, 2020, three customers accounted for 56% of our consolidated product revenues of which 27%, 19%, and 10% of the consolidated revenues were generated from these customers, respectively.

18

Note 6 – 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

The following is a general description of the commodity derivative instruments we employ:

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

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

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

Two-Way Collars. A two-way collar is an arrangement that contains a sold call option, which establishes a maximum price (ceiling price) we will receive for the contract volumes, and a purchased put, which establishes a minimum price (floor price) we will receive based on an index price. We have entered into two-way collars periodically to achieve particular hedging objectives. When the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price. If the index price is between the floor and ceiling prices, no payments are due from either party. When the index price is below the floor price, we will receive the difference between the floor price and the index price.

19

The following table sets forth our commodity derivative contracts as of December 31, 2022:

Commodity Derivatives	1Q2023			2Q2023			3Q2023			4Q2023			1Q2024		2Q2024
NYMEX WTI Crude Swaps
Average Volume Per Day (bbl)		2,500			2,400			2,807			2,657			462		462
Weighted Average Swap Price ($/bbl)	$	54.4		$	54.26		$	54.92		$	54.93		$	58.75	$	58.75
NYMEX WTI Crude Collars
Average Volume Per Day (bbl)		20,972			12,775			13,043			8,967
Weighted Average Purchased Put Price ($/bbl)	$	67.75		$	63.23		$	73.13		$	72.27
Weighted Average Sold Call Price ($/bbl)	$	83.64		$	75.69		$	89.07		$	87.57
NYMEX HH Swaps
Average Volume Per Day (MMBtu)		10,000			7,500
Weighted Average Swap Price ($/MMBtu)	$	3.620		$	3.690
NYMEX HH Collars
Average Volume Per Day (MMBtu)		14,617			11,538			11,413			11,413			11,538		11,538
Weighted Average Purchased Put Price ($/MMBtu)	$	6.561		$	2.500		$	2.500		$	2.500		$	2.500	$	2.328
Weighted Average Sold Call Price ($/MMBtu)	$	12.334		$	2.682		$	2.682		$	2.682		$	3.650	$	3.000
HSC Basis Swaps
Average Volume Per Day (MMBtu)		24,617			19,038			11,413			11,413
HSC Basis Average Fixed Price ($/MMBtu)	$	(0.153	)	$	(0.153	)	$	(0.153	)	$	(0.153	)
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

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 December 31, 2022, we did not have any interest rate derivatives.

Financial Statement Impact of Derivatives

The impact of our derivatives activities on income is included within Derivatives gains (losses) on our consolidated statements of operations. Derivative contracts that have expired at the end of a period, but for which cash had not been received or paid as of the balance sheet date, have been recognized as components of Accounts receivable (see Note 5) and Accounts payable and accrued liabilities (see Note 12) on the consolidated balance sheets. Adjustments to reconcile net income to net cash provided by operating activities include derivative losses and cash settlements that are reported under Net losses (gains) and Cash settlements and premiums (paid) received, net, on our consolidated statements of cash flows, respectively.

20

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

	Year Ended December 31,
	2022			2021			2020
Interest Rate Swap gains (losses) recognized in the consolidated statements of operations	$	64		$	(2	)	$	(7,510)
Commodity gains (losses) recognized in the consolidated statements of operations		(162,736	)		(136,997	)		95,932
	$	(162,672	)	$	(136,999	)	$	88,422
Interest rate cash settlements recognized in the consolidated statements of cash flows	$	(1,415	)	$	(3,822	)	$	(2,210	)
Commodity cash settlements and premiums received (paid) recognized in the consolidated statements of cash flows		(181,963	)		(77,099	)		80,297
Commodity cash settlements paid for acquired derivatives recognized in the consolidated statements of cash flows		—			(49,554	)		—
	$	(183,378	)	$	(130,475	)	$	78,087

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

		Fair Values
		December 31, 2022				December 31, 2021
Type	Balance Sheet Location	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Interest rate contracts	Derivative assets/liabilities – current	$	—	$	—	$	—	$	1,480
Commodity contracts	Derivative assets/liabilities – current		29,714		67,933		11,478		48,892
Commodity contracts	Derivative assets/liabilities – non-current		316		3,416		2,092		23,815
		$	30,030	$	71,349	$	13,570	$	74,187

As of December 31, 2022, we reported net commodity derivative liabilities of $41.3 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 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 13 for information regarding the fair value of our derivative instruments.

21

Note 7 – Property and Equipment, Net

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

	December 31,
	2022			2021
Oil and gas properties (full cost accounting method):
Proved	$	3,013,854		$	2,327,686
Unproved		41,882			57,900
Total oil and gas properties		3,055,736			2,385,586
Other property and equipment 1		30,969			31,055
Total properties and equipment		3,086,705			2,416,641
Accumulated depreciation, depletion, amortization and impairments		(1,277,705	)		(1,033,293	)
Total property and equipment, net	$	1,809,000		$	1,383,348

¹  Excludes the corporate office building and related other assets acquired in connection with the Lonestar Acquisition that were classified as Assets held for sale on the consolidated balance sheets as of December 31, 2021. We closed on the sale of the corporate office building in July 2022. See Note 4 for additional information. As of December 31, 2022, we had $1.2 million remaining other assets classified as Assets held for sale excluded from above.

Unproved property costs of $41.9 million and $57.9 million have been excluded from amortization as of December 31, 2022 and December 31, 2021, respectively. The total costs not subject to amortization as of December 31, 2022 were incurred in the following periods: $0.9 million in 2022, $1.3 million in 2021, $0.7 million in 2020 and $33.2 million prior to 2019 as well as $5.8 million of capitalized interest applied thereto. We transferred $25.2 million and $17.8 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 years ended December 31, 2022 and 2021, respectively. We capitalized internal costs of $5.3 million, $4.1 million and $2.1 million and interest of $4.3 million, $3.6 million and $2.7 million during the years ended December 31, 2022, 2021 and 2020, respectively, in accordance with our accounting policies. Average DD&A per boe of proved oil and gas properties was $16.42, $12.96 and $15.83 for the years ended December 31, 2022, 2021 and 2020, respectively.

Ceiling Test

Beginning in early 2020, certain events such as the COVID-19 pandemic coupled with decisions by the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC, collectively “OPEC+”) negatively impacted the oil and gas industry with significant declines in crude oil prices and oversupply of crude oil. Then in early 2021 with the deployment of vaccines and resulting increased mobility and global economic activity and other factors, demand for oil increased and commodity prices began to recover. Prior to the announced significant production cut to take effect in November 2022, OPEC+ had previously employed a strategy to gradually increase production. These shifts in OPEC+ production levels as well as the Russia-Ukraine war and related sanctions, which began in the first quarter of 2022, continue to contribute to a high level of uncertainty surrounding energy supply and demand resulting in volatile commodity prices. WTI crude oil and natural gas prices surged with prices over $120 per bbl and over $9 per Mcf, respectively, during the first half of 2022 due to oil supply shortage concerns. During the second half of 2022, WTI crude oil and natural gas prices dropped to lows under $72 per bbl and $4 per Mcf, respectively.

As discussed in Note 3, the Ceiling Test utilizes commodity prices based on a trailing 12-month average based on the closing prices on the first day of each month. With the higher commodity prices in 2022, we did not record any impairments of our oil and gas properties during the year ended December 31, 2022. However, the years ended December 31, 2021 and 2020 were impacted by the decline in commodity prices as a result of the various factors discussed above, resulting in impairments of our oil and gas properties of $1.8 million and $391.8 million, respectively.

22

Note 8 – Asset Retirement Obligations

The following table reconciles our AROs as of the dates presented, which are included within Other liabilities on our consolidated balance sheets:

	Year Ended December 31,
	2022			2021
Balance at beginning of period	$	8,413		$	5,461
Changes in estimates		182			—
Liabilities incurred		64			226
Liabilities settled		(589	)		(228	)
Acquisitions of properties		166			2,508
Accretion expense		613			446
Balance at end of period	$	8,849		$	8,413

Note 9 – Long-Term Debt      

The following table summarizes our long-term debt as of the dates presented:      

	December 31, 2022			December 31, 2021
Credit Facility	$	215,000		$	208,000
9.25% Senior Notes due 2026		400,000			400,000
Mortgage debt 1		—			8,438
Other 2		238			2,516
Total		615,238			618,954
Less: Unamortized discount 3		(3,055	)		(3,720	)
Less: Unamortized deferred issuance costs 3, 4		(8,106	)		(9,853	)
Total, net	$	604,077		$	605,381
Less: Current portion		—			(4,129	)
Long-term debt	$	604,077		$	601,252

¹  The mortgage debt related to the corporate office building and related other assets acquired in connection with the Lonestar Acquisition for which assets were held as collateral for such debt. In July 2022, the mortgage debt was fully repaid in connection with the sale of the corporate office building. See Note 4 for additional information on the sale.

²  Other debt of $2.2 million at December 31, 2022 was extinguished during 2022 and recorded as a gain on extinguishment on the consolidated statements of operations.

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

⁴  Excludes issuance costs associated with the Credit Facility, which represent costs attributable to the access to credit over its contractual term, that have been presented as a component of Other assets (see Note 12) and are being amortized over the term of the Credit Facility using the straight-line method.

Credit Facility

As of December 31, 2022, 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.

In June 2022, we entered into the Agreement and Amendment No. 12 to Credit Agreement (the “Twelfth Amendment”). The Twelfth Amendment, in addition to other changes described therein, amended the Credit Facility to, effective on June 1, 2022, (1) increase the borrowing base from $725 million to $875 million, with aggregate elected commitments remaining at $400 million and (2) replaced LIBOR with the Secured Overnight Financing Rate (“SOFR”), an index supported by short-term Treasury repurchase agreements.

23

In September 2022, we entered into the Agreement and Amendment No. 13 to Credit Agreement (the “Thirteenth Amendment”). The Thirteenth Amendment, in addition to other changes described therein, amended the Credit Facility to (1) increase the borrowing base from $875 million to $950 million and (2) increase the aggregate elected commitment amounts under the Credit Facility from $400 million to $500 million.

The outstanding borrowings under the Credit Facility bear interest at a rate equal to, at our option, either (a) a customary reference rate plus an applicable margin ranging from 1.50% to 2.50%, determined based on the utilization level under the Credit Facility or (b) effective June 1, 2022, a term SOFR reference rate (a Eurodollar rate, including LIBOR prior to June 1, 2022), plus an applicable margin ranging from 2.50% to 3.50%, determined based on the utilization level under the Credit Facility. Interest on reference rate borrowings is payable quarterly in arrears and is computed on the basis of a year of 365/366 days, and interest on Eurodollar 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 December 31, 2022, the actual weighted-average interest rate on the outstanding borrowings under the Credit Facility was 7.25%. 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 December 31, 2022, we were in compliance with all debt covenants under the Credit Facility.

We had $215.0 million in outstanding borrowings and $1.0 million in outstanding letters of credit under the Credit Facility as of December 31, 2022. Factoring in the outstanding letters of credit, we had $284.0 million of availability under the Credit Facility as of December 31, 2022. During the years ended December 31, 2022 and 2021, we incurred and capitalized issue costs of $0.9 million and $2.6 million, respectively, in connection with amendments to the Credit Facility. Additionally, during 2022 and 2021, we wrote off $0.1 million and $0.8 million of previously deferred debt issue costs associated with amendments to the Credit Facility, respectively.

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.

In connection with the consummation of the Lonestar Acquisition, the net proceeds from the 9.25% Senior Notes due 2026 were used to repay and discharge $249.8 million of Lonestar’s long-term debt including accrued interest and related expenses, and the remainder, along with cash on hand, of $146.2 million was used to repay outstanding obligations under the Second Lien Term Loan including a prepayment premium and accrued interest and related expenses. Thereafter, the Second Lien Term Loan was terminated and $6.9 million was recorded as a loss on extinguishment of debt for costs incurred related to a prepayment premium and write off of unamortized discount and issue costs. During 2021, we incurred and capitalized $10.4 million of issue costs in connection with the 9.25% Senior Notes due 2026. See Note 4 for additional information.

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

As of December 31, 2022, the Company was in compliance with all debt covenants under the indenture.

24

Note 10 – Income Taxes

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

	Year Ended December 31,
	2022		2021		2020
Current income tax expense (benefit)
Federal	$	—	$	—	$	(1,236	)
State		764		311		357
Total current income tax expense (benefit)		764		311		(879	)
Deferred income tax expense (benefit)
Federal		—		—		1,236
State		3,422		1,249		(2,660	)
Total deferred income tax expense (benefit)		3,422		1,249		(1,424	)
Income tax expense (benefit)	$	4,186	$	1,560	$	(2,303	)

The following table reconciles the difference between the income tax expense (benefit) computed by applying the statutory tax rate to our income (loss) before income taxes and our reported income tax expense (benefit) for the periods presented:

	Year Ended December 31,
	2022					2021					2020
Tax computed at federal statutory rate	$	98,428		21.0	%	$	21,100		21.0	%	$	(65,701	)	21.0	%
State income taxes, net of federal income tax benefit		4,186		0.9	%		1,560		1.6	%		(1,856	)	0.6	%
Change in valuation allowance		(44,070	)	(9.4	)%		(9,348	)	(9.3	)%		64,062		(20.5	)%
Noncontrolling interest		(52,299	)	(11.2	)%		(12,501	)	(12.4	)%		—		—	%
Other, net		(2,059	)	(0.4	)%		749		0.7	%		1,192		(0.4	)%
Income tax expense (benefit)	$	4,186		0.9	%	$	1,560		1.6	%	$	(2,303	)	0.7	%

The following table summarizes the principal components of our deferred income tax assets and liabilities as of the dates presented:

	December 31,
	2022			2021
Deferred tax assets:
Net operating loss (“NOL”) carryforwards	$	194,819		$	203,243
Asset retirement obligations		66			63
Property and equipment		27,530			24,585
Fair value of derivative instruments		310			493
Interest expense limitation		13,443			13,747
Other		—			18
Total deferred tax assets		236,168			242,149
Less: Valuation allowance		(158,017	)		(205,617	)
Total net deferred tax assets	$	78,151		$	36,532
Deferred tax liabilities:
Property and equipment	$	6,592		$	3,357
Investment in the Partnership		77,713			35,968
Other		62			—
Total deferred tax liabilities	$	84,367		$	39,325
Net deferred tax liabilities	$	(6,216	)	$	(2,793	)

25

Income Tax Provision

For the year ended December 31, 2022 and 2021, we did not have any current federal tax benefits. The provision for the year ended December 31, 2020 includes current federal benefits of $1.2 million attributable to refunds of AMT credits for the 2020 tax year. The amounts attributable to 2020 combined the amounts attributable to 2019, which had been recognized on our consolidated balance sheets as of December 31, 2019 as a current asset, were received in 2020 as an acceleration of all AMT credits in connection with certain provisions of the CARES Act. In addition, we have recognized deferred state tax expense (benefits) of $3.4 million, $1.2 million and $(2.7) million primarily attributable to property and equipment as well as $0.8 million, $0.3 million and $0.4 million current state expense attributable to the Texas margin tax for the years ended December 31, 2022, 2021 and 2020, respectively. Our overall effective tax rates were 0.9%, 1.6% and 0.7% for the years ended December 31, 2022, 2021 and 2020, respectively.

Deferred Tax Assets and Liabilities

As of December 31, 2022, we had federal NOL carryforwards of approximately $706.7 million, a substantial portion of which, if not utilized, expire between 2032 and 2037. NOLs incurred after January 1, 2018 can be carried forward indefinitely. Because of the change in ownership provisions of the Code, use of a portion of our federal NOLs may be limited in future periods. As of December 31, 2022, we carried a valuation allowance against our federal and state deferred tax assets of $158.0 million. We considered both the positive and negative evidence in determining whether it was more likely than not that some portion or all of our deferred tax assets will be realized. The amount of deferred tax assets considered realizable could, however, be adjusted if estimates of future taxable income during the carryforward period are reduced or increased or if objective negative evidence is no longer present and additional weight is given to subjective positive evidence, including projections for growth. The valuation allowance along with $84.4 million of deferred tax liabilities fully offset our deferred tax assets. The net deferred tax liability recognized on our consolidated balance sheets as of December 31, 2022 is attributable to certain state deferred tax liabilities associated with property and equipment and unrealized hedges. The valuation allowance related to all other net deferred tax assets remains in full as of December 31, 2022 and 2021.

Following the Juniper Transactions, Ranger Oil is a holding company and all of its operating assets are held within the Partnership. Certain of the federal deferred tax assets and liabilities were reclassified to investment in partnership deferred tax liability in 2021.

Other Income Tax Matters

We had no liability for unrecognized tax benefits as of December 31, 2022 and 2021. There were no interest and penalty charges recognized during the years ended December 31, 2022, 2021 and 2020. Tax years from 2015 forward remain open for examination by the Internal Revenue Service and various state jurisdictions.

Note 11 – Leases

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

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

	Year Ended December 31,
	2022			2021			2020
Operating lease cost	$	889		$	891		$	979
Short-term lease cost		49,418			24,655			23,721
Variable lease cost		32,370			24,807			21,932
Less: Amounts charged as drilling costs 1		(43,867	)		(21,213	)		(20,708	)
Total lease cost recognized in the consolidated statement of operations 2	$	38,810		$	29,140		$	25,924

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

²  Includes $14.9 million, $10.8 million and $11.2 million recognized in GPT, $23.1 million, $17.4 million and $13.8 million recognized in Lease operating expense (“LOE”) and $0.8 million, $0.9 million and $1.0 million recognized in G&A for the years ended December 31, 2022, 2021, and 2020, respectively.

26

The following table summarizes supplemental cash flow information related to leases for the periods presented:

	Year Ended December 31,
	2022		2021		2020
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	952	$	981	$	943
ROU assets obtained in exchange for operating lease obligations	$	118	$	—	$	388

The following table summarizes supplemental balance sheet information related to leases as of the dates presented:

		December 31,
Leases	Balance Sheet Location	2022		2021
Assets
ROU assets – operating leases	Other assets	$	989	$	1,671
Liabilities
Current operating lease obligations	Accounts payable and accrued liabilities	$	907	$	914
Non-current operating lease obligations	Other non-current liabilities		200		975
Total operating lease obligations		$	1,107	$	1,889

The following table presents other information as it relates to operating leases as of the dates presented:

	December 31,
	2022			2021
Weighted-average remaining lease term – operating leases		1.5 years			2.1 years
Weighted-average discount rate – operating leases		3.33	%		3.13	%

As of December 31, 2022, maturities of our operating lease liabilities consisted of the following:

	December 31, 2022
2023	$	907
2024		175
2025		29
2026		26
2027		1
Total undiscounted lease payments		1,138
Less: imputed interest		(31	)
Total operating lease obligations	$	1,107

27

Note 12 – Supplemental Balance Sheet Detail

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

	December 31,
	2022		2021
Prepaid and other current assets:
Inventories 1	$	19,341	$	10,305
Prepaid expenses 2		2,923		10,693
	$	22,264	$	20,998
Other assets:
Deferred issuance costs of the Credit Facility, net of amortization	$	3,218	$	3,308
Right-of-use assets – operating leases		989		1,671
Other		213		38
	$	4,420	$	5,017
Accounts payable and accrued liabilities:
Trade accounts payable	$	58,592	$	32,452
Drilling and other lease operating costs		62,842		35,045
Revenue and royalties payable		104,512		95,521
Production, ad valorem and other taxes		10,547		7,905
Derivative settlements to counterparties		4,109		6,117
Compensation and benefits		6,927		13,942
Interest		14,655		15,321
Environmental remediation liability 3		207		2,287
Current operating lease obligations		907		914
Other		2,311		4,877
	$	265,609	$	214,381
Other non-current liabilities:
Asset retirement obligations	$	8,849	$	8,413
Non-current operating lease obligations		200		975
Postretirement benefit plan obligations		885		970
	$	9,934	$	10,358

¹  Includes tubular inventory and well materials of $18.7 million and $9.5 million and crude oil volumes in storage of $0.6 million and $0.8 million as of December 31, 2022 and 2021, respectively.

²  The balance as of December 31, 2022 and 2021 includes $0.5 million and $9.6 million, respectively, for the prepayment of drilling and completion services and materials.

³  The balance as of December 31, 2022 and 2021 represents estimated costs associated with remediation activities for certain wells and tanks acquired as part of the Lonestar Acquisition; the remediation was completed in the fourth quarter of 2022.

28

Note 13 – Fair Value Measurements

We apply the authoritative accounting provisions included in GAAP for measuring 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.

We use a hierarchy that prioritizes the inputs we use to measure fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below.

Fair value measurements are classified and disclosed in one of the following three categories:

· Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Level 1 inputs generally provide the most reliable evidence of fair value.

· Level 2: Quoted prices in markets that are not active or inputs, which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

· Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity).

Our financial instruments, including cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to their short-term maturities. As of December 31, 2022 and 2021, 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 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. As of December 31, 2021, the carrying amount and estimated fair value of total debt (before amortization of issuance costs) was $619.0 million and $634.6 million, respectively.

Recurring Fair Value Measurements

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

	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

	As of December 31, 2021
	Level 1		Level 2		Level 3		Total
Financial assets:
Commodity derivative assets – current	$	—	$	11,478	$	—	$	11,478
Commodity derivative assets – non-current		—		2,092		—		2,092
Total financial assets	$	—	$	13,570	$	—	$	13,570
Financial liabilities:
Interest rate swap liabilities – current	$	—	$	1,480	$	—	$	1,480
Commodity derivative liabilities – current		—		48,892		—		48,892
Commodity derivative liabilities – non-current		—		23,815		—		23,815
Total financial liabilities	$	—	$	74,187	$	—	$	74,187

29

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

· Commodity derivatives: We determine the fair values of our commodity derivative instruments using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied volatilities, time value and non-performance risk. For the current market prices, we use third-party quoted forward prices, as applicable, for NYMEX WTI, MEH crude oil and NYMEX HH 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 December 31, 2022, we had not entered into any new interest rate derivative instruments.

Non-performance risk is incorporated by utilizing discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is in a liability position. See Note 6 for additional details on our derivative instruments.

Non-Recurring Fair Value Measurements

In addition to the fair value measurements applied with respect to assets contributed in the Juniper Transactions and acquired with the Lonestar Acquisition, as described in Note 4, the most significant non-recurring fair value measurements utilized in the preparation of our consolidated financial statements are those attributable to the initial determination of 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 14 – Commitments and Contingencies

The following table sets forth our significant commitments as of December 31, 2022, by category, for the next five years and thereafter:

Year	Gathering and Intermediate Transportation Commitments		Other Commitments
2023	$	13,937	$	296
2024		13,976		211
2025		13,937		136
2026		7,794		—
2027		3,796		—
Thereafter		12,012		—
Total	$	65,452	$	643

Drilling and Completion Commitments

As of December 31, 2022, we had contracts for three drilling rigs with remaining terms of less than two years.

30

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 December 31, 2022:

Description of contractual arrangement	Expiration of Contractual Arrangement	Minimum Gross Volume Commitment (MVC) (bbl/d)		Expiration of Minimum Volume Commitment (MVC)
Field gathering agreement	February 2041		8,000	February 2031
Intermediate pipeline transportation services	February 2026		8,000	February 2026
Volume capacity support	April 2026		8,000	April 2026

Each of 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.

Under the field gathering and volume capacity support arrangements, credits for deliveries of volumes in excess of the volume commitment may be applied to any deficiency arising in the succeeding 12-month period.

During the years ended December 31, 2022, 2021 and 2020, we recorded expense of $42.5 million, $36.0 million and $34.5 million, respectively, for these contractual obligations in connection with these arrangements.

Crude Oil Storage

As of December 31, 2022, we had access to up to approximately 180,000 barrels of dedicated tank capacity for no additional charge at the service provider’s central delivery point facility (“CDP”), in Lavaca County, Texas through February 2041. 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 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

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 December 31, 2022 and 2021, we had an estimated reserve of approximately $0.1 million for certain claims made against us regarding previously divested operations included in Accounts payable and accrued liabilities on our consolidated balance sheets.

31

Environmental Compliance

Extensive federal, state and local laws govern oil and gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as plugging of abandoned wells. As of December 31, 2022, and 2021, we had AROs of $8.8 million and $8.4 million, respectively. Additionally, we had environmental remediation liabilities recorded as part of the Lonestar Acquisition of $0.2 million and $2.3 million as of December 31, 2022, and 2021, respectively. The environmental remediation activities were completed in the fourth quarter of 2022.

The regulatory burden on the oil and gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material impact on our financial condition or results of operations. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws, including any significant limitation on the use of hydraulic fracturing, have the potential to adversely affect our operations.

Other Commitments

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 15 – Shareholders’ Equity

Capital Stock

Prior to the Lonestar Acquisition, the Company’s authorized capital stock consisted of 115,000,000 shares including (i) 110,000,000 shares of common stock, par value $0.01 per share and (ii) 5,000,000 shares of Series A Preferred Stock, par value $0.01 per share.

On October 6, 2021, in connection with the consummation of the Lonestar Acquisition, the Company effected a recapitalization, pursuant to which (i) the Company’s common stock was renamed and reclassified as Class A Common Stock, (ii) the authorized number of shares of capital stock of the Company was increased to 145,000,000 shares, (iii) 30,000,000 shares of Class B Common Stock was authorized, (iv) all 225,489.98 outstanding shares of the Series A Preferred Stock were exchanged for 22,548,998 newly issued shares of Class B Common Stock, and (v) the designation of the Series A Preferred Stock was cancelled.

As of December 31, 2022, the Company had two classes of common stock: Class A Common Stock and Class B Common Stock. The holders of record of Class A Common Stock and Class B Common Stock vote together as a single class on all matters on which holders of Class A Common Stock and Class B Common Stock are entitled to vote; except that certain directors are elected by holders of a majority of the shares of Class B Common Stock voting as a separate class.

The holders of Class A Common Stock have no preemptive rights to purchase shares of Class A Common Stock. Shares of Class A Common Stock are not subject to any redemption or sinking fund provisions and are not convertible into any of the Company’s other securities. In the event of the Company’s voluntary or involuntary liquidation, dissolution or winding up, holders of Class A Common Stock will share equally in the assets remaining after it pays its creditors and preferred shareholders. Holders of Class A Common Stock are entitled to receive dividends when and if declared by the Board of Directors.

Shares of Class B Common Stock are non-economic interests in the Company, and no dividends can be declared or paid on the Class B Common Stock. The holders of Class B Common Stock have no preemptive rights to purchase shares of any 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.

32

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 December 31, 2022, the Company had (i) 110,000,000 authorized shares of Class A Common Stock and 19,074,864 shares of Class A Common Stock issued and outstanding, (ii) 30,000,000 authorized shares of Class B Common Stock and 22,548,998 shares of Class B Common Stock issued and outstanding, and (iii) 5,000,000 authorized shares of preferred stock, par value $0.01 per share, and no shares of preferred stock were issued or outstanding.

Paid-in Capital

Paid-in capital represents the value of consideration we received in excess of par value for the original issuance of our common stock net of costs directly attributable to the issuance transactions. In addition, paid-in capital includes amounts attributable to the amortized cost of share-based awards that have been granted to our employees and directors, net of any adjustments with the ultimate vesting of such awards.

Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income and losses are entirely attributable to our pension and postretirement health care benefit obligations. For further details on our pension and postretirement health care plans, see Note 16.

Dividends

On July 7, 2022, the Company’s Board of Directors declared an inaugural cash dividend of $0.075 per share of Class A Common Stock and on November 2, 2022, a second cash dividend was declared of $0.075 per share of Class A Common Stock. The related dividends were paid on August 4, 2022 and November 28, 2022 to holders of record of Class A Common Stock as of the close of business on July 25, 2022 and November 16, 2022, respectively. In connection with any dividend, Ranger’s operating subsidiary will also make a corresponding distribution to its common unitholders. During 2022, the dividends paid to the holders of our Class A Common Stock and distribution to common unitholders totaled $6.3 million in the aggregate. The Company’s Credit Facility and the indenture have restrictive covenants that limit its ability to pay dividends.

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 year ended December 31, 2022, we repurchased 2,150,486 shares of our Class A Common Stock at a total cost of $75.2 million at an average purchase price of $34.95. The share repurchases were recorded to Class A common stock and Paid-in capital on our consolidated balance sheets. As of December 31, 2022, the remaining authorized repurchase amount under the share repurchase program was $64.8 million.

Change in Ownership of Consolidated Subsidiaries

The following table summarizes changes in the ownership interest in consolidated subsidiaries during the periods presented:

	Year Ended December 31,
	2022		2021			2020
Net income (loss) attributable to Class A common shareholders	$	217,693	$	40,229		$	(310,557	)
Transfers (to) from the noncontrolling interest, net 1		16,796	$	(57,604	)		N/A
Change from net income (loss) attributable to Class A common shareholders and net transfers to Noncontrolling interest	$	234,489	$	(17,375	)	$	(310,557	)

¹  The year ended December 31, 2022 includes a net transfer of $16.8 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. The year ended December 31, 2021 includes a net transfer to Noncontrolling interest of $57.6 million related to (i) the Class A common stock issuances and (2) the relative proportionate share of net assets acquired in the Lonestar Acquisition with a corresponding adjustment to Paid-in capital. These equity adjustments had no impact on earnings other than a resulting increase (decrease) to the noncontrolling interest proportionate share of net income (loss) and a corresponding increase (decrease) to the proportionate share of net income (loss) attributable to common shareholders.

33

During the year ended December 31, 2022, as discussed above and in Note 16, 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 $16.8 million during the year ended December 31, 2022 to reflect the revised ownership percentage of total equity. See Note 3 for further discussion.

As discussed in Note 4, on October 5, 2021, the Company completed its acquisition of Lonestar in an all-stock transaction. In accordance with the terms of the Merger Agreement, Lonestar shareholders received 0.51 shares of Penn Virginia common stock for each share of Lonestar common stock held immediately prior to the effective time of the Lonestar Acquisition.

In connection with the Lonestar Acquisition, 5,749,508 shares of Class A Common Stock of the Company were issued and, in accordance with the Partnership Agreement, an equivalent number of Common Units were issued to the Company resulting in a change in the proportionate share of Common Units held by the Company relative to Juniper as no additional Common Units in the Partnership were issued to Juniper. As such and effective upon the close of the Lonestar Acquisition, we recognized an adjustment to the carrying amount of noncontrolling interest and a corresponding adjustment to Class A common shareholders’ equity of $57.6 million to reflect the revised ownership percentage of total equity, inclusive of Juniper’s revised proportionate share of the fair value of net assets acquired in connection with the Lonestar Acquisition effective October 5, 2021.

Note 16 – 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 (the “Incentive Plan”) for share-based compensation awards. A total of 811,573 time-vested restricted stock units (“RSUs”) and 664,414 performance- based restricted stock units (“PRSUs”) have been granted to employees and directors through December 31, 2022.

All of our share-based compensation awards are classified as equity instruments because they result in the issuance of common stock on the date of grant, upon exercise or are otherwise payable in common stock upon vesting, as applicable. The compensation cost attributable to these awards has been measured at the grant date and recognized over the applicable vesting periods as a non-cash expense.

We recognized $5.6 million, $15.6 million (including $10.4 million and $1.9 million as a result of the change-in-control events associated with the Lonestar Acquisition discussed below and the Juniper Transactions, respectively) and $3.3 million of share-based compensation expense for the years ended December 31, 2022, 2021 and 2020, respectively, and nil, $0.5 million and $0.1 million of related income tax benefits for the years ended December 31, 2022, 2021 and 2020, respectively.

The Merger Agreement provided the terms in which Lonestar share-based awards held by Lonestar employees were replaced with share- based awards of the Company (“replacement awards”) on the acquisition date. For accounting purposes, the fair value of the replacement awards must be allocated between each employee’s pre-combination and post-combination services. Amounts allocated to pre- combination services have been included as consideration transferred as part of the Lonestar Acquisition. See Note 4 for a summary of consideration transferred. Compensation costs of $10.4 million allocated to post-combination services were recorded during the year ended December 31, 2021 as stock-based compensation expense from the immediate vesting of these awards pursuant to the terms of the Merger Agreement.

Time-Vested Restricted Stock Units

The RSUs entitle the grantee to receive a share of common stock upon the achievement of the applicable service period vesting requirement. The grant date fair value of our time-vested RSU awards are recognized on a straight-line basis over the applicable vesting period, which is generally over a three-year period.

34

The following table summarizes activity for our most recent fiscal year with respect to awarded RSUs:

	Time-Vested Restricted Stock Units			Weighted-Average Grant Date Fair Value
Balance at January 1, 2022		230,517		$	9.20
Granted		49,314		$	35.07
Vested		(112,509	)	$	10.03
Forfeited		(17,451	)	$	12.77
Balance at December 31, 2022		149,871		$	17.51

As of December 31, 2022, 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 1.74 years. The total grant date fair values of RSUs that vested in 2022, 2021 and 2020 were $1.1 million, $3.6 million and $2.8 million, respectively.

Performance Restricted Stock Units

The PRSUs entitle the grantee to receive a share of common stock upon the achievement of both service and market conditions. The table below presents information pertaining to PRSUs granted in the following periods:

	2022			2021		2020		2019
PRSUs granted 1		180,217			225,206		145,399		15,066
Monte Carlo grant date fair value 2	$	60.60 to $74.92			$17.74 to $33.31	$	2.40	$	34.02
Average grant date fair value 3	$	34.68	$		13.63		not applicable		not applicable

¹  The 2020 PRSU grants include one executive officers’ inducement award originally granted in August 2020 that was amended in April 2021 to conform vesting conditions to other PRSU awards granted in 2021.

²  Represents the Monte Carlo grant date fair value of PRSU grants based on the Company’s TSR performance (as defined below).

³  Represents the average grant date fair value of 2022 and 2021 PRSU grants based on the Company’s ROCE performance (as defined below).

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 expense 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.

Vesting of PRSUs granted in 2020 and 2019 range from 0% to 200% 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 is 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%			49.90	%
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.

35

The following table summarizes activity for our most recent fiscal year with respect to awarded PRSUs:

	Performance Restricted Stock Units			Weighted-Average Grant Date Fair Value
Balance at January 1, 2022		345,069		$	16.20
Granted		180,217		$	47.77
Vested		(68,190	)	$	10.12
Change in units based on performance 1		(4,494	)	$	7.01
Forfeited		(12,502	)	$	21.47
Balance at December 31, 2022		440,100		$	29.87

¹  PRSUs granted in 2020 and 2019 are granted at a target of 100% but can vest from a range of 0% to 200% of the original grant based on performance as described above. Amount represents difference between original grant amount and amounts ultimately earned.

As of December 31, 2022, we had $6.6 million of unrecognized compensation cost attributable to PRSUs. We expect that cost to be recognized over a weighted-average period of 1.65 years.

Executive Transition and Retirement

In August 2020, we appointed Darrin Henke as our president and chief executive officer, or CEO, and director following the retirement of John Brooks. We incurred incremental G&A costs of approximately $1.2 million, in connection with Mr. Henke’s appointment and Mr. Brooks’ separation. In addition to those incremental costs, we recognized $0.7 million during the year ended December 31, 2020 for the accelerated vesting of certain share-based compensation awards of Mr. Brooks in connection with his retirement.

Defined Contribution Plan

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 provide matching contributions on our employees’ elective deferral contributions up to 6% of compensation up to the maximum statutory limits. The 401(k) Plan also provides for discretionary employer contributions. We recognized expense attributable to the 401(k) Plan of $1.2 million, $1.0 million, $0.9 million for the years ended December 31, 2022, 2021 and 2020, respectively. The charges for the 401(k) Plan are included as a component of G&A expenses in our consolidated statements of operations. Amounts representing accrued obligations to the 401(k) Plan of $0.4 million and $0.3 million are recorded within Accounts payable and accrued expenses on our consolidated balance sheets as of December 31, 2022 and 2021, respectively.

Defined Benefit Pension and Postretirement Health Care Plans

We maintain unqualified legacy defined benefit pension and defined benefit postretirement health care 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 year ended December 31, 2022, 2021 and 2020, and is included as a component of Other, net in our consolidated statements of operations. The combined unfunded benefit obligations under these plans were $1.1 million as of December 31, 2022 and 2021 and are included within Accounts payable and accrued liabilities (current portion) and Other liabilities (non-current portion) on our consolidated balance sheets.

36

Note 17 – 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 Class B Common Stock as applicable to the years ended December 31, 2022 and 2021) held by the Noncontrolling interest in the Partnership are exchanged for Class A Common Stock. 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 Class B Common Stock as applicable to the years ended December 31, 2022 and 2021) held by the Noncontrolling interest.

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

	Year Ended December 31,
Numerator:	2022			2021			2020
Net income (loss)	$	464,518		$	98,918		$	(310,557	)
Net income attributable to Noncontrolling interest		(246,825	)		(58,689	)		—
Net income (loss) attributable to Class A common shareholders for Basic EPS		217,693			40,229			(310,557	)
Adjustment for assumed conversions of RSUs and PRSUs		1,628			—			—
Adjustment for assumed conversions and elimination of Noncontrolling interest net income		—			58,689			—
Net income (loss) attributable to Class A common shareholders for Diluted EPS	$	219,321		$	98,918		$	(310,557	)
Denominator:
Weighted average shares outstanding used in Basic EPS		20,205			16,695			15,176
Effect of dilutive securities:
Common Units and Series A Preferred Stock or Class B Common Stock, as applicable, that are exchangeable for Class A Common Stock 1, 2		—			—			—
RSUs and PRSUs 2		621			470			—
Weighted average shares outstanding used in Diluted EPS 2		20,826			17,165			15,176

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

²  For the years ended December 31, 2022 and 2021, 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 diluted earnings per share. For the year ended December 31, 2020, approximately 0.1 million potentially dilutive securities, represented by RSUs and PRSUs, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per share.

Note 18 – Subsequent Events

Proposed Merger with Baytex Energy Corp.

On February 27, 2023, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with 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 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 late in the second quarter of 2023, subject to the satisfaction of customary closing conditions, including the requisite shareholder and regulatory approvals.

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, payable on March 30, 2023 to holders of record of Class A Common Stock as of the close of business on March 17, 2023.

37

Supplemental Information on Oil and Gas Producing Activities (Unaudited)

Oil and Gas Reserves

All of our proved oil and gas reserves are located in the continental United States. The estimates of our proved oil and gas reserves were prepared by our independent third party engineers, DeGolyer and MacNaughton, Inc. utilizing data compiled by us. DeGolyer and MacNaughton, Inc. is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists. Our Senior Vice President, Chief Operating Officer is primarily responsible for overseeing the preparation of the reserve estimate by DeGolyer and MacNaughton, Inc.

Reserve engineering is a process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil, NGLs and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future prices for these commodities may all differ from those assumed. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are subject to change as additional information becomes available.

The following table sets forth our estimate of net quantities of proved reserves, including changes therein and proved developed and proved undeveloped reserves for the periods presented:

Proved Developed and Undeveloped Reserves	Oil (Mbbl)			NGLs (Mbbl)			Natural Gas (MMcf)			Total Equivalents (Mboe)
December 31, 2019		98,896			19,154			90,449			133,125
Revisions of previous estimates		(23,554	)		(5,599	)		(26,712	)		(33,606	)
Extensions and discoveries		29,966			3,208			15,357			35,734
Production		(6,829	)		(1,165	)		(5,360	)		(8,887	)
December 31, 2020		98,479			15,598			73,734			126,366
Revisions of previous estimates		(5,633	)		(2,606	)		(11,154	)		(10,098	)
Extensions and discoveries		45,709			9,877			47,774			63,548
Production		(7,711	)		(1,326	)		(6,712	)		(10,155	)
Purchase of reserves		32,278			18,476			121,550			71,012
December 31, 2021		163,122			40,019			225,192			240,673
Revisions of previous estimates		(35,615	)		(7,381	)		(44,239	)		(50,369	)
Extensions and discoveries		46,176			12,644			70,700			70,603
Production		(10,668	)		(2,205	)		(12,100	)		(14,890	)
Purchase of reserves		6,217			1,331			5,516			8,468
December 31, 2022		169,232			44,408			245,069			254,485
Proved Developed Reserves:
December 31, 2020		36,360			7,979			37,597			50,605
December 31, 2021		59,957			16,431			94,033			92,060
December 31, 2022		69,881			19,136			106,566			106,778
Proved Undeveloped Reserves:
December 31, 2020		62,119			7,619			36,137			75,761
December 31, 2021		103,165			23,588			131,159			148,613
December 31, 2022		99,351			25,272			138,503			147,707

The following is a discussion and analysis of the significant changes in our proved reserve estimates for the periods presented:

Year Ended December 31, 2022

In 2022, our proved reserves increased by 13.8 MMboe due to acquisitions and proved undeveloped reserves extensions. During 2022, Ranger Oil continued to drill and complete wells and increased drilling efficiencies in lateral footage capabilities. We optimized and refreshed the existing drilling inventory to access stranded acreage and optimize for longer laterals, resulting in an increase in average treatable lateral per well. This process resulted in an increase to extensions and discoveries of 70.6 MMboe that was offset by 34.3 MMboe of negative revisions due to schedule adjustments that moved wells beyond our five-year drilling window schedule. In addition, our revisions of previous estimates reflect: (i) 9.3 MMboe of unfavorable revisions attributable to changes in lateral lengths and type curves, (ii) unfavorable revisions of 10.0 MMboe due to performance, offset by (iii) favorable revisions due to pricing of 3.3 MMboe.

38

Year Ended December 31, 2021

In 2021, our proved reserves increased by 114.3 MMboe due primarily to the Juniper transactions and the Lonestar Acquisition increasing our reserves. During the COVID-19 pandemic, Ranger Oil continued to drill and complete wells and increased drilling efficiencies in lateral footage capabilities. Additionally, we optimized and refreshed the existing drilling inventory to access stranded acreage and optimize for longer laterals, resulting in an increase in average treatable lateral per well, thus increasing the average reserves per well. This process resulted in an increase to extensions and discoveries of 63.5 MMboe that was offset by 14.0 MMboe of negative revisions due to schedule adjustments that moved wells beyond our five-year drilling window schedule. In addition, our revisions of previous estimates reflect: (i) 5.8 MMboe of favorable revisions attributable to changes in lateral lengths and type curves and (ii) favorable revisions due to pricing of 3.6 MMboe, offset by (iii) unfavorable revisions of 5.5 MMboe due to performance.

Year Ended December 31, 2020

In 2020, our proved reserves declined by 6.8 MMboe due primarily to lower commodity pricing reducing our reserves in excess of the positive revisions to replace production. In light of the ongoing COVID-19 pandemic and its impact on our capital resources, we undertook a substantial review of our drilling plans and available site inventory that resulted in a substantial shift in the focus of our near-term drilling schedule to a greater focus on our core, oilier prospects. This process resulted in an increase to extensions and discoveries of 35.7 MMboe that was largely offset by 34.0 MMboe of negative revisions due primarily to certain wells that moved beyond our five-year drilling window schedule. In addition, our revisions of previous estimates reflect: (i) 6.9 MMboe of favorable revisions attributable to changes in lateral lengths and type curves, substantially offset by (ii) unfavorable revisions of 3.2 MMboe due to performance and (iii) declines in pricing of 3.2 MMboe.

Capitalized Costs Relating to Oil and Gas Producing Activities

The following table sets forth capitalized costs related to our oil and gas producing activities and accumulated DD&A for the periods presented:

	December 31,
	2022			2021			2020
Oil and gas properties:
Proved	$	3,013,854		$	2,327,686		$	1,545,910
Unproved		41,882			57,900			49,935
Total oil and gas properties		3,055,736			2,385,586			1,595,845
Other property and equipment		25,318			26,131			23,068
Total capitalized costs relating to oil and gas producing activities		3,081,054			2,411,717			1,618,913
Accumulated depreciation and depletion		(1,273,005	)		(1,028,970	)		(896,219	)
Net capitalized costs relating to oil and gas producing activities 1	$	1,808,049		$	1,382,747		$	722,694

¹  Excludes property and equipment attributable to our corporate operations which is comprised of certain capitalized hardware, software, leasehold improvements and office furniture and fixtures.

39

Costs Incurred in Certain Oil and Gas Activities

The following table summarizes costs incurred in our oil and gas property acquisition, exploration and development activities for the periods presented:

	Year Ended December 31,
	2022		2021		2020
Development costs	$	516,616	$	262,439	$	126,739
Proved property acquisition costs 1		137,532		—		—
Unproved property acquisition costs		6,882		3,687		3,448
Exploration costs		1,214		86		342
	$	662,244	$	266,212	$	130,529

¹  Excludes the fair value of proved properties of $478.0 million recorded in the purchase price allocation with respect to the Lonestar Acquisition for the year ended December 31, 2021. The purchase was funded through the issuance of our common stock.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

Future cash inflows were computed by applying the average prices of oil and gas during the 12-month period prior to the period end, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the period and estimated costs as of that fiscal year end, to the estimated future production of proved reserves. Future prices actually received may materially differ from current prices or the prices used in the standardized measure.

Future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pre-tax net cash flows relating to our proved reserves and the tax basis of proved oil and gas properties. In addition, the effects of statutory depletion in excess of tax basis, available NOL carryforwards and alternative minimum tax credits were used in computing future income tax expense. The resulting annual net cash inflows were then discounted using a 10% annual rate.

The standardized measure of discounted future net cash flows is not intended, and should not be interpreted, to represent the fair value of our oil and gas reserves. An estimate of the fair value would also consider, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and cost, and a discount factor more representative of economic conditions and risks inherent in reserve estimates. Accordingly, the changes in standardized measure reflected below do not necessarily represent the economic reality of such transactions.

Crude oil and natural gas prices were based on average (beginning of month basis) sales prices per bbl and MMBtu with the representative price of natural gas adjusted for basis premium and energy content to arrive at the appropriate net price. NGL prices were estimated as a percentage of the base crude oil price.

The following table summarizes the price measurements utilized, by product, with respect to our estimates of proved reserves as well as in the determination of the standardized measure of the discounted future net cash flows for the periods presented:

	Crude Oil		NGLs		Natural Gas
	$/bbl		$/bbl		$/MMBtu
December 31, 2020	$	39.54	$	7.51	$	1.99
December 31, 2021	$	66.57	$	22.99	$	3.60
December 31, 2022	$	93.67	$	35.42	$	6.36

40

The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved reserves for the periods presented:

	December 31,
	2022			2021			2020
Future cash inflows	$	18,918,984		$	12,157,254		$	3,832,194
Future production costs		(4,204,946	)		(2,938,528	)		(1,356,505	)
Future development costs		(2,876,385	)		(1,809,394	)		(926,904	)
Future net cash flows before income tax		11,837,653			7,409,332			1,548,785
Future income tax expense		(1,720,781	)		(978,510	)		(60,598	)
Future net cash flows		10,116,872			6,430,822			1,488,187
10% annual discount for estimated timing of cash flows		(5,268,597	)		(3,373,661	)		(837,897	)
Standardized measure of discounted future net cash flows	$	4,848,275		$	3,057,161		$	650,290

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following table summarizes the changes in the standardized measure of the discounted future net cash flows attributable to our proved reserves for the periods presented:

	Year Ended December 31,
	2022			2021			2020
Sales of oil and gas, net of production costs	$	(957,736	)	$	(476,734	)	$	(194,660	)
Net changes in prices and production costs		2,145,419			1,324,982			(950,201	)
Changes in future development costs		(81,629	)		(129,058	)		450,286
Extensions and discoveries		1,139,833			753,601			74,830
Development costs incurred during the period		380,463			131,743			102,459
Revisions of previous quantity estimates		(1,325,864	)		(188,804	)		(303,219	)
Purchases of reserves-in-place		348,926			926,169			—
Changes in production rates and all other		144,547			353,520			(282,055	)
Accretion of discount		341,872			65,755			160,010
Net change in income taxes		(344,717	)		(354,303	)		103,958
Net increase (decrease)		1,791,114			2,406,871			(838,592	)
Beginning of year		3,057,161			650,290			1,488,882
End of year	$	4,848,275		$	3,057,161		$	650,290

41

EXHIBIT 3

RANGER INTERIM FINANCIAL STATEMENTS

See attached.

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.

2

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.

3

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.

4

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.

5

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		Class A		Class B Common				Class A		Class B							Accumulated Other
		Shares		Common		Shares		Preferred		Common		Common		Paid-in		Retained			Comprehensive			Noncontrolling			Total
		Outstanding		Shares		Outstanding		Stock		Stock		Stock		Capital		Earnings			Loss			Interest			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.

6

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.

7

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.

8

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.

9

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.

10

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.

11

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.

12

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.

13

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%.

14

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.

15

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.

16

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.

17

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:

	Expiration of Contractual	Gross Minimum Volume Commitment (MVC)
Description of contractual arrangement	Arrangement	(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.

18

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.

19

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.

20

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.

21

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.

22

EXHIBIT 4

PRO FORMA FINANCIAL STATEMENTS

See attached.

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL INFORMATION

The following unaudited pro forma consolidated financial statements combine the historical financial information of Baytex Energy Corp. (“Baytex” or the “Company”) and Ranger Oil Corporation (“Ranger”) using the information from Baytex’s and Ranger’s unaudited historical interim financial statements as of the three month period ended March 31, 2023 and the audited historical financial statements as of and for the year ended December 31, 2022.

The Baytex unaudited interim consolidated statement of financial position as of March 31, 2023, the Baytex unaudited interim consolidated statement of income and comprehensive income for the three month period ended March 31, 2023, and the Baytex consolidated statement of income and comprehensive income for the year ended December 31, 2022, were prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”) and are presented in Canadian dollars (“CAD”). The Ranger unaudited interim consolidated balance sheet as of March 31, 2023, the Ranger unaudited interim consolidated statement of operations for the three month period ended March 31, 2023, and the Ranger consolidated statement of operations for the year ended December 31, 2022 were prepared in accordance with generally accepted accounting principles in the United States (“GAAP”) and are presented in U.S. dollars (“USD”). The unaudited pro forma consolidated financial statements are presented in CAD and in accordance with IFRS.

The Merger Transactions and Financing Transactions

On February 27, 2023, Baytex entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Ranger pursuant to which Ranger and Baytex would combine through the merger of Nebula Merger Sub, LLC, an indirect wholly owned subsidiary of Baytex (“merger sub”) with and into Ranger (the “company merger”), with Ranger continuing its existence as the surviving corporation following the company merger (the “surviving corporation”) as an indirect wholly owned subsidiary of Baytex. The transactions contemplated by the Merger Agreement, including the company merger, and the payment of related fees and expenses, are collectively referred to as the “Merger Transactions”.

On February 27, 2023, Canadian Imperial Bank of Commerce (“CIBC”), Royal Bank of Canada (“RBC”) and The Bank of Nova Scotia (“BNS”) entered into a debt commitment letter with Baytex providing for certain debt financing, the proceeds of which will be used, in part, to fund a portion of the cash consideration and expenses associated with the Merger Transactions. Additionally, on April 27, 2023, Baytex closed a private offering of US$800 million in aggregate principal amount of senior notes due 2030 (the “Baytex 8.500% Senior Notes”) that generated net proceeds of approximately US$776.7 million. The transactions contemplated by the debt commitment letter and the Baytex 8.500% Senior Notes, including the repayment, refinancing or redemption of existing Ranger and Baytex indebtedness, are referred to as the “Financing Transactions.”

On June 20, 2023, Baytex closed the Merger Transactions and the Financing Transactions.

Additional information on the Merger Transactions and the Financing Transactions is provided in Note 1 to the unaudited pro forma consolidated financial statements. Capitalized terms used in the unaudited pro forma consolidated financial statements that are not defined above are defined in Note 1. The unaudited pro forma consolidated financial statements include the following adjustments for the Merger Transactions and the Financing Transactions:

· total merger consideration of C$2.1 billion comprised of (i) the non-cash share value of C$1.3 billion, which is based on 7.49 Baytex common shares being issued per share of Ranger Class A common stock and 41.6 million shares of Ranger common stock outstanding on June 20, 2023 (including shares issued in the Opco Unit Exchange and shares issued in respect of certain outstanding Ranger restricted stock unit awards), multiplied by a share price of C$4.26, which is the closing share price of the Baytex common shares on the TSX on June 20, 2023; (ii) cash consideration of approximately C$0.7 billion, based on payment of US$13.31 per share of Ranger Class A common stock outstanding at closing and 41.6 million shares of Ranger common stock outstanding on June 20, 2023, converted from USD to CAD at a rate of $1.32, the USD/CAD exchange rate on June 20, 2023; and (iii) the non-cash share award consideration of C$43.8 million for Ranger equity awards outstanding at closing (other than those taken into account in the foregoing clauses (i) and (ii)), which were converted to 10.8 million time-vested Baytex share awards. The value of the non-cash share award consideration is calculated as the amortized value of the Baytex share awards issued based on the elapsed service period as of June 20, 2023 and the retained historical vesting dates of the Ranger awards.

· the use of proceeds of US$1.2 billion (C$1.6 billion) from the proceeds of the issuance of the Baytex 8.500% Senior Notes and other borrowings pursuant to the Financing Transactions to fund the US$0.6 billion (C$0.7 billion) cash portion of the merger consideration, to repay US$0.7 billion (C$0.9 billion) existing indebtedness of Ranger and to pay related fees, costs and expenses;

· adjustments to convert the historical financial statements of Ranger prepared in accordance with GAAP to IFRS and to conform to the accounting policies used by Baytex;

· adjustments to translate the Ranger unaudited interim consolidated balance sheet as of March 31, 2023 from USD to CAD using the period end exchange rate of $1.35, the Ranger unaudited interim consolidated statement of operations for the three month period ended March 31, 2023 from USD to CAD using the period average rate of $1.35, and the Ranger consolidated statement of operations for the year ended December 31, 2022 from USD to CAD using the 2022 average exchange rate of $1.30; and

· adjustments to present petroleum and natural gas sales and royalty expense on a gross basis on the unaudited pro forma consolidated statement of income, consistent with Baytex’s presentation practices; the Ranger historical consolidated statement of operations presents revenues net of royalty interests.

The unaudited pro forma consolidated financial statements contained herein do not reflect the costs of any integration activities or benefits that may result from the realization of future cost savings from operating efficiencies, or any other synergies that may result from the Merger Transactions.

The unaudited pro forma adjustments are based upon available information and certain assumptions as described in the accompanying notes to the unaudited pro forma consolidated financial statements, which Baytex management believes are reasonable. The unaudited pro forma consolidated financial statements are presented for informational purposes only and do not purport to represent what the actual combined financial information would have been if the Merger Transactions and the Financing Transactions actually occurred on the dates indicated, nor are they necessarily indicative of future combined results of operations or combined financial condition. Actual adjustments to the consolidated financial statements of Baytex will depend on a number of factors and actual results may differ materially from the estimates used within the accompanying unaudited pro forma consolidated financial statements.

In accordance with IFRS, Baytex will account for the Merger Transactions using the acquisition method of accounting for business combinations. Accordingly, the total purchase consideration paid by Baytex in connection with the Merger Transactions will be allocated to Ranger’s identifiable assets and liabilities based on their fair values as of the closing of the Merger Transactions. Any excess of the total purchase consideration over the fair value of the identifiable assets acquired and liabilities assumed from Ranger at their respective fair value will be recorded as goodwill. Conversely, any excess of the fair value of the identifiable assets acquired and liabilities assumed from Ranger at their respective fair values over the total purchase consideration would be recorded as a gain on acquisition. Ranger’s operating results will be included in Baytex’s consolidated results of operations only for periods subsequent to the closing of the Merger Transactions.

The unaudited pro forma consolidated financial information presented in this business acquisition report has been derived from the unaudited historical interim financial statements of Baytex and Ranger as of and for the three month period ended March 31, 2023 and from the audited historical financial statements of Baytex and Ranger for the year ended December 31, 2022. The unaudited pro forma interim consolidated statement of financial position as of March 31, 2023 presents the financial position of Baytex and Ranger giving pro forma effect to the Merger Transactions and the Financing Transactions as if the Merger Transactions and the Financing Transactions had occurred on March 31, 2023. The unaudited pro forma interim consolidated statement of income for the three month period ended March 31, 2023 and for the year ended December 31, 2022 present the results of operations of Baytex and Ranger giving pro forma effect to the Merger Transactions and the Financing Transactions as if the Merger Transactions and the Financing Transactions had occurred on January 1, 2022.

The unaudited pro forma consolidated financial statements should be read in conjunction with the disclosures contained in or incorporated by reference into Baytex’s registration statement on Form F-4 (File No. 333-271191) filed with the Securities and Exchange Commission (as amended, the “Form F-4”), as well as Baytex’s Information Circular and Proxy Statement dated April 3, 2023 (the “Information Circular”), including the disclaimers and risks as described therein. All references herein to other sections, documents incorporated by reference or similar references refer to such references as used in the Form F-4. The Form F-4 may be viewed under Baytex’s profile on EDGAR at www.sec.gov and the Information Circular may be viewed under Baytex’s profile on SEDAR and www.sedar.com. Neither the Form F-4 nor the Information Circular, nor any information included or incorporated by reference therein are incorporated by reference herein.

Unaudited Pro Forma Consolidated Statement of Financial Position

(in thousands of Canadian dollars, unless otherwise indicated) (unaudited)

As of March 31, 2023	Baytex			USD Ranger			CAD Ranger (Note 3a)			Presentation conforming adjustments			Note	CAD Ranger Adjusted (Note 3g)			Financing Transactions (Note 3h)		Note	Merger Transactions			Note	Pro forma consolidated
	IFRS			GAAP			GAAP			IFRS				IFRS										IFRS
ASSETS
Current assets
Cash	$	6,445		$	12,354		$	16,713		$	—			$	16,713		$	733,059	5a	$	(733,059	)	5a	$	23,158
Trade and other receivables		233,411			138,546			187,418			—				187,418			—			—				420,829
Financial derivatives		19,315			23,756			32,136			—				32,136			—			—				51,451
Prepaid and other assets		—			18,460			24,972			—				24,972			—			(24,972	)	5b		—
Assets held for sale		—			1,186			1,604			—				1,604			—			(1,604	)	5b		—
		259,171			194,302			262,843			—				262,843			733,059			(759,635	)			495,438
Non-current assets
Financial derivatives					216			292							292										292
Exploration and evaluation assets		165,958			—			—			—				—			—			—				165,958
Oil and gas properties		4,685,902			1,874,836			2,536,184			264,492		3d		2,800,676			—			424,554		5b		7,911,132
Other plant and equipment		6,646			17,278			23,373			(23,163	)	3b		210			—			—				6,856
Lease assets		8,164			—			—			19,205		3b		19,205			—			—				27,369
Deferred income tax asset		54,218			—			—			—		—		—			—							54,218
	$	5,180,059		$	2,086,632		$	2,822,692		$	260,534			$	3,083,226		$	733,059		$	(335,081	)		$	8,661,263
LIABILITIES
Current liabilities
Trade and other payables	$	269,177		$	239,792		$	324,379		$	(14,938	)	3b	$	309,441			—		$	104,839		5c	$	683,457
Financial derivatives		—			32,286			43,675			—				43,675			—			—				43,675
Lease obligations		4,699			—			—			14,938		3b		14,938			—			—				19,637
Asset retirement obligations		12,884			—			—			—				—			—			—				12,884
		286,760			272,078			368,054			—				368,054			—			104,839				759,653
Non-current liabilities
Other payables		1,845			13,131			17,763			(16,684	)	3b		1,079			—			—				2,924
Financial derivatives		—			1,320			1,786			—				1,786			—			—				1,786
Credit facilities		407,473			—			—			320,703		3b		320,703			284,339	5d		3,958		5d		1,016,473
Long-term notes		547,698			—			—			526,868		3b		526,868			448,720	5e		54,376		5e		1,577,662
Long-term debt, net		—			629,480			851,529			(851,529	)	3b		—			—			—				—
Lease obligations		3,596			—			—			4,563		3b		4,563			—			—				8,159
Asset retirement obligations		569,810			—			—			12,121		3b		12,121			—			104,090		5f		686,021
Deferred income tax liability		278,146			7,022			9,499			—				9,499			—			(100,426	)	5g		187,219
		2,095,328			923,031			1,248,631			(3,958	)			1,244,673			733,059			166,837				4,239,897
SHAREHOLDERS’ EQUITY
Shareholders’ capital		5,503,085			192			260			—				260			—			1,326,175		5h		6,829,520
Paid-in capital		—			216,941			293,467			(293,467	)	3b		—			—			—				—
Contributed surplus		89,879			—			—			293,467		3b		293,467			—			(249,639	)	5i		133,707
Accumulated other comprehensive income		755,647			(96	)		(130	)		—				(130	)		—			130		5i		755,647
Noncontrolling interest		—			631,763			854,617			—				854,617			—			(854,617	)	5i		—
Retained earnings (deficit)		(3,263,880	)		314,801			425,847			264,492		3d		690,339			—			(723,967	)	5j		(3,297,508	)
		3,084,731			1,163,601			1,574,061			264,492				1,838,553			—			(501,918	)			4,421,366
	$	5,180,059		$	2,086,632		$	2,822,692		$	260,534			$	3,083,226		$	733,059		$	(335,081	)		$	8,661,263

See accompanying notes to the unaudited pro forma consolidated financial statements.

Unaudited Pro Forma Consolidated Statement of Income

(in thousands of Canadian dollars, except per common share amounts and weighted average common shares or
if otherwise indicated) (unaudited)

Three Month Period Ended March 31, 2023	Baytex			USD Ranger			CAD Ranger (Note 3a)			Presentation conforming adjustments			Note	CAD Ranger Adjusted Balances (Note 3g)			Financing Transactions (Note 3h)			Notes	Merger Transactions			Note	Pro forma consolidated
	IFRS			GAAP			GAAP			IFRS				IFRS											IFRS
Revenue, net of royalties
Petroleum and natural gas sales	$	555,336		$	258,148		$	349,197		$	102,312		3e	$	451,509		$	—			$	—			$	1,006,845
Royalties		(93,253	)		—			—			(118,360	)	3c,e		(118,360	)		—				—				(211,613	)
		462,083			258,148			349,197			(16,048	)			333,149			—				—				795,232
Expenses
Operating		112,408			—			—			46,219		3c		46,219			—				—				158,627
Transportation		17,005			—			—			13,770		3c		13,770			—				—				30,775
Lease Operating		—			29,990			40,567			(40,567	)	3c		—			—				—				—
Gathering, processing and transportation		—			10,180			13,770			(13,770	)	3c		—			—				—				—
Production and ad valorem taxes		—			16,042			21,700			(21,700	)	3c		—			—				—				—
Blending and other		59,681			—			—			—				—			—				—				59,681
General and administrative		11,734			12,668			17,136			(6,108	)	3c		11,028			—				—				22,762
Transaction costs		8,871			—			—			3,334		3c		3,334			—				(12,205	)	6a		—
Exploration and evaluation		163			—			—			—				—			—				—				163
Depletion and depreciation		165,999			85,303			115,389			27,847		3d		143,236			—				12,684		6b		321,919
Share-based compensation		9,823			—			—			2,774		3c		2,774			—				—				12,597
Financing and interest		23,725			14,718			19,909			1,224		3f		21,133			18,157		6c		—				63,015
Financial derivatives (gain) loss		(14,625	)		(25,658	)		(34,708	)		—				(34,708	)		—				—				(49,333	)
Foreign exchange gain		(63	)		—			—			—				—			—				—				(63	)
Loss on dispositions		336			—			—			—				—			—				—				336
Other (income) expense		(1,058	)		123			166			—				166			—				—				(892	)
		393,999			143,366			193,929			13,023				206,952			18,157				479				619,587
Net income before income taxes		68,084			114,782			155,268			(29,071	)			126,197			(18,157	)			479				175,645
Income tax expense
Current income tax expense		1,120			185			250			—				250			—				—				1,370
Deferred income tax expense		15,523			806			1,090			—				1,090			—				22,304		6d		38,917
		16,643			991			1,340			—				1,340			—				22,304				40,287
Net income	$	51,441		$	113,791		$	153,928		$	(29,071	)		$	124,857			(18,157	)		$	(22,783	)		$	135,358
Net income per common share
Basic	$	0.09																							$	0.16
Diluted	$	0.09																							$	0.16
Weighted average common shares
Basic		545,062																						6e		856,432
Diluted		548,078																						6e		870,242

See accompanying notes to the unaudited pro forma consolidated financial statements.

Unaudited Pro Forma Consolidated Statement of Income

(in thousands of Canadian dollars, except per common share amounts and weighted average common shares or
if otherwise indicated) (unaudited)

Year Ended December 31, 2022	Baytex			USD Ranger			CAD Ranger (Note 3a)			Presentation conforming adjustments			Note	CAD Ranger Adjusted Balances (Note 3g)			Financing Transactions (Note 3h)			Notes	Merger Transactions			Note	Pro forma consolidated
	IFRS			GAAP			GAAP			IFRS				IFRS											IFRS
Revenue, net of royalties
Petroleum and natural gas sales	$	2,889,045		$	1,145,189		$	1,490,120		$	436,526		3e	$	1,926,646		$	—			$	—			$	4,815,691
Royalties		(562,964	)		—			—			(505,147	)	3c,e		(505,147	)		—				—				(1,068,111	)
		2,326,081			1,145,189			1,490,120			(68,621	)			1,421,499			—				—				3,747,580
Expenses
Operating		422,666			—			—			125,292		3c		125,292			—				—				547,958
Transportation		48,561			—			—			45,335		3c		45,335			—				—				93,896
Lease Operating		—			85,792			111,633			(111,633	)	3c		—			—				—				—
Gathering, processing and transportation		—			36,698			47,751			(47,751	)	3c		—			—				—				—
Production and ad valorem taxes		—			61,377			79,864			(79,864	)	3c		—			—				—				—
Blending and other		189,454			—			—			—				—			—				—				189,454
General and administrative		50,270			40,972			53,313			(7,227	)	3c		46,086			—				—				96,356
Transaction costs		—			—			—			—				—			—				100,843		6a		100,843
Exploration and evaluation		30,239			—			—			—				—			—				—				30,239
Depletion and depreciation		587,050			244,455			318,085			119,720		3d		437,805			—				71,376		6b		1,096,231
Impairment reversal		(267,744	)		—			—			—				—			—				—				(267,744	)
Share-based compensation		29,056			—			—			7,227		3c		7,227			—				—				36,283
Financing and interest		104,817			46,774			60,862			5,626		3f		66,488			55,002		6c		—				226,307
Financial derivatives loss		199,010			162,672			211,669			—				211,669			—				—				410,679
Foreign exchange loss (gain)		43,441			—			—			—				—			—				—				43,441
Gain on dispositions		(4,898	)		—			—			—				—			—				—				(4,898	)
Other expense (income)		3,244			(2,255	)		(2,934	)		—				(2,934	)		—				—				310
		1,435,166			676,485			880,243			56,725				936,968			55,002				172,219				2,599,355
Net income before income taxes		890,915			468,704			609,877			(125,346	)			484,531			(55,002	)			(172,219	)			1,148,225
Income tax expense
Current income tax expense		3,594			764			994			—				994			—				—				4,588
Deferred income tax expense		31,716			3,422			4,453			—				4,453			—				51,512		6d		87,681
		35,310			4,186			5,447			—				5,447			—				51,512				92,269
Net income	$	855,605		$	464,518		$	604,430		$	(125,346	)		$	479,084			(55,002	)		$	(223,731	)		$	1,056,956
Net income per common share
Basic	$	1.53																							$	1.21
Diluted	$	1.52																							$	1.19
Weighted average common shares
Basic		557,986																						6e		869,356
Diluted		563,835																						6e		885,999

See accompanying notes to the unaudited pro forma consolidated financial statements.

Baytex Energy Corp.

Notes to the Unaudited Pro Forma Consolidated Financial Statements
As of and for the three month period ended March 31, 2023 and for the year ended December 31, 2022

1. DESCRIPTION OF THE TRANSACTIONS

On June 20, 2023, Baytex completed the transactions contemplated by the Merger Agreement, pursuant to which Ranger and Baytex combined through the merger of merger sub, an indirect wholly owned subsidiary of Baytex, with and into Ranger, with Ranger continuing its existence as the surviving corporation following the company merger as an indirect wholly owned subsidiary of Baytex. On June 16, 2023, the holders of shares of Ranger Class B common stock and common units in ROCC Energy Holdings, L.P. exercised their right to exchange (the “Opco Unit Exchange”) all such shares of Ranger Class B common stock and Opco common units for Ranger Class A common stock. To effect the company merger, each share of Ranger Class A common stock, issued and outstanding immediately prior to the merger effective time (including any shares issued pursuant to the Opco Unit Exchange other than certain excluded shares as described in the Merger Agreement) were converted into the right to receive (i) 7.49 validly issued, fully paid and non-assessable Baytex common shares (the “share consideration”) and (ii) US$13.31 in cash, without interest (the “cash consideration” and, together with the share consideration, the “merger consideration”).

The merger consideration has been valued at C$2.1 billion (US$1.6 billion) comprised of (i) the non-cash share consideration of C$1.3 billion, which is based on 7.49 Baytex common shares being issued per share of Ranger Class A common stock and 41.6 million shares of Ranger common stock, including shares issued in the Opco Unit Exchange and shares issued in respect of certain outstanding Ranger restricted stock unit awards, outstanding as of June 20, 2023, multiplied by a share price of C$4.26, which is the closing share price of the Baytex common shares on the TSX on June 20, 2023; (ii) cash consideration of approximately C$0.7 billion, based on payment of US$13.31 per share of Ranger Class A common stock outstanding at closing and 41.6 million shares of Ranger common stock outstanding on June 20, 2023, converted from USD to CAD at a rate of $1.32, the USD/CAD exchange rate on June 20, 2023; and (iii) non-cash share award consideration of C$43.8 million for Ranger equity awards outstanding at closing (other than those taken into account in the foregoing clauses (i) and (ii)), which were converted to 10.8 million time-vested Baytex share awards. The value of this consideration is calculated as the amortized value of the Baytex share awards issued based on the elapsed service period as of June 20, 2023 and the retained historical vesting dates of the Ranger awards.

On February 27, 2023, CIBC, RBC and BNS entered into a debt commitment letter with Baytex providing for certain debt financing, the proceeds of which will be used, in part, to fund a portion of the cash consideration and expenses of the Merger Transactions. Pursuant to the debt commitment letter, CIBC, RBC and BNS committed to provide a new US$1.1 billion revolving credit facility (the “Baytex new bank facility”) and a US$150 million term credit facility (the “Baytex term loan”), and CIBC and RBC committed to provide a 364-day bridge loan facility in an aggregate principal amount of US$500 million (the “Baytex bridge loan”). The Baytex term loan bears interest at SOFR plus a margin. The Baytex new bank facility bears interest at SOFR plus a margin.

Additionally, on April 27, 2023, Baytex closed a private offering of US$800 million in aggregate principal amount of senior notes due 2030 (the “Baytex 8.500% Senior Notes”). The Baytex 8.500% Senior Notes were priced at 98.709% of par, will bear interest at a rate of 8.5% per annum and mature on April 30, 2030. As a result of this offering the Baytex bridge loan was cancelled.

The proceeds from the Baytex 8.500% Senior Notes and Baytex term loan, along with a draw under the Baytex new bank facility were used to pay the cash consideration, refinance and extinguish the existing debt of Ranger and pay related fees and expenses.

2. BASIS OF PRESENTATION

These unaudited pro forma consolidated financial statements (the “pro forma information”) of Baytex have been prepared in connection with the consummation of the Merger Transactions and the Financing Transactions for inclusion in Baytex’s business acquisition report. The pro forma information gives pro forma effect to the Merger Transactions and the Financing Transactions by applying pro forma adjustments to Baytex’s and Ranger’s historical consolidated financial statements in accordance with IFRS. The pro forma reporting entity includes Baytex and its subsidiaries as of March 31, 2023 as well as Ranger and its subsidiaries as of March 31, 2023.

The unaudited pro forma consolidated statement of financial position as of March 31, 2023 gives effect to the Merger Transactions and the Financing Transactions and assumptions described herein as if the Merger Transactions and Financing Transactions had occurred on March 31, 2023. The unaudited pro forma consolidated statement of income for the three month period ended March 31, 2023 and for the year ended December 31, 2022 give effect to the Merger Transactions and the Financing Transactions and assumptions described herein as if the Merger Transactions and the Financing Transactions had occurred on January 1, 2022. The accounting policies used in the preparation of the pro forma financial information are those set out in Baytex’s audited consolidated financial statements as of and for the year ended December 31, 2022, which were prepared in accordance with IFRS. The pro forma information has been prepared from information derived from and should be read in conjunction with:

· Baytex’s unaudited interim consolidated statement of financial position as of March 31, 2023, Baytex’s unaudited interim consolidated statement of income and comprehensive income for the three month period ended March 31, 2023, and Baytex’s audited consolidated statement of income and comprehensive income for the year ended December 31, 2022, together with the accompanying notes (collectively referred to as the “Baytex historical consolidated financial statements”); and

· Ranger’s unaudited interim consolidated balance sheet as of March 31, 2023, Ranger’s unaudited interim consolidated statement of operations for the three month period ended March 31, 2023, and Ranger’s audited consolidated statement of operations for the year ended December 31, 2022, together with the accompanying notes (collectively referred to as the “Ranger historical consolidated financial statements”).

The Baytex historical consolidated financial statements were prepared in accordance with IFRS and are presented in CAD. The Ranger historical consolidated financial statements were prepared in accordance with GAAP and are presented in USD. For purposes of preparing the unaudited pro forma consolidated financial statements, adjustments have been made to the Ranger historical consolidated financial statements to convert those financial statements to IFRS and present the information in CAD. In addition, adjustments have been made to conform the accounting policies of Ranger to the accounting policies used by Baytex as described in the notes to the Baytex historical consolidated financial statements.

The unaudited pro forma consolidated financial statements have been prepared in accordance with IFRS, using the acquisition method of accounting in accordance with IFRS 3, Business Combinations (“IFRS 3”), which will establish a new basis of accounting for all of Ranger’s identifiable assets acquired and liabilities that will be assumed at fair value as of the closing of the Merger Transactions and are subject to change. Baytex will be the acquirer for accounting purposes and Ranger will be the acquiree, based on factors considered at the time of preparation. The purchase accounting is dependent upon certain valuations and other studies that have yet to progress to a stage where there is sufficient information for a definitive measurement. The purchase equation is preliminary as management has not yet completed the valuation procedures as of this report and the various assets and liabilities of Ranger have been measured based on preliminary estimates.

Differences between these preliminary estimates and the final purchase accounting will occur, and these differences could have a material impact on the accompanying unaudited pro forma consolidated financial statements and the future results of operations and financial results of Baytex. The unaudited pro forma consolidated financial statements have not been adjusted to give effect to certain expected financial benefits of the Merger Transactions, such as tax savings, cost synergies or revenue enhancements, or the anticipated costs to achieve these benefits, including the cost of integration or restructuring activities.

The unaudited pro forma adjustments are based upon available information and certain assumptions as described in the accompanying notes to the unaudited pro forma consolidated financial statements, which Baytex management believes are reasonable. The unaudited pro forma consolidated financial statements are presented for informational purposes only and do not purport to represent what the actual combined financial information would have been if the Merger Transactions and the Financing Transactions actually occurred on the dates indicated, nor are they necessarily indicative of future combined results of operations or combined financial condition. If the proposed Merger Transactions and Financing Transactions are completed, the actual adjustments to the consolidated financial statements of Baytex will depend on a number of factors and actual results may differ materially from the estimates used within the accompanying unaudited pro forma consolidated financial statements.

3. PRESENTATION CONFORMING ADJUSTMENTS TO THE UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

The Ranger historical consolidated financial statements were prepared in accordance with GAAP and presented in USD. For purposes of the unaudited pro forma consolidated financial statements, those financial statements have been adjusted to conform to the recognition, measurement, and presentation requirements of IFRS and presented in CAD, which is the presentation currency of Baytex. The adjustments made to the Ranger historical consolidated financial statements are described below including certain adjustments to conform with IFRS (“GAAP adjustments”) and adjustments to align with Baytex’s presentation and accounting policies.

a. The Ranger interim consolidated balance sheet as of March 31, 2023 was translated from USD to CAD using the period end exchange rate of $1.35. The Ranger interim consolidated statement of operations for the three month period ended March 31, 2023 was translated from USD to CAD using the period average exchange rate of $1.35. The Ranger consolidated statement of operations for the year ended December 31, 2022 was translated from USD to CAD using the 2022 average exchange rate of $1.30.

b. Reflects presentation conforming adjustments to reclassify and/or combine certain asset and liability balances presented separately, or under different headings, on the face of the Ranger consolidated balance sheet as of March 31, 2023.

c. Reflects presentation conforming adjustments to reclassify and combine certain income and expense amounts presented separately, or under different headings, on the face of the Ranger consolidated statement of operations for the three month period ended March 31, 2023 and for the year ended December 31, 2022.

d. The unaudited pro forma consolidated financial statements include GAAP adjustments, net of estimated depletion on those adjustments, including:

· Under IFRS, each cash generating unit comprising oil and gas properties is tested for impairment when indicators are identified. An impairment loss is recognized if the carrying amount of the asset exceeds its recoverable amount, which is the higher of its fair value less costs to sell and its value in use. Subsequent reversals of impairment losses are allowed, but limited to cumulative historical impairment losses, net of subsequent depletion. Conversely, under GAAP, impairment testing is performed at the asset group level, which may consist of multiple assets with similar characteristics. Impairment losses are recognized if the carrying amount of the asset group exceeds proved reserves discounted at 10%, and subsequent reversals of impairment losses are prohibited. Using preliminary estimates, the fair value of the oil and gas properties of Ranger exceeds its carrying value as of January 1, 2022 resulting in a $264.5 million impairment reversal under IFRS which represents all historical accumulated impairments net of depletion. No such reversal would be recognized under GAAP.

· Under GAAP, depletion is calculated using proved reserves and associated finding and development costs, while under IFRS the Company’s accounting policy is to use proved and probable reserves and associated finding and development costs. The impact of these GAAP differences, being the reversal of impairment and the change in reserves and associated finding and development costs, resulted in $27.8 million of additional depletion of oil and gas properties for the three month period ended March 31, 2023 and $119.7 million of additional depletion of oil and gas properties for the year ended December 31, 2022.

e. Reflects the adjustment to present petroleum and natural gas sales and royalty expense on a gross basis on the pro forma consolidated statement of income, consistent with Baytex’s presentation practices. The Ranger historical consolidated statement of operations presents revenues net of royalty interests.

f. Reflects the expensing of interest related to unproved properties which was capitalized by Ranger under U.S. GAAP full-cost method of accounting.

g. Reflects Ranger historical financial information, converted to CAD and reflecting accounting and IFRS adjustments.

h. The Financing Transactions are predicated on the assumption that the Merger Transactions occur contemporaneously.

4. ESTIMATED PRELIMINARY PURCHASE EQUATION

The Merger Transactions will be accounted for as a business combination using the acquisition method of accounting whereby the assets acquired and liabilities assumed are recognized at their fair value, with limited exceptions. The fair values assigned to the net assets acquired are preliminary and based on estimates and assumptions based on information available at the time of preparation of these unaudited pro forma consolidated financial statements. Accordingly, these estimates may be adjusted in the future.

Consideration (in thousands of Canadian dollars)
Share consideration	$	1,326,435
Cash consideration		733,059
Share award consideration		43,828
Total consideration	$	2,103,322
Fair value of net assets of Ranger acquired (in thousands of Canadian dollars)
Oil and gas properties	$	3,165,805
Other plant and equipment		210
Lease assets		19,205
Cash		16,713
Trade and other receivables		187,418
Trade and other payables		(360,846	)
Lease obligations		(19,501	)
Other payables		(1,079	)
Financial derivatives		(13,032	)
Ranger credit facility(1)		(324,660	)
Ranger senior notes(1)		(581,244	)
Asset retirement obligations		(56,788	)
Deferred income tax asset		71,121
Net assets acquired	$	2,103,322

(a) Repayment of the Ranger credit facility and the Ranger senior notes is included with the presentation of Financing Transactions in the Unaudited Pro Forma Consolidated Statement of Financial Position.

The following assumptions have been applied in determining the above estimates:

a. Merger Consideration and Purchase Equation

The total merger consideration of approximately C$2.1 billion includes share consideration of C$1.3 billion, cash consideration of C$0.7 billion and share award consideration of C$43.8 million. The sources and uses of financing are set forth in the following table and are converted from USD to CAD at a rate of $1.32 to reflect the Merger Transactions and Financing Transactions in the presentation currency of Baytex.

Sources (in thousands of Canadian dollars)
Accounts payable and accrued liabilities	$	104,839
Baytex new bank facility (principal excluding deferred issue costs)		396,228
Baytex term loan		202,913
Baytex 8.500% Senior Notes		1,068,229
Baytex common shares		1,326,435
Baytex share awards		43,828
Total sources	$	3,142,472
Uses (in thousands of Canadian dollars)
Purchase price	$	2,103,322
Ranger credit facilities (principal)		324,660
Ranger senior notes (principal including change in control premium)		581,244
Transaction and financing costs		133,246
Total uses	$	3,142,472

The share consideration of C$1.3 billion was determined based on 7.49 Baytex common shares being issued per share of Ranger Class A common stock outstanding and 41,571,396 shares of Ranger common stock issued and outstanding on June 20, 2023, including (i) 19,009,954 shares of Ranger Class A common stock and (ii) 22,548,998 shares of Ranger Class B common stock and 12,444 DSUs that were converted into shares of Ranger Class A common stock at closing, for an aggregate total of 311,369,756 Baytex common shares issued. The 311.4 million Baytex common shares issued is multiplied by the share price of C$4.26, which is the closing price of the Baytex common shares on the TSX on June 20, 2023 to calculate total share consideration. The cash consideration is based on payment equal to US$13.31 per share of Ranger common stock outstanding and 41.6 million shares of Ranger common stock outstanding on June 20, 2023, converted from USD to CAD at a rate of $1.32. The non-cash share award consideration of C$43.8 million relates to the amortized value of Ranger equity awards outstanding at closing (other than DSUs that were converted into shares of Ranger Class A common stock at closing), which were converted into 10.8 million time-vested Baytex share awards. The value of the share award consideration is calculated as the amortized value of the Baytex share awards issued based on the elapsed service period as of June 20, 2023 and the retained historical vesting dates of the Ranger awards.

Determinations of fair value often require management to make assumptions and estimates about future events. The purchase equation is preliminary as management has not yet completed the valuation procedures as of the date of this report. As described in Note 2, the final purchase equation will be based on the fair value of the net assets purchased at the closing date of the company merger and other information available at that time. There may be material differences from this pro forma purchase price equation as a result of finalizing the valuation.

b. Oil and gas properties

The fair value of oil and gas properties acquired was estimated based on their fair value calculated as the present value of the estimated future cash flows after-tax associated with proved plus probable oil and gas reserves discounted at 13.1%. Baytex’s independent reserve evaluators have provided a preliminary assessment of Ranger’s proved plus probable reserves as of December 31, 2022, which was adjusted for forecasted commodity prices as of June 20, 2023.

A 1% change in the discount rate would have a $114.5 million impact on the fair value of oil and gas properties.

c. Other plant and equipment, working capital, financial derivatives, lease assets, lease obligations, credit facilities and senior notes

Baytex has assumed that the carrying value is equal to fair value for other plant and equipment, working capital (including cash, trade and other receivables, trade and other payables, and other payables), financial derivatives, lease assets and lease obligations. Additionally, the fair value of each of the Ranger credit facilities and the Ranger senior notes is assumed to be equal to the principal balance outstanding at March 31, 2023, plus the change in control offer premium Baytex is obligated to make pursuant to the terms of the Ranger senior notes. Trade and other payables also includes $51.4 million for transaction costs directly attributable to the Merger Transactions expected to be incurred by Ranger prior to closing.

d. Asset retirement obligations

The fair value of asset retirement obligations was determined based on preliminary estimates of expected expenditures as of March 31, 2023 and discounted using a credit-adjusted risk-free rate of 7.0%.

e. Deferred income tax asset

The deferred income tax asset was determined by applying statutory tax rates to the temporary differences between the fair value of assets acquired and liabilities assumed and the related tax pools. Ranger previously calculated the deferred tax liability based on the public share of these temporary differences, which was approximately 46% at March 31, 2023. Following the Merger Transactions the noncontrolling interest reported in Ranger’s historical consolidated financial statements will be converted to common interest. The value of the deferred tax asset includes the increase in temporary differences previously attributed to the noncontrolling interest, the increase in tax pools inherited following the close of the Merger Transactions, as well as the recognition of deferred tax assets which were previously unrecognized. The federal deferred tax assets which were previously unrecognized are now fully offset by federal deferred tax liabilities, which enable them to be recognized in full.

The deferred tax asset does not adjust for potential synergies that could result from restructuring or other discretionary actions, as there are currently not enough supportable facts to reliably estimate these values. Only amounts that are directly attributable to the Merger Transactions and factually supportable have been adjusted for.

The deferred tax assets acquired of $71.1 million is primarily related to U.S. federal income taxes. At March 31, 2023, the Baytex historical deferred tax liability associated with U.S. federal income taxes exceeds the deferred tax asset acquired and can therefore be used to reduce Baytex’s deferred tax liability as at March 31, 2023. As such, the deferred tax asset acquired has been presented as a reduction to the deferred tax liability in the unaudited pro forma statement of financial position.

5. PRO FORMA ADJUSTMENTS TO THE UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF FINANCIAL POSITION

The unaudited pro forma consolidated statement of financial position as of March 31, 2023 gives effect to the following assumptions and adjustments which are considered directly attributable to the Merger Transactions and the Financing Transactions and factually supportable.

a. Cash

Financing Transactions

Reflects a net increase in cash of $733.1 million associated with Financing Transactions described in Note 1 including an increase of $599.1 million related to a draw on the Baytex credit facilities and an increase of $1.1 billion related to the issuance of the Baytex 8.500% Senior Notes, partially offset by a $324.7 million decrease related to the repayment of the Ranger credit facilities and a $581.2 million decrease related to the extinguishment of the Ranger senior notes, inclusive of the applicable make-whole-premium. The Baytex 8.500% Senior Notes are net of $16.2 million financing costs which are capitalized against the notes and are recognized as non-cash interest expense over the term of the note. These notes are assumed to be received and repaid in cash.

Merger Transactions

Concurrent with the receipt of cash from the Financing Transactions described above, the net proceeds of $733.1 million were used to fund the cash portion of the purchase price consideration.

b. Oil and gas properties

Reflects a $365.1 million increase to the carrying value of Ranger’s oil and gas properties to adjust to their estimated fair value based on preliminary estimates, as described in the purchase equation in Note 4, as well as a $59.4 million increase related to the subsequent remeasurement of asset retirement obligations described further in Note 5f. Balances historically presented as prepaid and other assets and assets held for sale have been valued in conjunction with oil and gas properties and reclassified within the unaudited pro forma consolidated statement of financial position.

c. Trade and other Payables

Reflects estimated transaction costs, which are directly attributable to the Merger Transactions, incurred by both Ranger and Baytex prior to close. The Ranger transaction costs of $51.4 million attributable to the Merger Transactions are included in trade and other payables in the purchase equation under Note 4. Baytex transaction costs incurred as a result of Merger Transactions of $53.4 million have been included in trade and other payables.

d. Baytex credit facilities

Financing Transactions

The net increase in credit facilities of $284.3 million reflects the draw on the Baytex new bank facility which was used, together with the cash generated in Financing Transactions as described in Note 5e of $448.7 million, to fund the cash portion of the merger consideration of $733.1 million. The net increase in credit facilities also includes the repayment of the Ranger credit facility of $324.7 million as shown in the purchase price equation (Note 4) and the financing costs associated with the Baytex new bank facility of $12.2 million, funded by a total draw on the Baytex new bank facility of $599.1 million.

Merger Transactions

Reflects a $4.0 million increase in credit facilities due to the elimination of Ranger historical debt issue costs as a result of the fair value adjustment in the purchase price equation (Note 4).

e. Long-term notes

Financing Transactions

Reflects a net increase in long-term notes of $448.7 million associated with Financing Transactions described in Note 1 including an increase of $1.1 billion related to the issuance of the Baytex 8.500% Senior Notes, partially offset by a $581.2 million decrease related to the extinguishment of the Ranger senior notes. The Baytex 8.500% Senior Notes are net of financing costs which are capitalized against the Baytex 8.500% Senior Notes and are recognized as non-cash interest expense over the term of the note. The issuance of the Baytex 8.500% Senior notes are assumed to be received in cash and the repayment of the Ranger senior notes are assumed to be paid in cash.

Merger Transactions

Reflects a $14.2 million increase in long-term notes due to the elimination of Ranger historical debt issue costs along with $40.1 million associated with the recognition of the applicable make-whole-premium as a result of the fair value adjustment in the purchase price equation (Note 4).

f. Asset retirement obligations

Reflects an increase in asset retirement obligations to adjust to its estimated fair value based on preliminary estimates discounted using a credit-adjusted risk-free rate, as described in Note 4. Additionally, subsequent to the initial fair value measurement, the obligations acquired were remeasured using a risk-free rate of 3.0%, resulting in a $59.4 million increase in asset retirement obligations and oil and gas properties.

g. Deferred income tax liability

The decrease in deferred tax liability is mostly related to fair value assigned in the purchase price equation as described in Note 4, as well as the deferred tax consequences of transaction costs incurred by Baytex prior to close. As a result of the Merger Transactions, a deferred tax asset of $71.1 million has been generated related to U.S. federal income taxes. After closing, the deferred tax asset acquired can be used to reduce Baytex’s historical deferred tax liability related to U.S. federal income taxes. Similarly, the deferred tax asset generated in Canada as a result of Baytex transaction costs incurred as part of the Merger Transactions of $19.8 million can be used to reduce Baytex’s historical deferred tax liability in Canada. As a result, no incremental deferred tax assets are included in the pro forma consolidated statement of financial position. Since the deferred tax assets are fully offset by deferred tax liabilities in the same jurisdictions, the Merger Transactions have instead been classified as a reduction to deferred tax liabilities.

h. Shareholders’ capital

Reflects an increase due to the issuance of Baytex common shares to Ranger shareholders as outlined in the calculation of merger consideration per Note 1, partially offset by the elimination of historical Ranger common stock.

i. Other equity

The decrease in other equity, including contributed surplus, accumulated other comprehensive income and noncontrolling interest, reflects adjustments for the following:

i. share award consideration related to the fair value of Baytex share awards to be granted to holders of Ranger equity awards;

ii. the elimination of Ranger additional paid-in capital and accumulated other comprehensive income; and

iii. the elimination of the noncontrolling interest, which will cease to exist upon the conversion of Ranger Class B common stock to Ranger Class A common stock immediately prior to the closing of the company merger.

j. Retained earnings

The decrease in retained earnings reflects adjustments for the following:

i. a decrease to reflect the elimination of Ranger historical retained earnings; and

ii. a decrease to reflect $53.4 million transaction costs incurred by Baytex prior to close net of tax of $19.8 million.

6. PRO FORMA ADJUSTMENTS TO THE UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME

The unaudited pro forma consolidated statement of income for the three month period ended March 31, 2023 and the unaudited pro forma consolidated statement of income for the year ended December 31, 2022 gives effect to the following assumptions and adjustments, which are considered directly attributable to the Merger Transactions and the Financing Transactions. In addition, the Ranger historical consolidated financial statements were prepared in accordance with GAAP. For purposes of the unaudited pro forma consolidated financial statements, those financial statements have been adjusted to conform to the recognition, measurement, and presentation requirements of IFRS.

a. Transaction costs

The increase in transaction costs relates to estimated fees and expenses expected to be incurred by both Baytex and Ranger which are considered directly attributable to the Merger Transactions and are not expected to recur beyond 12 months after closing. Transaction costs include advisory fees, legal fees, tax fees and other professional fees, as well as post-combination severance costs for certain executives which the Company has decided to terminate upon closing. Transaction costs incurred by Baytex and Ranger during the three month period ended March 31, 2023 have been adjusted from the unaudited pro forma consolidated statement of income for the three month period ended March 31, 2023 as they have been included in the unaudited pro forma consolidated statement of income for the year ended December 31, 2022.

b. Depletion and depreciation

Depletion and depreciation expense for Ranger has increased assuming that the fair value of oil and gas properties reflected in the purchase equation were acquired on January 1, 2022. The depletion rate has been calculated using opening proved plus probable reserves acquired in conjunction with the preliminary estimate of reserves acquired which resulted in $12.7 million of additional depletion of oil and gas properties for the three month period ended March 31, 2023 and $71.3 million of additional depletion of oil and gas properties for the year ended December 31, 2022.

c. Financing and interest

Reflects an increase in financing and interest expense of $18.2 million for the three month period ended March 31, 2023 and an increase of $55.0 million for the year ended December 31, 2022 as a result of an increase in outstanding debt following the issuance of the Baytex 8.500% Senior Notes and the increase in debt following payment of purchase price consideration, partially offset by the repayment of the Ranger senior notes. An average SOFR rate of 4.5%, plus applicable margins has been used to calculate interest on the estimated average balance outstanding on the Baytex term loan and the Baytex new bank facility for the three month period ended March 31, 2023. An average SOFR rate of 1.8%, plus applicable margins, has been used to calculate interest on the estimated average balance outstanding on the Baytex term loan and Baytex new bank facility for the year ended December 31, 2022.

A change in the interest rate of 1/8 percent results in a change in financing and interest expense of $0.8 million for the three month period ended March 31, 2023 and a change in financing and interest expense of $3.4 million for the year ended December 31, 2022.

d. Deferred income tax expense

The increase in deferred tax expense reflects changes to the fair value of temporary differences, as described in Note 5g, assuming the Merger Transactions closed at the beginning of each period presented. Following the close of the Merger Transactions, Ranger would no longer have any accumulated unrecognized deferred tax assets, and therefore the expense reflects Ranger net income for the three month period ended March 31, 2023 and the year ended December 31, 2022 multiplied by the relevant statutory tax rate.

e. Weighted average common shares

For the three month period ended March 31, 2023, pro forma basic weighted average shares outstanding includes 545.1 million basic weighted average shares outstanding as disclosed in the Baytex historical consolidated financial statements for the three month period ended March 31, 2023 plus 311.4 million common shares issued in conjunction with the merger consideration. Pro forma diluted weighted average shares outstanding includes 548.1 million diluted weighted average shares outstanding as disclosed in the Baytex historical consolidated financial statements for the period ended March 31, 2023 plus 311.4 million common shares issued and the conversion of Ranger equity awards into 10.8 million share awards of Baytex.

For the year ended December 31, 2022, pro forma basic weighted average shares outstanding includes 558.0 million basic weighted average shares outstanding as disclosed in the Baytex historical consolidated financial statements for the year-ended December 31, 2022 plus 311.4 million common shares issued in conjunction with the merger consideration. Pro forma diluted weighted average shares outstanding includes 563.8 million diluted weighted average shares outstanding as disclosed in the Baytex historical consolidated financial statements for the year-ended December 31, 2022 plus 311.4 million common shares issued and the conversion of Ranger equity awards into 10.8 million share awards of Baytex.