PRIMEENERGY RESOURCES CORP 10-K

Item 9A. CONTROLS AND PROCEDURES. As of the end of the period covered by this Annual Report on Form 10-K, our principal executive officer and principal financial officer have evaluated the effectiveness of our “disclosure controls and procedures” (“Disclosure Controls”). Disclosure Controls, as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are procedures that are designed with the objective of ensuring that information required to be disclosed in our reports filed under the Exchange Act, such as this Annual Report, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure Controls are also designed with the objective of ensuring that such information is accumulated and communicated to our management, including the chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure. Our management, including the chief executive officer and chief financial officer, does not expect that our Disclosure Controls will prevent all error and all fraud. A control system, no matter how well conceived and 41 Table of Contents operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Members of our management, including our chief executive officer and chief financial officer, have evaluated the effectiveness of our disclosure controls and procedures, as defined by paragraph (e) of Exchange Act Rules 13a-15 or 15d-15, as of December 31, 2022 the end of the period covered by this Report. Based upon that evaluation, these officers concluded that our disclosure controls and procedures were effective as of December 31, 2022. Management’s Report on Internal Control Over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance that assets are safeguarded against loss from unauthorized use or disposition, transactions are executed in accordance with appropriate management authorization and accounting records are reliable for the preparation of financial statements in accordance with U.S. generally accepted accounting principles. 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. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2022. Management based this assessment on criteria for effective internal control over financial reporting described in “Internal Control – Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of our internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors. Based on this assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2022. This Annual Report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report. There have been no changes in our internal controls over financial reporting during the fourth fiscal quarter ended December 31, 2022 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. Item 9B. OTHER INFORMATION. None. 42 Table of Contents PART III Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE. Information relating to the Company’s Directors, nominees for Directors and executive officers will be included in the Company’s definitive proxy statement relating the Company’s Annual Meeting of Stockholders to be held in June 7, 2023, and which is incorporated herein by reference. Item 11. EXECUTIVE COMPENSATION. Information relating to executive compensation will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in June 7, 2023, and which is incorporated herein by reference. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS. Information relating to security ownership of certain beneficial owners and management will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in June 7, 2023, and which is incorporated herein by reference. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE. Information relating to certain transactions by Directors and executive officers of the Company will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in June 7, 2023, and which is incorporated herein by reference. Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES. Information relating to principal accountant fees and services will be included in the Company’s definitive proxy statement relating to the Company’s Annual Meeting of Stockholders to be held in June 7, 2023, and which is incorporated herein by reference. 43 Table of Contents PART IV Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES. The following documents are filed as part of this Report: 1. Financial statements (Index to Consolidated Financial Statements at page F-1 of this Report) 2. Financial Statement Schedules (Index to Consolidated Financial Statements – Supplementary Information at page F-1 of this Report) 3. Exhibits: 3.1 Certificate of Incorporation of PrimeEnergy Resources Corporation, as amended and restated of December 21, 2018, (filed as Exhibit 3.1 of PrimeEnergy Resources Corporation Form 8-K on December 27, 2018, and incorporated herein by reference). 3.2 Bylaws of PrimeEnergy Resources Corporation as amended and restated as of April 24, 2020 (filed as Exhibit 3.2 of PrimeEnergy Resources Corporation Form 8-K on April 27, 2020 and incorporated herein by reference). 10.18 Composite copy of Non-Statutory Option Agreements (Incorporated by reference to Exhibit 10.18 of PrimeEnergy Resources Corporation Form 10-K for the year ended December 31, 2004). 10.22.6 FOURTH AMENDED AND RESTATED CREDIT AGREEMENT dated as of July 5, 2022, is among PRIMEENERGY RESOURCES CORPORATION, a Delaware corporation (the “Borrower”), each of the Lenders from time to time party hereto and CITIBANK, N.A. (in its individual capacity, “Citibank”), as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “Administrative Agent”) (filed as exhibit 10.22.6 of PrimeEnergy Resources Corporation Form 10-Q for the Quarter Ended June 30 2022, and incorporated by reference). 10.22.6.1 FIRST AMENDMENT TO FOURTH AMENDED AND RESTATED CREDIT AGREEMENT, dated as of October 31, 2022 (the “First Amendment Effective Date”), is among PRIMEENERGY RESOURCES CORPORATION, a Delaware corporation (the “Borrower”), CITIBANK, N.A., as administrative agent (in such capacity, the “Administrative Agent”) and as Issuing Bank, each Guarantor party hereto and the financial institutions party hereto as Lenders (filed herewith). 14 PrimeEnergy Resources Corporation Code of Business Conduct and Ethics, as amended December 16, 2011 (Incorporated by reference to Exhibit 14 of PrimeEnergy Resources Corporation Form 10-K for the year ended December 31, 2011). 21 Subsidiaries (filed herewith). 23 Consent of Ryder Scott Company, L.P. (filed herewith). 31.1 Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith). 31.2 Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith). 32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith). 32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith). 99.1 Summary Reserve Report dated March 7, 2023, of Ryder Scott Company, L.P. (filed herewith). 101.INS Inline XBRL (eXtensible Business Reporting Language) Instance Document (filed herewith) 44 Table of Contents 101.SCH Inline XBRL Taxonomy Extension Schema Document (filed herewith) 101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith) 101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document (filed herewith) 101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document (filed herewith) 101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith) 104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) 45 Table of Contents SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 17 t h day of April, 2023. PrimeEnergy Resources Corporation By: /s/ Charles E. Drimal, Jr. Charles E. Drimal, Jr. Chairman, Chief Executive Officer and President Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated and on the 17th, day of April, 2023. /s/ Charles E. Drimal, Jr. Charles E. Drimal, Jr. Chairman, Chief Executive Officer and President; The Principal Executive Officer /s/ Beverly A. Cummings Beverly A. Cummings Director, Executive Vice President and Treasurer; The Principal Financial Officer /s/ Clint Hurt Clint Hurt Director /s/ Thomas S. T. Gimbel Thomas S. T. Gimbel Director /s/ H. Gifford Fong H. Gifford Fong Director 46 Table of Contents INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm F-2 Financial Statements Consolidated Balance Sheets – As of December 31, 2022 and 2021 F-6 Consolidated Statements of Income – For the years ended December 31, 2022 and 2021 F-7 Consolidated Statements of Equity – For the years ended December 31, 2022 and 2021 F-8 Consolidated Statements of Cash Flows – For the years ended December 31, 2022 and 2021 F-9 Notes to Consolidated Financial Statements F-10 Supplementary Information: Capitalized Costs Relating to Oil and Gas Producing Activities, years ended December 31, 2022 and 2021 F-24 Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities, years ended December 31, 2022 and 2021 F-24 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, years ended December 31, 2022 and 2021 F-24 Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves, years ended December 31, 2022 and 2021 F-25 Reserve Quantity Information, years ended December 31, 2022 and 2021 F-26 Results of Operations from Oil and Gas Producing Activities, years ended December 31, 2022 and 2021 F-26 Notes to Supplementary Information F-27 F-1 Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Stockholders of PrimeEnergy Resources Corporation and Subsidiaries: Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of PrimeEnergy Resources Corporation and Subsidiaries (the “Company”) as of December 31, 2022 and 2021, the related consolidated statements of income, equity, and cash flows for each of the years then ended, 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 years then ended, in conformity with accounting principles generally accepted in the United States of America. 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 Public Company Accounting Oversight Board (United States) (“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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. 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 Matters The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. F-2 Table of Contents Depreciation, Depletion and Amortization and Impairment of Property and Equipment Description of the Matter At December 31, 2022, the carrying value of the Company’s property and equipment was $174.0 million, and depreciation, depletion and amortization (DD&A) expense was $28.1 million for the year then ended. As described in Note 1, the Company follows the “successful efforts” method of accounting for its oil and gas properties. Under the “successful efforts” method, costs of acquiring undeveloped oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs, are capitalized. Provisions for impairment of undeveloped oil and gas leases are based on periodic evaluations. Annual lease rentals and exploration expenses, including geological and geophysical expenses and exploratory dry hole costs, are charged against income as incurred. Costs of drilling and equipping productive wells, including development of dry holes and related production facilities, are capitalized. All other property and equipment are carried at cost. Depreciation and depletion of oil and gas production equipment and properties are determined under the unit-of-production method based on estimated proved developed recoverable oil and gas reserves. Depreciation of all other equipment is determined under the straight-line method using various rates based on useful lives generally ranging from 5 to 10 years. The cost of assets and related accumulated depreciation is removed from the accounts when such assets are disposed of, and any related gains or losses are reflected in current earnings. Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated and successful. The Company reviews long-lived assets, including oil and gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted cash flows, the assets are impaired, and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows. Proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization. Proved reserves represent estimated quantities of natural gas, crude oil, condensate, and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. The process of estimating quantities of proved oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Estimates of oil and gas reserves, as determined by independent petroleum engineers, are continually subject to revision based on price, production history and other factors. Depletion expense, which is computed based on the units of production method, could be significantly impacted by changes in such estimates. Additionally, U.S. generally accepted accounting principles require that if the F-3 Table of Contents expected future undiscounted cash flows from an asset are less than its carrying cost, that asset must be written down to its fair market value. As the fair market value of an oil and gas property will usually be significantly less than the total undiscounted future net revenues expected from that asset, slight changes in the estimates used to determine future net revenues from an asset could lead to the necessity of recording a significant impairment of that asset. Auditing the Company’s DD&A and impairment calculations is complex because of the use of independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating oil and gas reserves. How We Addressed the Matter in Our Audit We obtained an understanding and evaluated the design of the Company’s controls over its process to calculate DD&A and impairment, including management’s controls over the completeness and accuracy of the financial data utilized by the engineers in estimating oil and gas reserves. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company’s independent petroleum engineers responsible for the preparation of the proved oil and gas reserve estimates for select properties. We also utilized the services of an independent auditor-engaged specialist to ensure the methodologies and assumptions utilized by the Company’s independent engineers were reasonable and in accordance with industry standards. In addition, we compared the Company’s recent production with its reserve estimates for properties that have significant production or significant reserve quantities and inquired of disproportionate ratios that did not align with our expectations. We also tested the mathematical accuracy of the DD&A and impairment calculations, including comparing the oil and gas reserve amounts used in the calculations to the Company’s reserve reports. Accounting for Asset Retirement Obligations Description of the Matter At December 31, 2022, the asset retirement obligation (ARO) balance totaled $15.4 million. As further described in Note 1, the Company’s ARO primarily represents the estimated present value of the amount the Company will incur to plug, abandon, and remediate producing properties at the end of their productive lives, in accordance with applicable state laws. The Company determined its asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The asset retirement obligation is recorded as a liability at its estimated present value at its inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statements of income. The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates. Auditing the Company’s ARO is complex and highly judgmental because of the significant estimation by management in determining the obligation. In particular, F-4 Table of Contents the estimate was sensitive to significant subjective assumptions such as retirement cost estimates and the estimated timing of settlements, which are both affected by expectations about future market and economic conditions. How We Addressed the Matter in Our Audit We obtained an understanding and evaluated the design of the Company’s internal controls over its ARO estimation process, including management’s review of the significant assumptions that have a material effect on the determination of the obligations. Based on our evaluation, we designed our audit procedures to include, among others, assessing the significant assumptions and inputs used in the valuation, such as retirement cost estimates and timing of settlement assumptions. Additionally, we compared the ARO against historical results, reviewed the reasonableness of the discount rate utilized in the estimate, considered the reasonableness of the current and long-term portion of the obligation by comparing the accretion expense trends, and considered the completeness of the properties included in the estimate by comparing to the Company’s reserve reports. /s/ GRASSI & CO., CPAs, P.C. We have served as the Company’s auditor since 1989. New York, New York April 14, 2023 F-5 Table of Contents PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Thousands of dollars, except share data) As of December 31, 2022 2021 ASSETS Current Assets Cash and cash equivalents $ 26,543 $ 10,347 Accounts receivable, net 12,147 14,208 Prepaid obligations 32,839 733 Due from related parties 388 — Derivative asset short-term 210 — Other current assets 38 40 Total Current Assets 72,165 25,328 Property and Equipment Oil and gas properties at cost 555,280 539,484 Less: Accumulated depletion and depreciation ( 385,811 ) ( 359,742 ) 169,469 179,742 Field and office equipment at cost 27,246 27,080 Less: Accumulated depreciation ( 22,728 ) ( 22,159 ) 4,518 4,921 Total Property and Equipment, Net 173,987 184,663 Other assets 985 923 Total Assets $ 247,137 $ 210,914 LIABILITIES AND EQUITY Current Liabilities Accounts payable $ 11,451 $ 7,282 Accrued liabilities 25,750 7,821 Due to related parties — 52 Current portion of asset retirement and other long-term obligations 2,566 1,630 Derivative liability short-term 1,190 4,935 40,957 21,720 Long-Term Bank Debt 11,000 36,000 Asset Retirement Obligations 13,525 13,222 Derivative Liability Long-Term — 650 Deferred Income Taxes 39,968 38,743 Other Long-Term Obligations 1,334 1,488 Total Liabilities 106,784 111,823 Commitments and Contingencies Equity Common stock, $. 10 par value; 2022 and 2021: Authorized: 2,810,000 shares, outstanding 2022: 1,901,000 shares; outstanding 202 1 : 1,992,077 shares. 281 281 Paid-in capital 7,555 7,555 Retained earnings 177,566 128,902 Treasury stock, at cost; 2022: 909,000 shares; 2021: 817,923 ( 45,049 ) ( 37,647 ) Total Stockholders’ Equity 140,353 99,091 Total Liabilities and Equity $ 247,137 $ 210,914 The accompanying Notes are an integral part of these Consolidated Financial Statements F-6 Table of Contents PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Thousands of dollars, except per share amounts) For the Years Ended December 31, 2022 2021 Revenues Oil sales $ 90,803 $ 50,474 Natural gas sales 18,428 11,432 Natural gas liquids sales 14,887 11,220 Realized gain (loss) on derivative instruments, net ( 16,644 ) ( 5,045 ) Field service income 12,978 9,262 Unrealized (loss) on derivative instruments 4,605 ( 4,914 ) Other income 30 29 Total Revenues 125,087 72,458 Costs and Expenses Lease operating expense 37,816 24,419 Field service expense 11,094 9,152 Depreciation, depletion, amortization and accretion on discounted liabilities 28,068 26,325 General and administrative expense 20,233 9,084 Total Costs and Expenses 97,211 68,980 Gain on Sale and Exchange of Assets 31,789 1,478 Income from Operations 59,665 4,956 Other Income and Expenses Less: Interest expense ( 909 ) ( 2,007 ) Add: Interest income 237 — Add: PPP Loan Forgiveness — 1,693 Income Before Provision Income Taxes 58,993 4,642 Income Tax Expense 10,329 2,516 Net Income 48,664 2,126 Less: Net Income Attributable to Non-Controlling Interest — 28 Net Income Attributable to PrimeEnergy $ 48,664 $ 2,098 Basic Income Per Common Share $ 24.91 $ 1.05 Diluted Income Per Common Share $ 17.95 $ 0.76 The accompanying Notes are an integral part of these Consolidated Financial Statements F-7 Table of Contents PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EQUITY (Thousands of dollars, except share amounts) Shares Outstanding Common Stock Additional Paid-In Capital Retained Earnings Treasury Stock Total Stockholders’ Equity – PrimeEnergy Non- Controlling Interest Total Equity Balance at December 31, 2020 1,994,177 $ 281 $ 7,541 $ 126,804 $ ( 37,502 ) $ 97,124 $ 874 $ 97,998 Purchase 2,100 shares of common stock ( 2,100 ) — — — ( 145 ) ( 145 ) — ( 145 ) Net Income — — — 2,098 — 2,098 28 2,126 Purchase of non-controlling interest — — 14 — — 14 ( 58 ) ( 44 ) Distributions to non-controlling interest — — — — — — ( 844 ) ( 844 ) Balance at December 31, 2021 1,992,077 $ 281 $ 7,555 $ 128,902 $ ( 37,647 ) $ 99,091 $ — $ 99,091 Purchase 91,077 shares of common stock ( 91,077 ) — — — ( 7,402 ) ( 7,402 ) — ( 7,402 ) Net Income — — — 48,664 — 48,664 — 48,664 Balance at December 31, 2022 1,901,000 $ 281 $ 7,555 $ 177,566 $ ( 45,049 ) $ 140,353 $ — $ 140,353 The accompanying Notes are an integral part of these Consolidated Financial Statements F-8 Table of Contents PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Thousands of dollars) For the Years Ended December 31, 2022 2021 Cash Flows from Operating Activities: Net Income $ 48,664 $ 2,126 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion, amortization and accretion on discounted liabilities 28,068 26,325 Gain on sale of properties ( 31,789 ) ( 1,478 ) Unrealized (gain) loss on derivative instruments ( 4,605 ) 4,914 PPP Loan forgiveness — ( 1,693 ) Provision for deferred income taxes 1,225 2,376 Changes in assets and liabilities: Accounts receivable 2,096 ( 6,760 ) Allowance for doubtful accounts ( 35 ) ( 227 ) Due from related parties ( 388 ) 44 Due to related parties ( 52 ) ( 30 ) Prepaid obligations ( 32,106 ) ( 143 ) Other current assets 2 64 Accounts payable 4,169 2,065 Accrued liabilities 17,929 1,034 Other assets 100 — Other long-term liabilities ( 151 ) — Net Cash Provided by Operating Activities 33,127 28,617 Cash Flows from Investing Activities: Capital expenditures, including exploration expense ( 15,974 ) ( 20,726 ) Proceeds from sale of properties and equipment 31,445 1,478 Net Cash Provided by (Used in) Investing Activities 15,471 ( 19,248 ) Cash Flows from Financing Activities: Purchase of stock for treasury ( 7,402 ) ( 145 ) Purchase of non-controlling interests — ( 676 ) Increase in long-term bank debt and other long-term obligations 11,000 11,209 Repayment of long-term bank debt and other long-term obligations ( 36,000 ) ( 10,209 ) Distribution to non-controlling interest — ( 197 ) Net Cash Used in Financing Activities ( 32,402 ) ( 18 ) Net Increase in Cash and Cash Equivalents 16,196 9,351 Cash and Cash Equivalents at the Beginning of the Year 10,347 996 Cash and Cash Equivalents at the End of the Year $ 26,543 $ 10,347 Supplemental Disclosures: Income taxes paid during the year $ 539 $ 343 Interest paid during the year $ 842 $ 1,957 Non-Cash Disclosures: Purchase of non-controlling interest $ — $ 14 Distribution of non-controlling interest in liquidated partnerships $ — $ 647 The accompanying Notes are an integral part of these Consolidated Financial Statements F-9 Table of Contents PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Description of Operations and Significant Accounting Policies Nature of Operations: PrimeEnergy Resources Corporation (“PERC”), a Delaware corporation, was organized in March 1973 and is engaged in the development, acquisition and production of oil and natural gas properties. PrimeEnergy Resources Corporation and its subsidiaries are herein referred to as the “Company.” The Company owns leasehold, mineral and royalty interests in producing and non-producing oil and gas properties across the United States, primarily in Oklahoma, and Texas. The Company operates approximately 630 active wells and owns non-operating interests and royalties in approximately 800 additional wells. Additionally, the Company provides well-servicing support operations, site-preparation and construction services for oil and gas drilling and reworking operations, both in connection with the Company’s activities and providing contract services for third parties. The Company is publicly traded on the NASDAQ under the symbol “PNRG.” PERC owns Eastern Oil Well Service Company (“EOWSC”) and EOWS Midland Company (“EMID”) which perform oil and gas field servicing. PERC also owns Prime Operating Company (“POC”), which serves as operator for most of the producing oil and gas properties owned by the Company and affiliated entities. The markets for the Company’s products are highly competitive, as oil and gas are commodity products and prices depend upon numerous factors beyond the control of the Company, such as economic, political and regulatory developments and competition from alternative energy sources. Consolidation and Presentation: The consolidated financial statements include the accounts of PrimeEnergy Resources Corporation, its subsidiaries and the Partnerships, using the full consolidation method for those partnerships which are controlled by the Company. The Company’s reserve estimates are based on the full consolidation method. DD&A expense and evaluation of impairment may differ from the Partnership as the Company’s cost basis for the Partnership interests acquired may be different than the cost basis at the Partnership level for properties acquired by the Partnership. All significant intercompany balances and transactions are eliminated in preparing the consolidated financial statements. Reclassifications: Certain reclassifications have been made to prior year statements to conform with the current year presentation. These reclassifications have no impact on net income and no material impact on any other financial statement captions. Subsequent Events: Subsequent events have been evaluated through the date that the consolidated financial statements were issued. During this period, there were no material subsequent items requiring disclosure, other than as stated in Footnote 4, to these consolidated financial statements. Use of Estimates: The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. F-10 Table of Contents Estimates of oil and gas reserves, as determined by independent petroleum engineers, are continually subject to revision based on price, production history and other factors. Depletion expense, which is computed based on the units of production method, could be significantly impacted by changes in such estimates. Additionally, U.S. generally accepted accounting principles require that if the expected future undiscounted cash flows from an asset are less than its carrying cost, that asset must be written down to its fair market value. As the fair market value of an oil and gas property will usually be significantly less than the total undiscounted future net revenues expected from that asset, slight changes in the estimates used to determine future net revenues from an asset could lead to the necessity of recording a significant impairment of that asset. Oil and gas properties: The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive explorat ion costs an d geological and geophysical expenditures are expensed. Oil and gas leasehold acquisition costs are capitalized when incurred and included as unproved oil and gas properties in the consolidated balance sheets. The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met: (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The Company’s exploratory wells include extension wells that extend the limits of a known reservoir. Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather the Company’s ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production data in the area, transportation or processing facilities, and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company’s assessment of suspended exploratory/extension well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is determined to be noncommercial and is charged to exploration and abandonments expense. As of December 31, 2022, the Company had no such suspended well costs. The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and in-process development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, abandonments expense is recognized. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact the depletion rate of its amortization base. Generally, no gain or loss is recorded until an entire amortization base is sold. However, gain or loss is recorded from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. Field and office Equipment: Depreciation of all other equipment is determined under the straight-line method using various rates based on useful lives generally ranging from 5 to 10 years. The cost of assets and related accumulated depreciation is removed from the accounts when such assets are disposed of, and any related gains or losses are reflected in current earnings. F-11 Table of Contents Capitalization of Interest: Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the projects are substantially complete and ready for their intended use if the projects are evaluated and successful. Impairment of Long-Lived Assets: The Company reviews long-lived assets, including oil and gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. If the carrying amounts are not expected to be recovered by undiscounted cash flows, the assets are impaired, and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows. Fair Value: The Company follows the authoritative guidance that establishes a formal framework for measuring fair values of assets and liabilities in financial statements that are already required by U.S. generally accepted accounting principles to be measured at fair value. The guidance defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The transaction is based on a hypothetical transaction in the principal or most advantageous market considered from the perspective of the market participant that holds the asset or owes the liability. The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company attempts to utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The Company is able to classify fair value balances based on the observability of those inputs. The guidance establishes a formal fair value hierarchy based on the inputs used to measure fair value. The hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. Revenue recognition: The majority of the Company’s production is operated by third party operators where we elect to market our products under the joint operating agreements. Accordingly, we receive our proportionate share of revenue proceeds for production sold by the operator under the operator’s marketing agreements. The Company recognizes revenue and any costs indicated by the operator in the related production period. The Company recognizes revenue related to production from properties operated by the Company when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Oil sales. The Company recognizes oil sales revenue when (i) control/custody transfers to the purchaser and (ii) the agreed-upon index price, net of any price differentials, is fixed and determinable. Any costs incurred prior to the transfer of control to the customer, such as gathering and transportation costs, are recognized as oil and gas production costs. NGL and gas sales . Under the majority of the Company’s gas processing contracts, gas is delivered to a midstream processing entity and the Company recognizes revenue when the products are delivered to the midstream gathering or processing entity at a specified index price, net of downstream gathering and processing fees. F-12 Table of Contents Asset Retirement Obligation: The asset retirement obligation primarily represents the estimated present value of the amount the Company will incur to plug, abandon and remediate producing properties at the end of their productive lives, in accordance with applicable state laws. The Company determined its asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The asset retirement obligation is recorded as a liability at its estimated present value at its inception, with an offsetting increase to producing properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the statements of income. Income Taxes: The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. As of December 31, 2022 and 2021, The Company had no valuation allowance. The Company is required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that the Company has taken. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. General and Administrative Expenses: General and administrative expenses represent cost and expenses associated with the operation of the Company. Earnings Per Common Share: Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. Statements of Cash Flows: For purposes of the consolidated statements of cash flows, the Company considers short-term, highly liquid investments with original maturities of less than ninety days to be cash equivalents. Concentration of Credit Risk: The Company maintains significant banking relationships with financial institutions in the State of Texas. The Company limits its risk by periodically evaluating the relative credit standing of these financial institutions. The Company’s oil and gas production purchasers consist primarily of independent marketers and major gas pipeline companies. Hedging: The Company periodically enters into oil and gas financial instruments to manage its exposure to oil and gas price volatility. The oil and gas reference prices upon which the price hedging instruments are based reflect F-13 Table of Contents various market indices that have a high degree of historical correlation with actual prices received by the Company. The financial instruments are accounted for in accordance with applicable accounting standards for derivative instruments and hedging activities. Such standards require that applicable derivative instruments be measured at fair market value and recognized as assets or liabilities in the balance sheet. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation is generally established at the inception of a derivative. For derivatives designated as cash flow hedges and meeting applicable effectiveness guidelines, changes in fair value, to the extent effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value of a derivative resulting from ineffectiveness or an excluded component of the gain/loss is recognized immediately in the statements of income. 2. Acquisitions and Dispositions 2022 Transactions : In the first quarter of 2022, the Company sold 1,809 net leasehold acres in Reagan and Midland Counties, Texas through two separate transactions receiving gross proceeds of $ 14.0 million. In the second quarter of 2022, the Company sold 241 net acres in Canadian County, Oklahoma for $ 845,000 . In the third quarter of 2022, the Company sold an additional 113 net acres in Canadian County, Oklahoma for $ 423,700 . On November 14, 2022, the Company completed an acreage exchange of approximately 725 net acres in the Midland Basin creating a block of 1,200 contiguous acres. The Company entered into an agreement, including this acreage, to create a 2,560 -acre AMI for the joint development of horizontal wells. As part of the agreement, the Company sold a portion of its interest in this acreage to the joint development partner for proceeds of $ 16.1 million. 2021 Transaction s : During 2021 the Company acquired 5.9 net acres, located in Midland county, Texas, for approximately $ 29,500 and sold or farmed out interests in certain non-core undeveloped and developed oil and natural gas properties in Oklahoma. In Texas, the Company divested approximately 116 net mineral acres (NMA) located in Martin County, Texas for proceeds of $ 1.45 million. During 2021 the Company liquidated partnerships for total cash payments of $ 632,000 , resulting in the non-cash distribution of non-controlling interest of $ 647,000 . Effective December 31, 2021, all managed partnerships and trusts were liquidated. 3. Additional Balance Sheet Information Accounts receivable, net at December 31, 2022 and 2021 consisted of the following: December 31, (Thousands of dollars) 2022 2021 Joint interest billings $ 1,806 $ 1,902 Trade receivables 1,762 1,429 Oil and gas sales 8,894 11,154 Other 21 94 12,483 14,579 Less: Allowance for doubtful accounts ( 336 ) ( 371 ) Total $ 12,147 $ 14,208 F-14 Table of Contents Accounts payable at December 31, 2022 and 2021 consisted of the following: December 31, (Thousands of dollars) 2022 2021 Trade $ 5,142 $ 2,390 Royalty and other owners 3,600 2,802 Partner advances 1,111 1,209 Other 1,598 881 Total $ 11,451 $ 7,282 Accrued liabilities at December 31, 2022 and 2021 consisted of the following: December 31, (Thousands of dollars) 2022 2021 Compensation and related expenses $ 9,743 $ 3,919 Property costs 6,413 2,901 Taxes 9,352 893 Other 242 108 Total $ 25,750 $ 7,821 4. Long-Term Debt Bank Debt: On February 15, 2017 , the Company and its lenders entered into a Third Amended and Restated Credit Agreement (the “2017 Credit Agreement”) with a maturity date of February 15, 2021 . Under the 2017 Credit Agreement, the Company had a revolving line of credit and letter of credit facility of up to $ 300 million subject to a borrowing base that is determined semi-annually by the lenders based upon the Company’s consolidated financial statements and the estimated value of the Company’s oil and gas properties, in accordance with the Lenders’ customary practices for oil and gas loans. The credit facility is secured by substantially all of the Company’s oil and gas properties. The 2017 Credit Agreement includes terms and covenants that require the Company to maintain a minimum current ratio and total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio, as defined, and restrictions are placed on the payment of dividends, the amount of treasury stock the Company may purchase, commodity hedge agreements, and loans and investments in its consolidated subsidiaries and limited partnerships. On December 20, 2021 the company entered into a Seventh Amendment to the 2017 Credit Agreement and Citibank N.A was appointed as successor administrative agent replacing PNC Bank. Under this amendment the Company’s borrowing base was $ 50 million. Borrowings under the 2017 Credit Agreement would bear interest at alternate base rate (ABR) plus an applicable margin ranging from 2.00 % to 3.00 % or at the Company’s option, at a rate equal to the secured overnight financing rate (SOFR rate) as administered by the SOFR Administrator, in this case the Federal Reserve Bank of New York, plus an applicable margin ranging from 3.00 % to 4.00 %. The 2017 Credit Agreement was set to mature on February 11, 2023 . On December 31, 2021, the Company had a total of $ 36 million of borrowings outstanding under its revolving credit and $ 14 million was available for future borrowings. The 2017 Credit Agreement was terminated on July 5th, 2022 with the issuance of the Fourth Amended and Restated Credit Agreement. On July 5, 2022 , the Company and its lenders entered into a Fourth Amended and Restated Credit Agreement (the “2022 Credit Agreement”) with a maturity date of June 1, 2026. Under the 2022 Credit Agreement, the Company has a revolving line of credit and letter of credit facility of up to $ 300 million subject F-15 Table of Contents to a borrowing base that is determined semi-annually by the lenders based upon the Company’s consolidated financial statements and the estimated value of the Company’s oil and gas properties, in accordance with the Lenders’ customary practices for oil and gas loans. The initial borrowing base of the agreement is $ 75 million. The credit facility is secured by substantially all of the Company’s oil and gas properties. The 2022 Credit Agreement includes terms and covenants that require the Company to maintain a minimum current ratio and total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio, as defined, and restrictions are placed on the payment of dividends, the amount of treasury stock the Company may purchase, and commodity hedge agreements. On December 31, 2022, the Company had a total of $ 11 million of borrowings outstanding under its revolving credit facility and $ 64 million was available for future borrowings. Effective January 20, 2023 , in lieu of a formal amendment, a borrowing base letter authorized by all lenders and Prime of the 2022 Credit Agreement resulted in an adjustment to decrease the amount of the Borrowing Base available from $ 75 million to $ 60 million until such time as the next redetermination date as required by the agreement. As of March 31, 2023, the borrowing base was $ 60 million and the Company no outstanding borrowings under the Credit Facility. Paycheck Protection Program Loans During May 2020, Prime Operating Company and Eastern Oil Well Services Corporation, subsidiaries of the Company received loan proceeds in the amount of $ 1.28 million and $ 0.47 million, respectively, under the Paycheck Protection Program (the “PPP”) of the CARES Act, which was enacted March 27, 2020. The PPP Loans are evidenced by a promissory note in favor of the Lender, which bears interest at the rate of 1.00 % per annum. No payments of principal or interest are due under the note until the date on which the amount of loan forgiveness (if any) under the CARES Act, which can be up to 10 months after the end of the related notes covered period (which is defined as 24 weeks after the date of the loan) (the “Deferral Period”). The note may be prepaid at any time prior to maturity with no prepayment penalties. Funds from the PPP Loans may be used only for payroll and related costs, costs used to continue group health care benefits, mortgage payments, rent, utilities, and interest on other debt obligations that were incurred prior to February 15, 2020 (the “Qualifying Expenses”). Under the terms of the PPP Loans, certain amounts thereunder may be forgiven if they are used for Qualifying Expenses as described in and in compliance with the CARES Act. The Company utilized the PPP Loan proceeds exclusively for Qualifying Expenses during the 24-week coverage period and has submitted its application for forgiveness in accordance with the terms of the CARES Act and related guidance. In the event the PPP Loan or any portion thereof is forgiven, the amount forgiven is applied to the outstanding principal and accrued interest. To the extent, if any, that any or all of the PPP loans are not forgiven, beginning one month following expiration of the Deferral Period, and continuing monthly until 24 months from the date of each applicable Note (the “Maturity Date”), the Company is obligated to make monthly payments of principal and interest to the Lender with respect to any unforgiven portion of the Note, in such equal amounts required to fully amortize the principal amount outstanding on such Note as of the last day of the applicable Deferral Period by the applicable Maturity Date. The PPP loans have been approved for forgiveness by the Small Business Administration ( SBA) in conjunction with our lender PNC Bank. The effective date of February 18, 2022 for Eastern Oil Well Service Company in the amount of $ 481 thousand in principal and interest paid to our lender PNC Bank. The effective date of March 16, 2022 for Prime Operating Company in the amount of $ 1.2 million in principal and interest to our lender PNC Bank. Effective December 31, 2021, PPP debt and any accrued interest were reclassed from the consolidated balance sheet and recorded in other income on the consolidated statements of income. F-16 Table of Contents (5) Other Long-Term Obligations and Commitments: Operating Leases: The Company leases office facilities under operating leases and recognizes lease expense on a straight-line basis over the lease term. Lease assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term. A new finance lease for office equipment is included in Property and equipment, Current portion of asset retirement and Other Long-Term Obligations in 2022. As most of the Company’s lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The weighted average discount rate used was 7.54 %. Certain leases may contain variable costs above the minimum required payments and are not included in the right-of-use assets or liabilities. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at the Company’s sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Operating lease costs for the years ended December 31, 2022 and 2021 were $ 628 thousand and $ 577 thousand, respectively. Cash payments included in the operating lease cost for years ended December 31, 2022 and 2021 were $ 673 thousand and $ 599 thousand, respectively. The weighted-average remaining operating lease terms for the years ended December 31, 2022 and 2021 were 11 months and 15 months, respectively. The Company acquired and amended certain leases for office space in Texas providing for payments of $ 673,000 in 2022, $ 684,000 in 2023, $ 202,000 in 2024 and $ 27,000 in 2025. Rent expense for office space the years ended December 31, 2022 and 2021 was $ 755,000 and $ 653,000 , respectively. The payment schedule for the Company’s operating lease obligations as of December 31, 2022 is as follows: (Thousands of dollars) Operating Leases 2023 $ 684 2024 202 2025 27 Total undiscounted lease payments $ 913 Less: Amount associated with discounting ( 61 ) Total net operating lease liabilities $ 852 Less: Current portion included in Other current liabilities 647 Non-current portion included in Other liabilities $ 205 F-17 Table of Contents Asset Retirement Obligation: A reconciliation of the liability for plugging and abandonment costs for the years ended December 31, 2022 and 2021 is as follows: Years Ended December 31, (Thousands of dollars) 2022 2021 Asset retirement obligation at beginning of period $ 14,295 $ 13,660 Net wells placed on production 11 724 Liabilities settled ( 1,407 ) ( 1,047 ) Dispositions ( 344 ) ( 52 ) Accretion expense 666 642 Revisions in estimated liabilities 2,222 368 Asset retirement obligation at end of period $ 15,443 $ 14,295 Less: Current portion included in Current portion of asset retirement and other long-term obligations 1,918 1,073 Long-term Asset Retirement Obligations included in Asset Retirement Obligations $ 13,525 $ 13,222 The Company’s liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive life of wells and a risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to producing properties, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of assumptions and the relatively long life of most of the Company’s wells, the costs to ultimately retire the wells may vary significantly from previous estimates. 6. Contingent Liabilities The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company’s financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations, which have not been material to the Company’s results of operations. From time to time, the Company is party to certain legal actions arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company. 7. Stock Options and Other Compensation In May 1989, non-statutory stock options were granted by the Company to four key executive officers for the purchase of shares of common stock. At December 31, 2021 and 2020, options on 767,500 shares were outstanding and exercisable at prices ranging from $ 1.00 to $ 1.25 . According to their terms, the options have no expiration date. F-18 Table of Contents 8. Income Taxes The components of the provision for income taxes for the years ended December 31, 2022 and 2021 are as follows: Years Ended December 31, (Thousands of dollars) 2022 2021 Current: Federal $ 8,330 $ 81 State 774 59 Total current 9,104 140 Deferred: Federal 886 1,802 State 339 574 Total deferred 1,225 2,376 Total income tax provision $ 10,329 $ 2,516 At December 31, (Thousands of dollars) 2022 2021 Deferred Tax Assets: Accrued liabilities $ 353 $ 80 Allowance for doubtful accounts 77 85 Derivative Contracts 223 1,272 Partnership basis difference 90 98 State Net operating loss carry-forwards 283 470 Total deferred tax assets 1,026 2,005 Deferred Tax Liabilities: Depletion and depreciation 40,994 40,748 Total deferred tax liabilities 40,994 40,748 Net deferred tax liabilities $ 39,968 $ 38,743 The total provision for income taxes for the years ended December 31, 2022 and 2021 varies from the federal statutory tax rate as a result of the following: Years Ended December 31, (Thousands of dollars) 2022 2021 Expected tax expense $ 12,389 $ 975 Net changes in deferred assets and liabilities 1,225 2,376 Permanent differences 870 ( 677 ) State income tax, net of federal benefit 612 47 Provision to return adjustment ( 4,765 ) 744 Tax Credits — ( 948 ) Other, net ( 2 ) ( 1 ) Total income tax provision $ 10,329 $ 2,516 Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. F-19 Table of Contents The Company is entitled to percentage depletion on certain of its wells, which is calculated without reference to the basis of the property. To the extent that such depletion exceeds a property’s basis, it creates a permanent difference, which lowers the Company’s effective rate. The availability of the percentage depletion deduction is phased out as an entity’s production exceeds certain levels, and based on the Company’s increasing production the percentage depletion deduction is becoming less significant. The Company is allowed a credit against the Texas Franchise Tax based on net operating losses incurred in prior periods. The credits allowed are $ 89 thousand in the years 2020 through 2026. Any credits not utilized in a given year due to the allowable credit exceeding the tax liability may be carried forward. No credit may be carried forward past 2026 . The value of the credit is calculated net of the federal income tax effect. The Company has not recorded any provision for uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and various state and local jurisdictions. The 2004, 2005, 2006, 2009 and 2017 federal income tax returns have been audited by the Internal Revenue Service. Returns for unexamined earlier years may be examined and adjustments made to the amount of percentage depletion and AMT credit carryforwards flowing from those years into an open tax year, although in general no assessment of income tax may be made for those years on which the statute has closed. Federal and State returns for the years 2020 through 2022 remain open for examination by the relevant taxing authorities. Enactment of the Inflation Reduction Act of 2022 . On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (the “IRA”), which includes, among other things, a corporate alternative minimum tax (the “CAMT”). Under the CAMT, a 15 percent minimum tax will be imposed on certain adjusted financial statement income of “applicable corporations,” which is effective for tax years beginning after December 31, 2022. The CAMT generally treats a corporation as an “applicable corporation” in any taxable year in which the “average annual adjusted financial statement income” of the corporation and certain of its subsidiaries and affiliates for a three taxable-year period ending prior to such taxable year exceeds $ 1 billion. The IRA also establishes a one percent excise tax on stock repurchases made by publicly traded U.S. corporations. The excise tax is effective for any stock repurchases after December 31, 2022. The IRA did not impact the Company’s current year tax provision or the Company’s consolidated financial statements, but the new provisions could impact future periods. Enactment of the Consolidated Appropriations Act, 2021 . On December 27, 2020, President Trump signed into law the Consolidated Appropriations Act, 2021 (the “Act”). The Act includes many tax provisions, including the extension of various expiring provisions, extensions and expansions of certain earlier pandemic tax relief provisions, among other things. The Act did not have a material impact on the Company’s tax provisions or the Company’s consolidated financial statements. Enactment of the Coronavirus Aid, Relief and Economic Security Act. On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief and Economic Security Act (“CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer social security payments, net operating loss carryback periods, alternative minimum tax credit refunds, modifications to the net interest deduction limitations and technical corrections to tax depreciation methods for qualified improvement property. Under the CARES Act the refundable portion of AMT credits was increased to 100% therefore the Company received a full refund of such credits in 2020. 9. Segment Information and Major Customers The Company operates in one industry – oil and gas exploration, development, operation and servicing. The Company’s oil and gas activities are entirely in the United States. The Company sells its oil and natural gas and liquids production to a number of direct purchasers under direct contracts or through other operators under joint F-20 Table of Contents operating agreements. Listed below are the purchasers of the Company’s production which represented more than 10 % of the Company’s sales for the years ended 2022 and 2021. 2022 2021 Oil: APA Corporation 55 % 48 % Plains All American Inc. 16 % 18 % Natural gas and liquids: APA Corporation 58 % 52 % Targa Pipeline Mid-Continent West Tex, LLC 11 % 19 % Although there are no long-term oil and gas purchasing agreements with these purchasers, the Company believes that they will continue to purchase its oil and gas products and, if not, could be replaced by other purchasers. 10. Financial Instruments Fair Value Measurements: Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. The fair values of the Company’s interest rate swaps, natural gas and crude oil price collars and swaps are designated as Level 3. The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at December 31, 2022 and December 31, 2021: December 31, 2022 Quoted Prices in Active Markets For Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance at December 31, 2022 (Thousands of dollars) Assets Commodity derivative contracts $ — $ — $ 210 $ 210 Total assets $ — $ — $ 210 $ 210 Liabilities Commodity derivative contracts $ — $ — $ ( 1,190 ) $ ( 1,190 ) Total liabilities $ — $ — $ ( 1,190 ) $ ( 1,190 ) December 31, 2021 Quoted Prices in Active Markets For Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Balance at December 31, 2021 (Thousands of dollars) Assets Commodity derivative contracts $ — $ — $ — $ — Total assets $ — $ — $ — $ — Liabilities Commodity derivative contract $ — $ — $ ( 5,585 ) $ ( 5,585 ) Total liabilities $ — $ — $ ( 5,585 ) $ ( 5,585 ) The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. F-21 Table of Contents These estimates are verified using comparable NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness. The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided. The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the year ended December 2022. (Thousands of dollars) Net Liabilities – December 31, 2021 $ ( 5,585 ) Total realized and unrealized gains (losses): Included in earnings (a) ( 12,039 ) Purchases, sales, issuances and settlements 16,644 Net Liabilities – December 31, 2022 $ ( 980 ) (a) Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments. Derivative Instruments: The Company is exposed to commodity price and interest rate risk, and management considers periodically the Company’s exposure to cash flow variability resulting from the commodity price changes and interest rate fluctuations. Futures, swaps and options are used to manage the Company’s exposure to commodity price risk inherent in the Company’s oil and gas production operations. The Company does not apply hedge accounting to any of its commodity-based derivatives. Both realized and unrealized gains and losses associated with commodity derivative instruments are recognized in earnings. The following table sets forth the effect of derivative instruments on the consolidated balance sheets at December 31, 2022 and 2021: Fair Value (Thousands of dollars) Balance Sheet Location December 31, 2022 December 31, 2021 Asset Derivatives: Derivatives not designated as cash-flow hedging instruments: Crude oil commodity contract Other current assets $ 162 $ — Natural gas commodity contract Other current assets 48 — Total $ 210 $ — Liability Derivatives: Derivatives not designated as cash-flow hedging instruments: Crude oil commodity contracts Derivative liability short-term $ ( 931 ) $ ( 3,992 ) Natural gas commodity contracts Derivative liability short-term ( 259 ) ( 943 ) Crude oil commodity contracts Derivative liability long-term — ( 490 ) Natural gas commodity contracts Derivative liability long-term — ( 160 ) Total $ ( 1,190 ) $ ( 5,585 ) Total derivative instruments $ ( 980 ) $ ( 5,585 ) F-22 Table of Contents The following table sets forth the effect of derivative instruments on the consolidated statements of income for the years ended December 31, 2022 and 2021: Location of gain/loss recognized in income Amount of gain/loss recognized in income (Thousands of dollars) 2022 2021 Derivatives not designated as cash-flow hedge instruments: Natural gas commodity contracts Unrealized gain (loss) on derivative instruments, net 892 ( 859 ) Crude oil commodity contracts Unrealized (loss) gain on derivative instruments, net 3,713 ( 4,055 ) Natural gas commodity contracts Realized gain (loss) on derivative instruments, net ( 4,543 ) ( 1,833 ) Crude oil commodity contracts Realized (loss) on derivative instruments, net ( 12,101 ) ( 3,212 ) $ ( 12,039 ) $ ( 9,959 ) 11. Related Party Transactions During 2021 the Company, as managing general partner or managing trustee, repurchased the interests of the partners and trust unit holders in certain of the Partnerships or Trusts in an amount totaling $ 676,000 . Effective December 31, 2021, all managed partnerships and trusts were liquidated. Amounts due to or from related parties primarily represent receipts or expenses, related to oil and gas properties, collected or paid by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors. 12. Salary Deferral Plan The Company maintains a salary deferral plan (the “Plan”) in accordance with Internal Revenue Code Section 401(k), as amended. The Plan provides for matching contributions, of which $ 301,837 and $ 304,955 were made in 2022 and 2021, respectively 13. Earnings per Share Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. The following reconciles amounts reported in the consolidated financial statements: Years Ended December 31, 2022 2021 Net Income (In 000’s) Weighted Average Number of Shares Outstanding Per Share Amount Net Income (In 000’s) Weighted Average Number of Shares Outstanding Per Share Amount Basic $ 48,664 1,953,916 $ 24.91 $ 2,098 1,992,077 $ 1.05 Effect of dilutive securities: Options — 757,254 752,085 Diluted $ 48,664 2,711,170 $ 17.95 $ 2,098 2,744,162 $ 0.76 F-23 Table of Contents PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES SUPPLEMENTARY INFORMATION CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES (Unaudited) As of December 31, (Thousands of dollars) 2022 2021 Proved Developed oil and gas properties $ 555,280 $ 539,484 Proved Undeveloped oil and gas properties — — Total Capitalized Costs 555,280 539,484 Accumulated depreciation, depletion and valuation allowance ( 385,811 ) ( 359,742 ) Net Capitalized Costs $ 169,469 $ 179,742 COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES (Unaudited) Years Ended December 31, (Thousands of dollars) 2022 2021 Development Costs $ 13,598 $ 18,678 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES (Unaudited) As of December 31, (Thousands of dollars) 2022 2021 Future cash inflows $ 994,842 $ 501,431 Future production costs ( 378,160 ) ( 207,697 ) Future development costs ( 95,746 ) ( 18,507 ) Future income tax expenses ( 110,439 ) ( 57,798 ) Future Net Cash Flows 410,497 217,429 10% annual discount for estimated timing of cash flows ( 165,961 ) ( 81,623 ) Standardized Measure of Discounted Future Net Cash Flows $ 244,536 $ 135,806 See accompanying Notes to Supplementary Information F-24 Table of Contents PRIMEENERGY RESOURES CORPORATION AND SUBSIDIARIES SUPPLEMENTARY INFORMATION STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN RELATING TO PROVED OIL AND GAS RESERVES (Unaudited) The following are the principal sources of change in the standardized measure of discounted future net cash flows during 2022 and 2021: Years Ended December 31, (Thousands of dollars) 2022 2021 Sales of oil and gas produced, net of production costs $ ( 86,302 ) $ ( 45,322 ) Net changes in prices and production costs 72,640 143,750 Extensions, discoveries and improved recovery 126,029 6,440 Revisions of previous quantity estimates ( 10,902 ) 18,991 Net change in development costs ( 2,814 ) ( 12,904 ) Reserves sold ( 818 ) ( 136 ) Reserves purchased — — Accretion of discount 13,581 4,162 Net change in income taxes ( 8,435 ) ( 21,180 ) Changes in production rates (timing) and other 5,751 386 Net change 108,730 94,187 Standardized measure of discounted future net cash flow: Beginning of year 135,806 41,619 End of year $ 244,536 $ 135,806 See accompanying Notes to Supplementary Information F-25 Table of Contents PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES SUPPLEMENTARY INFORMATION RESERVE QUANTITY INFORMATION Years Ended December 31, 2022 and 2021 (Unaudited) As of December 31, 2022 2021 Oil (MBbls) NGL’s (MBbls) Gas (MMcf) Oil (MBbls) NGLs (MBbls) Gas (MMcf) Proved Developed Reserves: Beginning of year 5,386 2,882 23,902 2,684 2,258 13,633 Extensions, discoveries and improved recovery 99 74 464 69 1 628 Revisions of previous estimates ( 375 ) ( 37 ) 1,309 1,639 813 11,836 Converted from undeveloped reserves — — — 1,747 231 1,067 Reserves sold ( 28 ) ( 5 ) ( 73 ) ( 15 ) ( 5 ) ( 26 ) Reserve purchased — — — — — — Production ( 939 ) ( 417 ) ( 3,325 ) ( 738 ) ( 416 ) ( 3,236 ) End of year 4,143 2,497 22,277 5,386 2,882 23,902 Proved Undeveloped Reserves: Beginning of year — — — 1,784 787 3,897 Extensions, discoveries and improved recovery 3,028 1,833 9,030 ( 61 ) ( 557 ) ( 2,726 ) Revisions of previous estimates — — — 31 4 386 Converted to developed reserves — — — ( 1,747 ) ( 231 ) ( 1,067 ) Reserves Sold — — — ( 7 ) ( 4 ) ( 489 ) End of year 3,028 1,833 9,030 — — — Total Proved Reserves at the End of the Year 7,171 4,330 31,307 5,386 2,882 23,902 RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES Years Ended December 31, 2022 and 2021 (Unaudited) Years Ended December 31, (Thousands of dollars) 2022 2021 Revenue: Oil and gas sales $ 124,118 $ 73,126 Costs and Expenses: Lease operating expenses 37,816 27,804 Depreciation, depletion and accretion 28,068 26,325 Income tax expense 10,329 3,989 Total Costs and Expenses 76,213 58,118 Results of Operations from Producing Activities (excluding corporate overhead and interest costs) $ 47,905 $ 15,008 See accompanying Notes to Supplementary Information F-26 Table of Contents PRIMEENERGY RESOURCES CORPORATION AND SUBSIDIARIES NOTES TO SUPPLEMENTARY INFORMATION (Unaudited) 1. Presentation of Reserve Disclosure Information Reserve disclosure information is presented in accordance with U.S. generally accepted accounting principles. The Company’s reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 10 % of the Company’s reserves. 2. Determination of Proved Reserves The estimates of the Company’s proved reserves were determined by an independent petroleum engineer in accordance with U.S. generally accepted accounting principles. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development and other factors. Estimated future net revenues were computed by reserves, less estimated future development and production costs based on current costs. Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future. 3. Results of Operations from Oil and Gas Producing Activities The results of operations from oil and gas producing activities were prepared in accordance with U.S. generally accepted accounting principles. General and administrative expenses, interest costs and other unrelated costs are not deducted in computing results of operations from oil and gas activities. 4. Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves The standardized measure of discounted future net cash flows relating to proved oil and gas reserves and the changes of standardized measure of discounted future net cash flows relating to proved oil and gas reserves were prepared in accordance with U.S. generally accepted accounting principles. Future cash inflows are computed as described in Note 2 by applying current prices to year-end quantities of proved reserves. Future production and development costs are computed estimating the expenditures to be incurred in developing and producing the oil and gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are calculated by applying the U.S. tax rate to future pre-tax cash inflows relating to proved oil and gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences and tax credits and allowances relating to the proved oil and gas reserves. Future net cash flows are discounted at a rate of 10 % annually (pursuant to applicable guidance) to derive the standardized measure of discounted future net cash flows. This calculation does not necessarily represent an estimate of fair market value or the present value of such cash flows since future prices and costs can vary substantially from year-end and the use of a 10 % discount figure is arbitrary. F-27 Table of Contents 5. Changes in Reserves The 2022 and 2021 extensions and discoveries reflect the drilling activity in the Company’s West Texas and Mid-Continent areas. The Company is employing technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of its proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data and well test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques. Future development plans are reflective of the current commodity prices and have been established based on an expectation of available cash flows from operations and availability under our revolving credit facility. F-28