MEXCO ENERGY CORP 10-K

ITEM 9A. CONTROLS AND PROCEDURES Management’s Annual Report on Internal Control over Financial Reporting. The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated 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. Our internal control over financial reporting is supported by appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel, and a written Code of Conduct adopted by our Board, applicable to all directors, officers and employees of Mexco. 31 Our chief executive officer and chief financial officer assessed the effectiveness our internal control over financial reporting using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in the 2013 “Internal Control - Integrated Framework”. Based upon that evaluation, our chief executive officer and chief financial officer concluded that our internal control over financial reporting was effective as of March 31, 2025. Evaluation of Disclosure Controls and Procedures. We maintain disclosure controls and procedures to ensure that the information we must disclose in our filings with the SEC is recorded, processed, summarized and reported on a timely basis. At the end of the period covered by this report, our principal executive officer and principal financial officer reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e). Based on such evaluation, such officers concluded that, as of March 31, 2025, our disclosure controls and procedures were effective. Changes in Internal Control over Financial Reporting. No changes in the Company’s internal control over financial reporting occurred during the year ended March 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. ITEM 9B. OTHER INFORMATION None ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTION Not applicable PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE See “Mexco Energy Corporation Board of Directors”, “Named Executive Officers Who Are Not Directors”, “Section 16(a) Beneficial Ownership Reporting Compliance”, “Corporate Governance and Code of Business Conduct” and “Meetings and Committees of the Board of Directors” in the Proxy Statement of Mexco Energy Corporation for our Annual Meeting of Stockholders to be held September 9, 2025 (“Proxy Statement”) to be filed with the SEC within 120 days after the end of our fiscal year ended March 31, 2025, which is incorporated herein by reference. The information required by this item with respect to executive officers of the Company is also set forth in Part I of this report. ITEM 11. EXECUTIVE COMPENSATION The information required by this item will be contained in the Proxy Statement under the caption “Executive Compensation”, and is hereby incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS The information required by this item will be contained in the Proxy Statement under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Employee Incentive Stock Option Plans”, and is hereby incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE The information required by this item will be contained in the Proxy Statement under the captions “Certain Relationships and Related Transactions” and “Meetings and Committees of the Board of Directors”, and is hereby incorporated by reference herein. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES The information required by this item will be contained in the Proxy Statement under the caption “Audit Fees and Services”, and is hereby incorporated by reference herein. PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES Consolidated Financial Statements. For a list of the consolidated financial statements filed as part of this Form 10-K, see the “Index to Consolidated Financial Statements” set forth on F-1 of this report. Financial Statement Schedules. All schedules have been omitted because they are not applicable, not required under the instructions or the information requested is set forth in the consolidated financial statements or related notes thereto. Exhibits. For a list of the exhibits required by this Item and accompanying this Form 10-K see the “Index to Exhibits” set forth on page 37 of this report. ITEM 16. FORM 10-K SUMMARY None 32 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. MEXCO ENERGY CORPORATION By: /s/ Nicholas C. Taylor By: /s/ Tamala L. McComic Chairman of the Board and Chief Executive Officer President and Chief Financial Officer Dated: June 27, 2025 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of June 27, 2025, by the following persons on behalf of the Registrant and in the capacity indicated. /s/ Nicholas C. Taylor Nicholas C. Taylor Chief Executive Officer, Chairman of the Board of Directors /s/ Tamala L. McComic Tamala L. McComic Chief Financial Officer, President, Treasurer and Assistant Secretary /s/ Michael J. Banschbach Michael J. Banschbach Director /s/ Kenneth L. Clayton Kenneth L. Clayton Director /s/ Thomas R. Craddick Thomas R. Craddick Director /s/ Thomas H. Decker Thomas H. Decker Director /s/ Christopher M. Schroeder Christopher M. Schroeder Director 33 Glossary of Abbreviations and Terms The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report. Basin. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate. Bbl . One stock tank barrel, or 42 U.S. gallons of liquid volume, used herein in reference to crude oil, condensate or natural gas liquids hydrocarbons. BOE. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil. BTU. British thermal unit. Completion . The installation of permanent equipment for the production of oil or natural gas. Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve. Credit Facility. A line of credit provided by a bank or group of banks, secured by oil and gas properties. DD&A. Refers to depreciation, depletion and amortization of the Company’s property and equipment. Developed acreage . The number of acres which are allocated or assignable to producing wells or wells capable of production. Development costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves. Development well . A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. Dry hole . A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. Exploration. The search for natural accumulations of oil and natural gas by any geological, geophysical or other suitable means. Exploratory well . A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. Extensions and discoveries . As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. Formation. A layer of rock which has distinct characteristics that differs from nearby rock. Gross acres or wells. Refers to the total acres or wells, as the case may be, in which an interest is owned any amount of working interest. Lease. An instrument which grants to another (the lessee) the exclusive right to enter and explore for, drill for, produce, store and remove oil and natural gas from the mineral interest, in consideration for which the lessor is entitled to certain rents and royalties payable under the terms of the lease. Typically, the duration of the lessee’s authorization is for a stated term of years and “for so long thereafter” as minerals are producing. Mcf . One thousand cubic feet of natural gas. 34 MBOE . One thousand barrels of oil equivalent. MMBOE . One million barrels of oil equivalent. MMBtu . One million British thermal units of energy commonly used to measure heat value or energy content of natural gas. Natural gas liquids (“NGLs”) . Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline. Net acres or wells. Refers to gross acres or wells multiplied, in each case, by the percentage interest owned by the Company. Net production . Oil and gas production that is owned by the Company, less royalties and production due others. Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests. Oil . Crude oil or condensate. Operator . The individual or company responsible for the exploration, development and production of an oil or natural gas well or lease. Overriding royalty interest (“ORRI”). A royalty interest that is created out of the operating or working interest. Its term is coextensive with that of the operating interest from which it was created. Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells. Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed operating and production expenses and taxes. Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons. Proved developed nonproducing reserves (“PDNP”) . Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. Proved developed producing reserves (“PDP”). Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. Proved developed reserves. The combination of proved developed producing and proved developed nonproducing reserves. Proved reserves. The estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. Proved undeveloped reserves (“PUD”) . Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. 35 PV-10. When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses except for specific general and administrative expenses incurred to operate the properties, discounted to a present value using an annual discount rate of 10%. Recompletion. A process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production. Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs. Royalty . An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage, or of the proceeds of the sale thereof, but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. Standardized measure of discounted future net cash flows . The discounted future net cash flows relating to proved reserves based on prices used in estimating the reserves, year-end costs, and statutory tax rates, and a 10% annual discount rate. The information for this calculation is included in the note regarding disclosures about oil and gas reserve data contained in the Notes to Consolidated Financial Statements included in this Form 10-K. Undeveloped acreage . Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. Unit. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement. Wellbore. The hole drilled by the bit that is equipped for crude oil or natural gas production on a completed well. Also called well or borehole. Working interest . An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden. 36 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm F-2 Consolidated Balance Sheets F-4 Consolidated Statements of Operations F-5 Consolidated Statements of Changes in Stockholders’ Equity F-6 Consolidated Statements of Cash Flows F-7 Notes to Consolidated Financial Statements F-8 F- 1 Report of Independent Registered Public Accounting Firm Board of Directors and Shareholders Mexco Energy Corporation Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Mexco Energy Corporation (a Colorado corporation) and Subsidiaries (the Company) as of March 31, 2025 and 2024, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the two years in the period ended March 31, 2025, 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 March 31, 2025 and 2024, and the results of its operations and its cash flows for each of the two years in the period ended March 31, 2025, in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the entity’s management. Our responsibility is to express an opinion on these 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 entity’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. Estimation of proved reserves impacting the recognition and valuation of depletion expense and impairment of oil and gas properties. F- 2 Critical Accounting Matter Description As described in Note 2 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 revenues and expenses to calculate depletion expense. To estimate the volume of proved reserves and future revenues, 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 expense. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense and impairment evaluation, as a critical audit matter. 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, which require a high degree of subjectivity necessary to estimate the volume and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or the impairment assessment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment. How the Critical Audit Matter Was Addressed in the Audit We obtained an understanding of the design and implementation of management’s controls and our audit procedures related to the estimation of proved reserves included the following, among others. ● We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers 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, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, such as commodity pricing, historical pricing differentials, operating costs, estimated capital costs and working and net revenue 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 as follows: - Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year; - Evaluated the models used to estimate the operating costs at year-end compared to historical operating costs; - Compared the models used to determine the future capital expenditures and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells; - Evaluated the working and net revenue interests used in the reserve report by inspecting a sample of ownership interests, historical pricing differentials, and operating costs to underlying support from the Company’s accounting records. - 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 or the operator’s intent to develop the proved undeveloped properties; - Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report. /s/ WEAVER AND TIDWELL, L.L.P. We have served as the Company’s auditor since 2017. PCAOB ID # 410 Midland, Texas June 27, 2025 F- 3 Mexco Energy Corporation and Subsidiaries CONSOLIDATED BALANCE SHEETS March 31, March 31, 2025 2024 ASSETS Current assets Cash and cash equivalents $ 1,753,955 $ 2,473,484 Accounts receivable: Oil and natural gas sales 1,113,588 1,001,709 Trade 67,951 9,186 Prepaid drilling 24,381 148,748 Prepaid costs and expenses 60,981 56,193 Total current assets 3,020,856 3,689,320 Property and equipment, at cost Oil and gas properties, using the full cost method 51,611,782 48,304,585 Other 121,926 121,926 Accumulated depreciation, depletion and amortization ( 36,637,530 ) ( 34,184,837 ) Property and equipment, net 15,096,178 14,241,674 Investment – cost basis 2,100,000 1,100,000 Operating lease, right-of-use asset 126,525 19,263 Other noncurrent assets 4,298 8,597 Total assets $ 20,347,857 $ 19,058,854 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable and accrued expenses $ 307,387 $ 221,603 Income tax payable 192,802 189,254 Operating lease liability, current 51,003 19,263 Total current liabilities 551,192 430,120 Long-term liabilities Operating lease liability, long-term 75,522 - Deferred income tax liability 320,604 311,661 Asset retirement obligations 688,842 688,808 Total long-term liabilities 1,084,968 1,000,469 Total liabilities 1,636,160 1,430,589 Commitments and contingencies - - Stockholders’ equity Preferred stock - $ 1.00 par value; 10,000,000 shares authorized; none outstanding - - Common stock - $ 0.50 par value; 40,000,000 shares authorized; 2,239,283 and 2,226,916 shares issued; and, 2,046,000 and 2,091,399 shares outstanding as of March 31, 2025 and 2024 1,119,641 1,113,458 Additional paid-in capital 8,844,953 8,567,856 Retained earnings 10,625,849 9,122,481 Treasury stock, at cost ( 193,283 and 135,517 shares, respectively) ( 1,878,746 ) ( 1,175,530 ) Total stockholders’ equity 18,711,697 17,628,265 Total liabilities and stockholders’ equity $ 20,347,857 $ 19,058,854 The accompanying notes to the consolidated financial statements are an integral part of these statements. F- 4 Mexco Energy Corporation and Subsidiaries CONSOLIDATED STATEMENTS OF OPERATIONS Years ended March 31, 2025 2024 Operating revenues: Oil sales $ 6,145,674 $ 5,348,257 Natural gas sales 970,811 1,114,390 Other 241,581 142,237 Total operating revenues 7,358,066 6,604,884 Operating expenses: Production 1,605,096 1,526,472 Accretion of asset retirement obligation 29,983 29,869 Depreciation, depletion and amortization 2,452,694 1,969,742 General and administrative 1,320,074 1,243,547 Total operating expenses 5,407,847 4,769,630 Operating income 1,950,219 1,835,254 Other income (expenses): Interest income 72,629 135,476 Interest expense ( 6,150 ) ( 5,234 ) Net other income (expense) 66,479 130,242 Income before provision for income taxes 2,016,698 1,965,496 Provision for income taxes 304,330 620,544 Net income $ 1,712,368 $ 1,344,952 Income per common share: Basic: $ 0.83 $ 0.64 Diluted: $ 0.81 $ 0.62 Weighted average common shares outstanding: Basic: 2,064,147 2,114,360 Diluted: 2,107,775 2,161,010 Dividends declared per share $ 0.10 $ 0.10 The accompanying notes to the consolidated financial statements are an integral part of these statements. F- 5 Mexco Energy Corporation and Subsidiaries CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY Years ended March 31, 2025 and 2024 Common Stock Par Value Additional Paid-In Capital Retained Earnings Treasury Stock Total Stockholders’ Equity Balance at April 1, 2023 $ 1,110,708 $ 8,321,145 $ 7,991,129 $ ( 590,495 ) $ 16,832,487 Net income - - 1,344,952 - 1,344,952 Issuance of stock through options exercised 2,750 16,912 - - 19,662 Dividends paid ( 213,600 ) ( 213,600 ) Purchase of stock ( 585,035 ) ( 585,035 ) Stock based compensation - 229,799 - - 229,799 Balance at March 31, 2024 $ 1,113,458 $ 8,567,856 $ 9,122,481 $ ( 1,175,530 ) $ 17,628,265 Balance $ 1,113,458 $ 8,567,856 $ 9,122,481 $ ( 1,175,530 ) $ 17,628,265 Net income - - 1,712,368 - 1,712,368 Issuance of stock through options exercised 6,183 71,458 - - 77,641 Dividends paid - - ( 209,000 ) - ( 209,000 ) Purchase of stock - - - ( 703,216 ) ( 703,216 ) Stock based compensation - 205,639 - - 205,639 Balance at March 31, 2025 $ 1,119,641 $ 8,844,953 $ 10,625,849 $ ( 1,878,746 ) $ 18,711,697 Balance $ 1,119,641 $ 8,844,953 $ 10,625,849 $ ( 1,878,746 ) $ 18,711,697 SHARE ACTIVITY 2025 2024 Common stock shares, issued: At beginning of year 2,226,916 2,221,416 Issued 12,367 5,500 At end of year 2,239,283 2,226,916 Common stock shares, held in treasury: At beginning of year ( 135,517 ) ( 85,416 ) Acquisitions ( 57,766 ) ( 50,101 ) At end of year ( 193,283 ) ( 135,517 ) Common stock shares, outstanding At end of year 2,046,000 2,091,399 The accompanying notes to the consolidated financial statements are an integral part of these statements. F- 6 Mexco Energy Corporation and Subsidiaries CONSOLIDATED STATEMENTS OF CASH FLOWS Years ended March 31, 2025 2024 Cash flows from operating activities: Net income $ 1,712,368 $ 1,344,952 Adjustments to reconcile net income to net cash provided by operating activities: Deferred income tax expense 8,943 311,661 Stock-based compensation 205,639 229,799 Depreciation, depletion and amortization 2,452,694 1,969,742 Accretion of asset retirement obligations 29,983 29,869 Amortization of debt issuance costs 4,299 4,309 Changes in operating assets and liabilities: (increase) Decrease in accounts receivable ( 170,644 ) 362,920 (Increase) decrease in right-of-use asset ( 107,262 ) 56,366 (increase) Decrease in prepaid expenses ( 4,788 ) 309 Increase in accounts payable and accrued expenses 69,059 16,198 Increase (decrease) in operating lease liability 107,262 ( 56,366 ) Increase in income tax payable 3,548 189,254 Settlement of asset retirement obligations ( 41,480 ) ( 25,078 ) Net cash provided by operating activities 4,269,621 4,433,935 Cash flows from investing activities: Additions to oil and gas properties ( 3,416,616 ) ( 3,349,326 ) Drilling refund 59,471 26,194 Investment in limited liability companies at cost ( 1,000,000 ) ( 400,000 ) Proceeds from sale of oil and gas properties and equipment 202,570 306,633 Net cash used in investing activities ( 4,154,575 ) ( 3,416,499 ) Cash flows from financing activities: Proceeds from exercise of stock options 77,641 19,662 Proceeds from long-term debt 650,000 275,000 Debt issuance costs - ( 750 ) Dividends paid ( 209,000 ) ( 213,600 ) Acquisition of treasury stock ( 703,216 ) ( 585,035 ) Reduction of long-term debt ( 650,000 ) ( 275,000 ) Net cash used in financing activities ( 834,575 ) ( 779,723 ) Net (decrease) increase in cash and cash equivalents ( 719,529 ) 237,713 Cash and cash equivalents at beginning of year 2,473,484 2,235,771 Cash and cash equivalents at end of year $ 1,753,955 $ 2,473,484 Supplemental disclosure of cash flow information: Cash paid for interest $ 1,852 $ 925 Cash paid for income taxes $ 228,487 $ - Accrued capital expenditures included in accounts payable $ 38,417 $ 21,693 Non-cash investing and financing activities: Asset retirement obligations $ 5,231 $ 7,617 The accompanying notes to the consolidated financial statements are an integral part of these statements. F- 7 MEXCO ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Years Ended March 31, 2025 and 2024 1. Nature of Operations Mexco Energy Corporation (a Colorado corporation) and its wholly owned subsidiaries, Forman Energy Corporation (a New York corporation), Southwest Texas Disposal Corporation (a Texas corporation) and TBO Oil & Gas, LLC (a Texas limited liability company) (collectively, the “Company”) are engaged in the acquisition, exploration, development and production of crude oil, natural gas, condensate and natural gas liquids (“NGLs”). Most of the Company’s oil and gas interests are centered in West Texas and Southeastern New Mexico; however, the Company owns producing properties and undeveloped acreage in fourteen states. All of the Company’s oil and gas interests are operated by others. 2. Summary of Significant Accounting Policies Principles of Consolidation . The consolidated financial statements include the accounts of Mexco Energy Corporation and its wholly owned subsidiaries. All significant intercompany balances and transactions associated with the consolidated operations have been eliminated. Estimates and Assumptions . In preparing financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”), management is required to make informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the consolidated financial statements and affect the reported amounts of revenues and expenses during the reporting period. In addition, significant estimates are used in determining proved oil and gas reserves. Although management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates. The estimate of the Company’s oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect these reported results. Cash and Cash Equivalents . The Company considers all highly liquid debt instruments purchased with maturities of three months or less and money market funds to be cash equivalents. The Company maintains cash in bank deposit accounts that may, at times, exceed federally insured limits. At March 31, 2025, the Company had on deposit all of its cash and cash equivalents with three financial institutions. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk. Accounts Receivable . Accounts receivable includes trade receivables from joint interest owners and oil and gas purchasers. Credit is extended based on an evaluation of a customer’s financial condition and, generally, is uncollateralized. The collectibility of receivables is assessed and an allowance is made for any credit losses. The allowance for credit losses is determined based on a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company has not experienced any significant credit losses. For the years ended March 31, 2025 and 2024, no allowance has been made for any credit losses. Oil and Gas Properties . The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs are capitalized and amortized on a composite unit of production method based on proved oil and natural gas reserves. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation (“ARO”) when incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas. This includes any sales of properties such as Term Assignments and Assignments, Bill of Sales and Conveyances. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. F- 8 Excluded Costs . Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the depreciation, depletion and amortization (“DD&A”) pool). Impairments transferred to the DD&A pool increase the DD&A rate. No costs were excluded for the years ended March 31, 2025 and 2024. Ceiling Test . Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is the after-tax present value of the future net cash flows from proved crude oil and natural gas reserves and using an average price over the prior first day of the month 12-month period held flat for the life of production plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, the Company must charge the amount of the excess to earnings as an expense reflected in additional accumulated DD&A. This is called a “ceiling limitation write-down.” This impairment to our oil and gas properties does not impact cash flow from operating activities, but does reduce stockholders’ equity and reported earnings. Depreciation, Depletion and Amortization . The depreciable base for oil and gas properties includes the sum of capitalized costs, net of accumulated DD&A, estimated future development costs and asset retirement costs not accrued in oil and gas properties, less costs excluded from amortization and salvage. The depreciable base of oil and gas properties is amortized using the unit-of-production method. Asset Retirement Obligations . The Company has significant obligations to plug and abandon natural gas and crude oil wells and related equipment at the end of oil and gas production operations. The Company records the fair value of a liability for an ARO in the period in which it is incurred and a corresponding increase in the carrying amount of the related asset. Subsequently, the asset retirement costs included in the carrying amount of the related asset are allocated to expense using the units of production method. In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense in the Consolidated Statements of Operations. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. The Company uses the present value of estimated cash flows related to the ARO to determine the fair value. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset. Income Taxes . The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates applicable to the years in which those differences are expected to be settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income in the period that includes the enactment date. Any interest and penalties are recorded as interest expense and general and administrative expense, respectively. Other Property and Equipment . Provisions for depreciation of office furniture and equipment are computed on the straight-line method based on estimated useful lives of three 3 to ten years . Income Per Common Share . Basic net income per share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted net income per share assumes the exercise of all stock options having exercise prices less than the average market price of the common stock during the period using the treasury stock method and is computed by dividing net income by the weighted average number of common shares and dilutive potential common shares (stock options) outstanding during the period. In periods where losses are reported, the weighted-average number of common shares outstanding excludes potential common shares, because their inclusion would be anti-dilutive. F- 9 Revenue Recognition . Revenues from our royalty and non-operated working interest properties are recorded in accordance with ASC 606, Revenue from Contracts with Customers. Revenue is reported net of post-production costs when such costs are contractually deducted by the operator prior to distribution. Since the revenue checks are generally received two to three months after the production month, the Company accrues for revenue earned but not received by estimating production volumes and product prices. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. Stock-based Compensation . The Company uses the Binomial option pricing model to estimate the fair value of stock-based compensation expenses at grant date. This expense is recognized as compensation expense in its consolidated financial statements over the vesting period. The Company recognizes the fair value of stock-based compensation awards as wages within general and administrative expense in the Consolidated Statements of Operations based on a graded-vesting schedule over the vesting period. Reclassifications . Certain amounts in prior periods’ consolidated financial statements have been reclassified to conform with the current period’s presentation. These reclassifications had no effect on previously reported results of operations, retained earnings or net cash flows. Investments . The Company accounts for investments of less than 3% in limited liability companies at cost . The Company has no control of the limited liability companies. The cost of the investment is recorded as an asset on the consolidated balance sheets and when income from the investment is received, it is immediately recognized on the consolidated statements of operations. The Company evaluates investments for an impairment whenever events or changes in circumstances indicate that the carrying amount of an investment may not be recoverable. Indicators of impairment may include, but are not limited to, sustained declines in market value, investee financial condition and operating performance, industry or economic trends, and other relevant factors. Segments . Based on the Company’s organizational structure, the Company has one operating segment, which is crude oil and natural gas development, exploration and production. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise. Liquidity and Capital Resources . Historically, we have funded our operations, acquisitions, exploration and development expenditures from cash generated by operating activities, bank borrowings, sales of non-core properties and issuance of common stock. Our long-term strategy is on increasing profit margins while concentrating on obtaining reserves with low-cost operations by acquiring and developing oil and gas properties with potential for long-lived production. We focus our efforts on the acquisition of royalties and working interest, non-operated properties in areas with significant development potential. Recently Adopted Accounting Pronouncements . In December 2023, the FASB issued ASU 2023-09, Topic 740 Income Taxes: Improvements to Income Tax Disclosures, which is intended to enhance the transparency and decision usefulness of income tax disclosures. The amendments in this standard provide for enhanced income tax information primarily through changs to the rate reconciliation and income taxes paid. This ASU is effective for fiscal years beginning after December 15, 2024. While the adoption of this ASU will modify the company’s disclosures, it will not have an impact on the Company’s financial position, results of operations, or liquidity. New Accounting Pronouncements Not Yet Adopted . In November 2024, the FASB issued ASU 2024-03, Topic 220 Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures: Disaggregation of the Income Statement Expenses. The amendments in this update require disclosure in the Company’s annual and interim consolidated financial statements of specified information about certain costs and expenses, including depletion, depreciation and amortization recognized as part of crude oil and natural gas producing activities, and employee compensation. This ASU is effective for fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. While the adoption of this ASU will modify the company’s disclosures, it will not have an impact on the Company’s financial position, results of operations, or liquidity. 3. Long-Term Debt On December 28, 2018, the Company entered into a loan agreement (the “Agreement”) with West Texas National Bank (“WTNB”), which originally provided for a credit facility of $ 1,000,000 with a maturity date of December 28, 2021 . The Agreement has no monthly commitment reduction and a borrowing base to be evaluated annually. On February 28, 2020, the Agreement was amended to increase the credit facility to $ 2,500,000 , extend the maturity date to March 28, 2023 and increase the borrowing base to $ 1,500,000 . On March 28, 2023, the Agreement was amended to extend the maturity date to March 28, 2026 . Under the Agreement, interest on the facility accrues at a rate equal to the prime rate as quoted in the Wall Street Journal plus one-half of one percent (.5%) floating daily. Interest on the outstanding amount under the Agreement is payable monthly. In addition, the Company will pay an unused commitment fee in an amount equal to one-half of one percent (.5%) times the daily average of the unadvanced amount of the commitment. The unused commitment fee is payable quarterly in arrears on the last day of each calendar quarter. As of March 31, 2025, there was $ 1,500,000 available for borrowing by the Company on the facility. F- 10 No principal payments are anticipated to be required through the maturity date of the credit facility, March 28, 2026 . Upon closing the second amendment to the Agreement, the Company paid a loan origination fee of $ 9,000 plus legal and recording expenses totaling $ 12,950 , which are amortized over the life of the credit facility. Amounts borrowed under the Agreement are collateralized by the common stock of the Company’s wholly owned subsidiaries and substantially all of the Company’s oil and gas properties. The Agreement contains customary covenants for credit facilities of this type including limitations on change in control, disposition of assets, mergers and reorganizations. The Company is also obligated to meet certain financial covenants under the Agreement and requires senior debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”) ratios (Senior Debt/EBITDA) less than or equal to 4.00 to 1.00 measured with respect to the four trailing quarters and minimum interest coverage ratios (EBITDA/Interest Expense) of 2.00 to 1.00 for each quarter. In addition, the Agreement prohibits the Company from paying cash dividends on its common stock without prior written permission of WTNB. The Company obtained written permission from WTNB prior to declaring the special dividend on April 10, 2023 and the regular annual dividend on April 30, 2024 as discussed in Note 9. The Agreement does not permit the Company to enter into hedge agreements covering crude oil and natural gas prices without prior WTNB approval. There was no balance outstanding on the credit facility as of March 31, 2025. The following table is a summary of activity on the WTNB credit facility for the years ended March 31, 2025 and 2024: Summary of Line of Credit Activity Principal Balance at April 1, 2023: $ - Borrowings 275,000 Repayments ( 275,000 ) Balance at March 31, 2024: $ - Borrowings 650,000 Repayments ( 650,000 ) Balance at March 31, 2025: $ - 4. Asset Retirement Obligations The Company’s asset retirement obligations relate to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties. The ARO is included on the consolidated balance sheets with the current portion being included in the accounts payable and accrued expenses. The following table provides a rollforward of the asset retirement obligations for fiscal years ended March 31: Schedule of Rollforward of Asset Retirement Obligations 2025 2024 Carrying amount of asset retirement obligations, beginning of year $ 718,808 $ 730,276 Liabilities incurred 5,231 7,617 Liabilities settled ( 35,180 ) ( 48,954 ) Accretion expense 29,983 29,869 Revisions - - Carrying amount of asset retirement obligations, end of year 718,842 718,808 Less: Current portion 30,000 30,000 Non-Current asset retirement obligation $ 688,842 $ 688,808 5. Income Taxes In August 2022, President Biden signed the Inflation Reduction Act of 2022 (“IRA 2022”). The IRA 2022, among other tax provisions, imposes a 15% corporate alternative minimum tax on adjusted financial statement income of certain large corporations (generally, corporations reporting more than $1 billion of average adjusted pre-tax net income on their consolidated financial statements), effective for tax years beginning after December 31, 2022. The IRA 2022 also establishes a 1% excise tax on stock repurchases made by publicly traded U.S. corporations, effective for stock repurchases after December 31, 2022. The IRA 2022 did not impact the Company’s current year tax provision or the Company’s consolidated financial statements. F- 11 The Company files a consolidated federal income tax return and various state income tax returns. The amount of income taxes the Company records requires the interpretation of complex rules and regulations of federal and state taxing jurisdictions. With few exceptions, the earliest year open to examination by U.S. federal and state income tax jurisdictions is 2020. The income tax provision consists of the following for the years ended March 31, 2025 and 2024: Schedule of Income Tax Provision 2025 2024 Year Ended March 31 2025 2024 Current income tax expense: Federal $ 232,035 $ 189,254 State 63,352 119,629 Total current income tax expense $ 295,387 $ 308,883 Deferred income tax expense (benefit): Federal 56,614 311,661 State ( 47,671 ) - Total deferred income tax expense $ 8,943 $ 311,661 Total income tax expense: $ 304,330 $ 620,544 Income tax for the year ended March 31, 2025 was $ 304,330 . Income tax for the year ended March 31, 2024 was $ 620,544 . GAAP requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Significant components of net deferred tax assets (liabilities) at March 31 are as follows: Schedule of Components of Net Deferred Tax Assets (Liabilities) 2025 2024 Deferred tax assets: Percentage depletion carryforwards $ 1,283,374 $ 1,281,990 Deferred stock-based compensation 15,745 15,745 Asset retirement obligation 150,957 150,950 Net operating loss - 151,193 Other 82,083 35,345 Total deferred tax assets $ 1,532,159 $ 1,635,223 Deferred tax liabilities: Excess financial accounting bases over tax bases of property and equipment ( 1,852,763 ) ( 1,946,884 ) Deferred tax liability, net $ ( 320,604 ) $ ( 311,661 ) Valuation allowance - - Net deferred tax liabilities $ ( 320,604 ) $ ( 311,661 ) As of March 31, 2025, the Company has a statutory depletion carryforward of approximately $ 6,100,000 , which does not expire. F- 12 A reconciliation of the provision for income taxes to income taxes computed using the federal statutory rate for years ended March 31 follows: Schedule of Reconciliation of Provision for Income Taxes 2025 2024 Tax expense at federal statutory rate (1) $ 423,507 $ 412,754 Statutory depletion carryforward ( 153,438 ) 152,054 Change in valuation allowance - ( 3,578 ) Permanent differences 22,206 46,819 State income expense, net of federal benefit 50,048 94,507 Other ( 37,993 ) ( 82,012 ) Total income tax $ 304,330 $ 620,544 Effective income tax rate 15.1 % 31.6 % (1) The federal statutory rate was 21 % for fiscal years ending March 31, 2025 and 2024. For the years ended March 31, 2025 and 2024, the Company did no t have any uncertain tax positions. While the amount of unrecognized tax benefits may change in the next 12 months, the Company does not expect any change to have a significant impact on its results of operations. The recognition of the total amount of the unrecognized tax benefits would have an impact on the effective tax rate. If these unrecognized tax benefits are disallowed, the Company will be required to pay additional taxes. 6. Major Customers Currently, the Company operates exclusively within the United States and its revenues and operating profit are derived from the oil and gas industry. Oil and gas production is sold to various purchasers and the receivables are unsecured. Historically, the Company has not experienced significant credit losses on its oil and gas accounts and management is of the opinion that significant credit risk does not exist. Management is of the opinion that the loss of any one purchaser would not have an adverse effect on the Company’s ability to sell its oil and gas production. In fiscal 2025, Purchaser A accounted for 58 % of the total operating revenues and 43 % of the total oil and natural gas accounts receivable; Purchaser B accounted for 5 % of the total operating revenues and 6 % of the total oil and natural gas accounts receivable; and, Purchaser C accounted for 4 % of the total operating revenues and 11 % of the total oil and natural gas accounts receivable. In fiscal 2024, Purchaser A accounted for 59 % of the total operating revenues and 48 % of the total oil and natural gas accounts receivable and Purchaser B accounted for 8 % of the total operating revenues and 8 % of the total oil and natural gas accounts receivable. 7. Oil and Natural Gas Costs The costs related to the Company’s oil and natural gas activities were incurred as follows for the years ended March 31: Schedule of Cost Related to Oil and Gas Activities 2025 2024 Property acquisition costs: Proved $ 1,984,243 $ 1,826,266 Unproved - - Exploration 31,934 153,039 Development 1,417,163 1,363,529 Capitalized asset retirement obligations 5,231 7,617 Total costs incurred for oil and gas properties $ 3,438,571 $ 3,350,451 F- 13 The Company had the following aggregate capitalized costs relating to its oil and gas property activities at March 31: Schedule of Aggregate Capitalized Costs Relating Oil and Gas Property Activities 2025 2024 Proved oil and gas properties $ 51,611,782 $ 48,304,585 Unproved oil and gas properties: subject to amortization - - not subject to amortization - - Oil and gas properties, gross $ 51,611,782 $ 48,304,585 Less accumulated DD&A 36,517,279 34,066,282 Total oil and gas properties $ 15,094,503 $ 14,238,303 DD&A amounted to $ 13.74 and $ 12.81 per BOE of production for the years ended March 31, 2025 and 2024, respectively. 8. Income Per Common Share The following is a reconciliation of the number of shares used in the calculation of basic income per share and diluted income per share for the years ended March 31: Schedule of Reconciliation of Basic and Diluted Net Income (loss) Per Share 2025 2024 Net income $ 1,712,368 $ 1,344,952 Shares outstanding: Weighted avg. common shares outstanding – basic 2,064,147 2,114,360 Effect of the assumed exercise of dilutive stock options 43,628 46,650 Weighted avg. common shares outstanding – dilutive 2,107,775 2,161,010 Income per common share: Basic $ 0.83 $ 0.64 Diluted $ 0.81 $ 0.62 For the year ended March 31, 2025, 60,500 shares relating to stock options were excluded from the computation of diluted net income because their inclusion would be anti-dilutive. Anti-dilutive stock options have a weighted average exercise price of $ 15.34 at March 31, 2025. For the year ended March 31, 2024, 93,000 shares relating to stock options were excluded from the computation of diluted net income because their inclusion would be anti-dilutive. Anti-dilutive stock options have a weighted average exercise price of $ 13.12 at March 31, 2024. 9. Stockholders’ Equity In April 2024, the Company’s Board (the “Board”) authorized the use of up to $ 1,000,000 to repurchase shares of the Company’s common stock, par value, $ 0.50 , for the treasury account. This program does not have an expiration date and may be modified, suspended or terminated at any time by the Board. Under the repurchase program, share of common stock may be purchased from time to time through open market purchases or other transactions. The amount and timing of repurchases will be subject to the availability of stock, prevailing market conditions, the trading price of stock, our financial performance and other conditions. Repurchases may also be made from time-to-time in connection with the settlement of our share-based compensation awards. Repurchases will be funded from cash flow. On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA 2022”). The IRA 2022, among other tax provisions, establishes a 1 % excise tax on stock repurchases made by publicly traded U.S. corporations, effective for stock repurchases in excess of an annual limit of $ 1,000,000 after December 31, 2022. During the year ended March 31, 2025, the Company repurchased 57,766 shares for the treasury account at an aggregate cost of $ 703,216 , an average price of $ 12.17 per share per share. During the year ended March 31, 2024, the Company repurchased 50,101 shares for the treasury account at an aggregate cost of $ 585,035 , an average price of $ 11.68 per share. F- 14 10. Stock-based Compensation In September 2019, the Company adopted the 2019 Employee Incentive Stock Plan (the “2019 Plan”). The 2019 Plan provides for the award of stock options up to 200,000 shares and includes option awards as well as stock awards. Option awards are granted with the restriction of requiring payment for the shares. Stock awards are granted without restrictions and without payment by the recipient. Neither option awards nor stock awards may exceed 25,000 shares granted to any one individual in any fiscal year. Stock options may be an incentive stock option or a nonqualified stock option. Options to purchase common stock under the plan are granted at the fair market value of the common stock at the date of grant, become exercisable to the extent of 25 % of the shares optioned on each of four anniversaries of the date of grant, expire ten years from the date of grant and are subject to forfeiture if employment terminates. The 2019 Plan expires ten years from the date of adoption. According to the Company’s employee stock incentive plan, new shares will be issued upon the exercise of stock options and the Company can repurchase shares exercised under the plan. During the year ended March 31, 2025, there were no stock options granted. During the year ended March 31, 2024, the Compensation Committee of the Board of Directors approved and the Company granted 32,000 stock options. The plan also provides for the granting of stock awards. No stock awards were granted during fiscal 2025 and 2024. The Company recognized compensation expense of $ 205,639 and $ 229,799 related to vesting stock options in general and administrative expense in the Consolidated Statements of Operations for fiscal 2025 and 2024, respectively. The total cost related to non-vested awards not yet recognized at March 31, 2025 totals $ 280,173 , which is expected to be recognized over a weighted average of 1.54 years. The fair value of each stock option is estimated on the date of grant using the Binomial valuation model. Expected volatilities are based on historical volatility of the Company’s stock over the contractual term of 120 months and other factors. The Company uses historical data to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options granted are expected to be outstanding. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. No dividend yield was used in the calculation on current options outstanding because at the time of the last issuance of stock options, either no dividend had been declared or the Company had only declared a special one-time dividend. Actual value realized, if any, is dependent on the future performance of the Company’s common stock and overall stock market conditions. There is no assurance the value realized by an optionee will be at or near the value estimated by the Binomial model. Included in the following table is a summary of the grant-date fair value of stock options granted and the related assumptions used in the Binomial models for stock options granted in fiscal 2025 and 2024. All such amounts represent the weighted average amounts for each period. Schedule of Grant-date Fair Value of Stock Options Granted and Assumptions Used Binominal Models For the year ended March 31, 2025 2024 Grant-date fair value - $ 8.73 Volatility factor - 56.5 % Dividend yield - - Risk-free interest rate - 3.44 % Expected term (in years) - 6.25 No forfeiture rate is assumed for stock options granted to directors or employees due to the forfeiture rate history for these types of awards. During the year ended March 31, 2025, 2,500 unvested stock options were forfeited due to the resignation of an employee. During the year ended March 31, 2024, there were no stock options forfeited or expired. F- 15 The following table is a summary of activity of stock options for the years ended March 31, 2025 and 2024: Schedule of Activity of Stock Options Number of Shares Weighted Average Exercise Price Per Share Weighted Aggregate Average Remaining Contract Life in Years Intrinsic Value Outstanding at April 1, 2023 139,250 $ 8.36 7.04 $ 419,853 Granted 32,000 12.68 Exercised ( 5,500 ) 3.58 Forfeited or Expired - - Outstanding at March 31, 2024 165,750 $ 9.36 6.62 $ 103,275 Granted - - Exercised ( 12,367 ) 6.28 Forfeited or Expired ( 2,500 ) 14.83 Outstanding at March 31, 2025 150,883 $ 9.52 5.98 $ - Vested at March 31, 2025 105,508 $ 7.69 5.31 $ 50,431 Exercisable at March 31, 2025 105,508 $ 7.69 5.31 $ 50,431 During the year ended March 31, 2025, stock options covering 12,367 shares were exercised with a total intrinsic value of $ 92,316 . The Company received proceeds of $ 77,641 from these exercises. During the year ended March 31, 2025, stock options covering 5,500 shares were exercised with a total intrinsic value of $ 37,566 . The Company received proceeds of $ 19,662 from these exercises. Other information pertaining to option activity was as follows during the year ended March 31: Schedule of Other Information Pertaining to Option Activity 2025 2024 Weighted average grant-date fair value of stock options granted (per share) $ - $ 8.73 Total fair value of options vested $ 205,241 $ 234,025 Total intrinsic value of options exercised $ 92,316 $ 37,566 The following table summarizes information about options outstanding at March 31, 2025: Schedule of Information About Options Outstanding Range of Exercise Prices Number of Options Weighted Average Exercise Price Per Share Weighted Average Remaining Contract Life in Years Aggregate Intrinsic Value $ 3.34 – 4.83 25,677 $ 3.34 4.84 – 5.97 35,000 4.84 5.98 – 8.51 29,706 8.51 8.52 – 18.05 60,500 15.34 $ 3.34 – 18.05 150,883 $ 9.52 5.98 $ - Outstanding options at March 31, 2025 expire between September 2028 and April 2033 and have exercise prices ranging from $ 3.34 to $ 18.05 . 11. Related Party Transactions Related party transactions for the Company primarily relate to shared office expenditures in addition to administrative and operating expenses paid on behalf of the principal stockholder. The total billed to and reimbursed by the stockholder for the years ended March 31, 2025 and 2024 were $3 1,506 and $ 23,379 , respectively. The principal stockholder pays for his share of the lease amount for the shared office space directly to the lessor. Amounts paid by the principal stockholder directly to the lessor for the year ending March 31, 2025 and 2024 were $ 11,974 and $ 15,572 , respectively. F- 16 12. Commitments and Contingencies From time to time the Company is a party to litigation or other legal proceedings that the Company considers to be part of the ordinary course of business. The Company is currently not involved in any legal proceedings that it considers probable or reasonably possible, individually or in the aggregate, to result in a material adverse effect on its financial condition, results of operations or liquidity. 13. Leases The Company leases approximately 4,160 rentable square feet of office space from an unaffiliated third party for the corporate office located in Midland, Texas. This includes 702 square feet of office space shared with and paid by our principal shareholder. In June 2024, the Company agreed to extend its current lease at a flat (unescalated) rate for 36 months. The amended lease now expires on July 31, 2027 . The Company determines an arrangement is a lease at inception. Operating leases are recorded in operating lease right-of-use asset, operating lease liability, current, and operating lease liability, long-term on the consolidated balance sheet. Operating lease right-of-use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent its obligation to make lease payments arising from the lease. Operating lease assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. As the Company’s lease does not provide an implicit rate, the Company uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The incremental borrowing rate used at adoption was 9 %. Significant judgement is required when determining the incremental borrowing rate. Rent expense for lease payments is recognized on a straight-line basis over the lease term. The balance sheet classification of lease assets and liabilities was as follows: Schedule of Operating Lease Assets and Liabilities March 31, 2025 Assets Operating lease right-of-use asset, beginning balance $ 19,263 Current period amortization ( 50,811 ) Lease extension 158,073 Total operating lease right-of-use asset $ 126,525 Liabilities Operating lease liability, current $ 51,003 Operating lease liability, long term 75,522 Total lease liabilities $ 126,525 Future minimum lease payments as of March 31, 2025 under non-cancellable operating leases are as follows: Schedule of Future Minimum Lease Payments Lease Obligation Fiscal Year Ended March 31, 2026 $ 60,320 Fiscal Year Ended March 31, 2027 60,320 Fiscal Year Ended March 31, 2028 20,107 Total lease payments $ 140,747 Less: imputed interest ( 14,222 ) Operating lease liability 126,525 Less: operating lease liability, current ( 51,003 ) Operating lease liability, long term $ 75,522 Net cash paid for our operating lease for the year ended March 31, 2025 and 2024 was $ 47,653 and $ 42,668 , respectively. Rent expense, less sublease income of $ 11,974 is included in general and administrative expenses. 14. Acquisitions During the year ended March 31, 2025, the Company incurred approximately $ 2,000,000 in acquisition costs to acquire various royalty interests in approximately 840 producing wells located in Adams, Broomfield, and Weld Counties, Colorado; DeSoto Parish, Louisiana; Eddy County, New Mexico; Karnes, Live Oak, Reagan, Reeves, and Upton Counties, Texas; Laramie County, Wyoming; and multiple counties in Nebraska, North and South Dakota, and Montana. F- 17 During the year ended March 31, 2024, the Company incurred approximately $ 1,800,000 in acquisition costs to acquire various royalty interests in approximately 340 producing wells in Crane, Ector, Howard, Midland, Reeves, and Upton Counties, Texas. 15. Oil and Gas Reserve Data (Unaudited) The estimates of the Company’s proved oil and gas reserves, which are located entirely within the United States, were prepared in accordance with the generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The estimates as of March 31, 2025 and 2024 were based on evaluations prepared by Russell K. Hall and Associates, Inc. The services provided by Russell K. Hall and Associates, Inc. are not audits of our reserves but instead consist of complete engineering evaluations of the respective properties. For more information about their evaluations performed, refer to the copy of their report filed as an exhibit to this Annual Report on Form 10-K. Management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future. The following table presents the weighted average first-day-of-the-month prices used for oil and gas reserve preparation, based upon SEC guidelines. Schedule of Weighted Average First-day-of-the-month Prices Used for Oil and Gas Reserve March 31, 2025 2024 % Change Prices utilized in the reserve estimates before adjustments: Oil per Bbl $ 71.00 $ 73.96 ( 4 %) Natural gas per MMBtu $ 2.44 $ 2.45 - The Company’s total estimated proved reserves at March 31, 2025 were approximately 1.401 MBOE of which 48 % was oil and 52 % was natural gas. Changes in Proved Reserves : Schedule of Changes in Proved Reserve Oil (Bbls) Natural Gas (Mcf) Proved Developed and Undeveloped Reserves: As of April 1, 2023 727,000 4,949,000 Revision of previous estimates ( 86,000 ) ( 463,000 ) Purchase of minerals in place 24,000 121,000 Extensions and discoveries 199,000 437,000 Sales of minerals in place ( 3,000 ) ( 4,000 ) Production ( 70,000 ) ( 503,000 ) As of March 31, 2024 791,000 4,537,000 Revision of previous estimates ( 132,000 ) ( 71,000 ) Purchase of minerals in place 40,000 221,000 Extensions and discoveries 60,000 243,000 Sales of minerals in place - - Production ( 84,000 ) ( 570,000 ) As of March 31, 2025 675,000 4,360,000 Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves (“PUD”) are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion within five years of the date of their initial recognition. Moreover, the Company may be required to write down its proved undeveloped reserves if the operators do not drill on the reserves within the required five-year timeframe. Such downward revisions are primarily attributable to reserves written off due to the five-year limitation and the change in the timing of new development. The reserves written off were primarily in Lea County, New Mexico due to a change in the timing of development in wells in which we own a working interest. These interests are held by production and still in place to be developed in the future. F- 18 Summary of Proved Developed and Undeveloped Reserves as of March 31, 2025 and 2024 : Summary of Proved Developed and Undeveloped Reserves Oil (Bbls) Natural Gas (Mcf) Proved Developed Reserves: As of April 1, 2023 486,770 3,971,370 As of March 31, 2024 444,610 3,566,240 As of March 31, 2025 405,840 3,654,900 Proved Undeveloped Reserves: As of April 1, 2023 240,060 978,010 As of March 31, 2024 346,330 970,880 As of March 31, 2025 269,000 704,810 At March 31, 2025, the Company reported estimated PUDs of 386 MBOE, which accounted for 28 % of its total estimated proved oil and gas reserves. This figure primarily consists of a projected 72 new wells (296 MBOE) operated by others, 37 wells are planned to be drilled in fiscal 2026, 12 wells in fiscal 2027 and 23 wells in fiscal 2028. The cost of these projects would be funded, to the extent possible, from existing cash balances, cash flow from operations and bank borrowings. The remainder may be funded through non-core asset sales and/or sales of our common stock. The following table discloses the Company’s progress toward the conversion of PUDs during fiscal 2025. Progress of Converting Proved Undeveloped Reserves : Schedule of Progress of Converting Proved Undeveloped Reserves Oil & Natural Gas (BOE) Future Development Costs PUDs, beginning of year 508,141 $ 5,481,477 Revision of previous estimates ( 95,438 ) ( 1,621,802 ) Sales of reserves - - Conversions to PD reserves ( 84,006 ) ( 645,145 ) Additional PUDs added 57,765 797,445 PUDs, end of year 386,462 $ 4,011,975 Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2025 and 2024 along with estimates of the operating costs, production taxes and future development costs necessary to produce such reserves. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense. Operating costs and production taxes are estimated based on current costs with respect to producing oil and natural gas properties. Future development costs including abandonment costs are based on the best estimate of such costs assuming current economic and operating conditions. The future cash flows estimated to be spent to develop the Company’s share of proved undeveloped properties through March 31, 2028 are $ 4,011,975 . Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable carryforwards. The future net revenue information assumes no escalation of costs or prices, except for oil and natural gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant. F- 19 The current reporting rules require that year end reserve calculations and future cash inflows be based on the 12-month average market prices for sales of oil and gas on the first calendar day of each month during the fiscal year discounted at 10 % per year and assuming continuation of existing economic conditions. The average prices used for fiscal 2025 were $ 73.79 per bbl of oil and $ 2.14 per mcf of natural gas. The average prices used for fiscal 2024 were $ 76.88 per bbl of oil and $ 2.75 per mcf of natural gas. The standardized measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first day of the month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and natural gas reserves, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10 % per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rate to the difference. The basis for this table is the reserve studies prepared by an independent petroleum engineering consultant, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of proved oil and gas properties. The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of March 31, 2025 and 2024 in accordance with ASC 932, “Extractive Activities – Oil and Gas” which requires the use of a 10 % discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves: Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves March 31 2025 2024 Future cash inflows $ 59,135,000 $ 73,290,000 Future production costs and taxes ( 18,172,000 ) ( 21,634,000 ) Future development costs ( 4,137,000 ) ( 5,481,000 ) Future income taxes ( 4,982,000 ) ( 7,067,000 ) Future net cash flows 31,844,000 39,108,000 Annual 10% discount for estimated timing of cash flows ( 11,769,000 ) ( 14,480,000 ) Standardized measure of discounted future net cash flows $ 20,075,000 $ 24,628,000 Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves: Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows to Proved Oil and Gas Reserves March 31 2025 2024 Sales of oil and gas produced, net of production costs $ ( 5,511,000 ) $ ( 4,936,000 ) Net changes in price and production costs ( 2,735,000 ) ( 14,394,000 ) Changes in previously estimated development costs ( 1,111,000 ) ( 77,000 ) Revisions of quantity estimates ( 5,155,000 ) ( 3,620,000 ) Net change due to purchases and sales of minerals in place 1,996,000 1,146,000 Extensions and discoveries, less related costs 1,713,000 7,208,000 Net change in income taxes 1,309,000 2,208,000 Accretion of discount 2,321,000 2,908,000 Changes in timing of estimated cash flows and other 2,620,000 1,370,000 Changes in standardized measure ( 4,553,000 ) ( 8,187,000 ) Standardized measure, beginning of year 24,628,000 32,815,000 Standardized measure, end of year $ 20,075,000 $ 24,628,000 16. Subsequent Events On May 13, 2025, the Company announced that its Board declared a regular annual dividend of $ 0.10 per common share to its shareholders of record at the close of business on June 2, 2025. The regular annual dividend in the amount of $204,600 was paid on June 16, 2025. In June 2025, the Company expended approximately $ 116,000 to participate in the drilling of 5 horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Eddy County, New Mexico. The Company completed a review and analysis of all events that occurred after the consolidated balance sheet date to determine if any such events must be reported and has determined that there are no other subsequent events to be disclosed. F- 20 INDEX TO EXHIBITS Exhibit Number 3.1 Restated Articles of Incorporation of Mexco Energy Corporation filed as Exhibit 3.1 to the Company’s Annual Report on Form 10-K dated June 24, 1998, and incorporated herein by reference. 3.2 Amended Bylaws of Mexco Energy Corporation as amended on September 13, 2011 filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K dated September 14, 2011, and incorporated herein by reference. 10.1 2009 Employee Incentive Stock Plan of Mexco Energy Corporation filed as Exhibit A to the Company’s Proxy Statement on Form 14C dated July 15, 2009, and incorporated herein by reference. 10.2 2019 Employee Incentive Stock Plan of Mexco Energy Corporation filed as Exhibit A to the Company’s Proxy Statement on Form 14C dated July 16, 2019, and incorporated herein by reference. 10.3 Loan Agreement dated December 28, 2018 between West Texas National Bank and Mexco Energy Corporation filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K dated December 31, 2018, and incorporated herein by reference. 10.4 First Amendment to Loan Agreement dated February 28, 2020 to the Loan Agreement between West Texas National Bank and Mexco Energy Corporation filed as Exhibit 10.4 to the Company’s Annual Report on form 10-K filed on June 26, 2020, and incorporated herein by reference. 10.5 Second Amendment to Loan Agreement dated March 28, 2023 to the Loan Agreement between West Texas National Bank and Mexco Energy Corporation filed as Exhibit 10.5 to the Company’s Annual Report on Form 10-K dated June 26, 2023, and incorporated herein by reference. 14.1 Code of Business Conduct and Ethics of Mexco Energy Corporation filed with the Company’s Quarterly Report on Form 10-Q filed on November 15, 2004, and incorporated herein by reference. 21.1 Subsidiaries of Mexco Energy Corporation 23.1 Consent of Weaver and Tidwell, L.L.P., Independent Registered Public Accounting Firm 23.2 Consent of Russell K. Hall & Associates, Inc., Independent Petroleum Engineers 31.1 Certification of the Chief Executive Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of the Chief Financial Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification of the Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99.1 Report of Russell K. Hall & Associates, Inc., Independent Petroleum Engineering Firm 101.INS Inline XBRL Instance Document 101.SCH Inline XBRL Taxonomy Extension Schema Document 101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document 101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document 101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document 101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document 104 Cover Page Innteractive Data File (embedded within the Inline XBRL and contained in Exhibit 101) 37