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 and applicable to all directors, officers, and employees of Mexco. Our chief executive officer and chief financial officer assessed the effectiveness of 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, 2026. 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, 2026, 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, 2026 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 30 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 8, 2026 (“Proxy Statement”) to be filed with the SEC within 120 days after the end of our fiscal year ended March 31, 2026, 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 F22 of this report. ITEM 16. FORM 10-K SUMMARY None 31 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 29, 2026 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of June 29, 2026, 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 32 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. 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 that has distinct characteristics differing from nearby rock. Gross acres or wells. Refers to the total acres or wells, as the case may be, in which the Company owns a working, royalty, mineral, or other 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. 33 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 can be estimated 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. 34 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 a 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. 35 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm (PCAOB ID Number 410 ) 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 To the Board of Directors and Shareholders of 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, 2026 and 2025, 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, 2026, 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, 2026 and 2025, and the results of its operations and its cash flows for each of the two years in the period ended March 31, 2026, 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 matter communicated below is a matter 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 a critical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Estimation of proved reserves impacting the recognition and valuation of depletion expense and impairment of oil and gas properties. F- 2 Critical Audit 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. Denver, Colorado June 29, 2026 F- 3 Mexco Energy Corporation and Subsidiaries CONSOLIDATED BALANCE SHEETS March 31, March 31, 2026 2025 ASSETS Current assets Cash and cash equivalents $ 2,775,976 $ 1,753,955 Accounts receivable: Oil and natural gas sales 1,287,841 1,113,588 Trade 111,494 67,951 Prepaid drilling 204,218 24,381 Prepaid costs and expenses 68,846 60,981 Total current assets 4,448,375 3,020,856 Property and equipment, at cost Oil and gas properties, using the full cost method 53,664,668 51,611,782 Other 125,501 121,926 Accumulated depreciation, depletion and amortization ( 39,161,357 ) ( 36,637,530 ) Property and equipment, net 14,628,812 15,096,178 Investment – cost basis 2,527,429 2,100,000 Operating lease right-of-use asset 75,522 126,525 Other noncurrent assets 12,325 4,298 Total assets $ 21,692,463 $ 20,347,857 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable and accrued expenses $ 379,929 $ 307,387 Income tax payable 17,203 192,802 Operating lease liability, current 55,787 51,003 Total current liabilities 452,919 551,192 Long-term liabilities Operating lease liability, long-term 19,735 75,522 Deferred income tax liability 533,673 320,604 Asset retirement obligations 699,317 688,842 Total long-term liabilities 1,252,725 1,084,968 Total liabilities 1,705,644 1,636,160 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 shares issued and 2,046,000 shares outstanding as of March 31, 2026 and 2025 1,119,641 1,119,641 Additional paid-in capital 9,018,953 8,844,953 Retained earnings 11,726,971 10,625,849 Treasury stock, at cost ( 193,283 shares) ( 1,878,746 ) ( 1,878,746 ) Total stockholders’ equity 19,986,819 18,711,697 Total liabilities and stockholders’ equity $ 21,692,463 $ 20,347,857 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, 2026 2025 Operating revenues: Oil sales $ 5,276,981 $ 6,145,674 Natural gas sales 1,271,067 970,811 Other 13,276 23,954 Total operating revenues 6,561,324 7,140,439 Operating expenses: Production 1,428,353 1,605,096 Accretion of asset retirement obligation 32,168 29,983 Depreciation, depletion and amortization 2,523,827 2,452,694 General and administrative 1,306,275 1,320,074 Total operating expenses 5,290,623 5,407,847 Operating income 1,270,701 1,732,592 Other income (expenses): Income from investments in LLCs 329,102 217,627 Interest income 89,341 72,629 Interest expense ( 4,379 ) ( 6,150 ) Net other income 414,064 284,106 Income before provision for income taxes 1,684,765 2,016,698 Provision for income taxes 379,043 304,330 Net income $ 1,305,722 $ 1,712,368 Income per common share: Basic: $ 0.64 $ 0.83 Diluted: $ 0.63 $ 0.81 Weighted average common shares outstanding: Basic: 2,046,000 2,064,147 Diluted: 2,080,503 2,107,775 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, 2026 and 2025 Common Stock Par Value Additional Paid-In Capital Retained Earnings Treasury Stock Total Stockholders’ Equity Balance at April 1, 2024 $ 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 Net income - - 1,305,722 - 1,305,722 Dividends paid - - ( 204,600 ) - ( 204,600 ) Stock based compensation - 174,000 - - 174,000 Balance at March 31, 2026 $ 1,119,641 $ 9,018,953 $ 11,726,971 $ ( 1,878,746 ) $ 19,986,819 SHARE ACTIVITY 2026 2025 Common stock shares, issued: At beginning of year 2,239,283 2,226,916 Issued - 12,367 At end of year 2,239,283 2,239,283 Common stock shares, held in treasury: At beginning of year ( 193,283 ) ( 135,517 ) Acquisitions - ( 57,766 ) At end of year ( 193,283 ) ( 193,283 ) Common stock shares, outstanding At end of year 2,046,000 2,046,000 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, 2026 2025 Cash flows from operating activities: Net income $ 1,305,722 $ 1,712,368 Adjustments to reconcile net income to net cash provided by operating activities: Deferred income tax expense 213,069 8,943 Stock-based compensation 174,000 205,639 Depreciation, depletion and amortization 2,523,827 2,452,694 Accretion of asset retirement obligations 32,168 29,983 Amortization of debt issuance costs 4,343 4,299 Changes in operating assets and liabilities: Increase in accounts receivable ( 217,796 ) ( 170,644 ) Decrease (increase) in right-of-use asset 51,003 ( 107,262 ) Increase in prepaid expenses ( 7,866 ) ( 4,788 ) (Decrease) increase in accounts payable and accrued expenses ( 33,087 ) 69,059 (Decrease) increase in operating lease liability ( 51,003 ) 107,262 (Decrease) increase in income tax payable ( 175,599 ) 3,548 Settlement of asset retirement obligations ( 39,629 ) ( 41,480 ) Net cash provided by operating activities 3,779,152 4,269,621 Cash flows from investing activities: Additions to oil and gas properties ( 2,189,426 ) ( 3,416,616 ) Additions to other property and equipment ( 3,575 ) - Drilling refund 54,368 59,471 Investment in limited liability companies at cost ( 427,429 ) ( 1,000,000 ) Proceeds from sale of oil and gas properties and equipment 25,901 202,570 Net cash used in investing activities ( 2,540,161 ) ( 4,154,575 ) Cash flows from financing activities: Proceeds from exercise of stock options - 77,641 Proceeds from long-term debt - 650,000 Debt issuance costs ( 12,370 ) - Dividends paid ( 204,600 ) ( 209,000 ) Acquisition of treasury stock - ( 703,216 ) Reduction of long-term debt - ( 650,000 ) Net cash used in financing activities ( 216,970 ) ( 834,575 ) Net increase (decrease) in cash and cash equivalents 1,022,021 ( 719,529 ) Cash and cash equivalents at beginning of year 1,753,955 2,473,484 Cash and cash equivalents at end of year $ 2,775,976 $ 1,753,955 Supplemental disclosure of cash flow information: Cash paid for interest $ 36 $ 1,852 Cash paid for income taxes $ 362,802 $ 228,487 Accrued capital expenditures included in accounts payable $ 144,047 $ 38,417 Non-cash investing and financing activities: Asset retirement obligations $ 9,592 $ 5,231 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, 2026 and 2025 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, 2026, 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 include trade receivables from joint interest owners and oil and gas purchasers. The opening balance of accounts receivable from contracts with customers as of April 1, 2024, was $ 1,001,709 . Credit is extended based on an evaluation of a customer’s financial condition and is generally 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, 2026 and 2025, no allowance has been made for any credit losses. Oil and Gas Properties . The Company accounts for its oil and natural gas properties using the full cost method of accounting. Under this method, all costs incurred in the acquisition, exploration, and development of oil and natural gas properties are capitalized and amortized using the unit-of-production method based on proved reserves. Costs directly related to exploration and development activities are capitalized, while production costs, general corporate overhead, and similar activities are expensed as incurred. The carrying value of oil and natural gas properties includes asset retirement costs associated with the fair value of asset retirement obligations (“ARO”) when incurred. Sales or other dispositions of oil and natural gas properties, whether or not currently being amortized, are generally accounted for as adjustments to capitalized costs, with no gain or loss recognized unless the disposition significantly alters the relationship between capitalized costs and proved reserves. This treatment includes transactions involving Term Assignments and Assignments, Bills of Sale and Conveyances. Depletion of evaluated oil and natural gas properties is calculated using the unit-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, 2026 and 2025. 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 unweighted arithmetic average of the first-day-of-the-month prices for the preceding 12-month period, held constant 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 of our oil and gas properties does not affect cash flow from operating activities but does reduce stockholders’ equity and reported earnings. No impairment was recorded for the years ended March 31, 2026 or 2025. 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 accrues the estimated costs of plugging, restoration, and removal of facilities by recognizing the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which the obligation is incurred, typically at the inception of a well’s life, with a corresponding increase in the carrying amount of the related long-lived asset. The initial fair value is determined using the present value of estimated future cash flows, which incorporates management assumptions regarding ultimate plugging and abandonment costs, inflation factors, credit-adjusted risk-free discount rates, and the timing of settlement. Capitalized asset retirement costs are subsequently allocated to expense over the useful life of the related assets utilizing the units-of-production method, while the discounted ARO liability is accreted over time to its expected settlement value, with such changes reflected as accretion expense within the Consolidated Statements of Operations. Management continuously evaluates its estimates against changes in the legal, regulatory, environmental, and political environments; any subsequent revisions to the timing or amount of undiscounted estimated cash flows result in a corresponding adjustment to both the ARO liability and the carrying value of the related asset. Settlement of the liability is accounted for as an adjustment to the Company’s full cost pool with no gain or loss recognized, and for all periods presented, estimated future costs of abandonment and dismantlement are included in the full cost amortization base pursuant to SEC Regulation S-X Rule 4-10 and amortized as a component of depletion, depreciation, and amortization expense. 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 . F- 9 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. 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 revenue checks are generally received two to three months after the production month, the Company accrues revenue earned but not yet 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 grant-date fair value of stock-based awards. Compensation expense is recognized within general and administrative expense in the Consolidated Statements of Operations using the graded-vesting method over the applicable 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 utilizes the measurement alternative to account for investments when it does not possess the ability to exercise significant influence or control and the investment does not have a readily determinable fair value. Under this method, investments are initially recognized at cost and subsequently measured at cost, adjusted for any observable changes in the fair value of the investment. In addition, the Company reviews the carrying value of investments measured under the measurement alternative for impairment on a regular basis. If there is an indication of impairment, the Company assesses whether the carrying value of the investment exceeds its recoverable amount. Any impairment losses are recognized in the consolidated statements of operations. Income from these investments is recognized as Income from investments in LLCs in the consolidated statements of operations. Segments . The Company’s chief operating decision maker (“CODM”), comprised of the Chairman of the Board and the President, evaluates operating results and allocates capital resources on a consolidated basis. Accordingly, the Company has one reportable segment: crude oil and natural gas development, exploration, and production. 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 to increase 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 non-operated working interests in areas with significant development potential. 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. F- 10 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 $ 1,000,000 credit facility 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 . On September 17, 2025, WTNB reaffirmed the borrowing base at $ 1,500,000 . On March 28, 2026, the Agreement was amended to extend the maturity date to March 28, 2029 . 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, 2026, the Company had $ 1,500,000 available to borrow under the facility. No principal payments are anticipated to be required through the maturity date of the credit facility, March 28, 2029 . Upon closing the third amendment to the Agreement, the Company paid a loan origination fee of $ 9,000 plus legal expenses totaling $ 12,200 , 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 changes in control, disposition of assets, mergers, and reorganizations. The Company is also obligated to meet certain financial covenants under the Agreement including requirements that senior debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”) ratios (Senior Debt/EBITDA) is 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. Commencing with the fiscal quarter ending June 30, 2026, the amended Agreement requires the Company to maintain Senior Debt to EBITDA ratios less than or equal to 3.00 to 1.00 measured with respect to the four trailing quarters. 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 regular annual dividend in 2025 and special dividend in 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, 2026 and 2025. The following table is a summary of activity on the WTNB credit facility for the years ended March 31, 2026 and 2025: Summary of Line of Credit Activity Principal Balance at April 1, 2024: $ - Borrowings 650,000 Repayments ( 650,000 ) Balance at March 31, 2025: $ - Borrowings - Repayments - Balance at March 31, 2026: $ - F- 11 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 included in 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 2026 2025 Carrying amount of asset retirement obligations, beginning of year $ 718,842 $ 718,808 Liabilities incurred 9,592 5,231 Liabilities settled ( 31,285 ) ( 35,180 ) Accretion expense 32,168 29,983 Revisions - - Carrying amount of asset retirement obligations, end of year 729,317 718,842 Less: Current portion 30,000 30,000 Non-Current asset retirement obligation $ 699,317 $ 688,842 5. Income Taxes On July 4, 2025, the “One Big Beautiful Bill” (“OBBB”) was enacted. The OBBB is a comprehensive piece of legislation that includes significant changes to federal tax policy, environmental funding, and energy development regulations. Key provisions relevant to the crude oil and natural gas industry include (i) tax policy changes that extend and expand components of the 2017 Tax Cuts and Jobs Act and (ii) the introduction of fee and royalty-related provisions aimed at reducing financial and administrative burdens on domestic energy producers. The Company has evaluated the impact of the OBBB; however, certain provisions continue to be assessed for their impact on our consolidated financial statements in future periods. 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 2021. The income tax provision consists of the following for the years ended March 31, 2026 and 2025: Schedule of Income Tax Provision 2026 2025 Year Ended March 31 2026 2025 Current income tax expense: Federal $ 107,292 $ 232,035 State 58,682 63,352 Total current income tax expense $ 165,974 $ 295,387 Deferred income tax expense (benefit): Federal 224,910 56,614 State ( 11,841 ) ( 47,671 ) Total deferred income tax expense $ 213,069 $ 8,943 Total income tax expense: $ 379,043 $ 304,330 Income tax for the year ended March 31, 2026 was $ 379,043 . Income tax for the year ended March 31, 2025 was $ 304,330 . F- 12 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) 2026 2025 Deferred tax assets: Percentage depletion carryforwards $ 1,108,633 $ 1,283,374 Stock-based compensation 15,745 15,745 Asset retirement obligation 153,157 150,957 Other 94,650 82,083 Total deferred tax assets $ 1,372,185 $ 1,532,159 Deferred tax liabilities: Excess financial accounting bases over tax bases of property and equipment ( 1,905,858 ) ( 1,852,763 ) Deferred tax liability, net $ ( 533,673 ) $ ( 320,604 ) Valuation allowance - - Net deferred tax liabilities $ ( 533,673 ) $ ( 320,604 ) As of March 31, 2026, the Company has a statutory depletion carryforward of approximately $ 5,300,000 , which does not expire. 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 2026 % of Income Before Income Taxes 2025 % of Income Before Income Taxes Tax expense at federal statutory rate (1) $ 353,801 21.0 % $ 423,507 21.0 % Excess percentage depletion ( 63,000 ) ( 3.7 )% ( 153,438 ) ( 7.6 )% Permanent differences 30,966 1.8 % 22,206 1.1 % State income expense, net of federal benefit 37,004 2.2 % 50,048 2.5 % Other 20,272 1.2 % ( 37,993 ) ( 1.9 )% Total income tax $ 379,043 22.5 % $ 304,330 15.1 % (1) The federal statutory rate was 21 % for fiscal years ending March 31, 2026 and 2025. For the years ended March 31, 2026 and 2025, the Company did no t have any uncertain tax positions. 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 2026, BTA Oil Producers, LLC accounted for 33 % of the total operating revenues and 37 % of the total oil and natural gas accounts receivable; Apex Natural Gas LLC accounted for 2 % of the total operating revenues and 11 % of the total oil and natural gas accounts receivable; and Exxon Mobil Corporation accounted for 15 % of the total operating revenues and 7 % of the total oil and natural gas accounts receivable. In fiscal 2025, BTA Oil Producers, LLC accounted for 59 % of the total operating revenues and 43 % of the total oil and natural gas accounts receivable; Permian Resources Corporation accounted for 6 % of the total operating revenues and 6 % of the total oil and natural gas accounts receivable; and, Pioneer Natural Resources accounted for 4 % of the total operating revenues and 11 % of the total oil and natural gas accounts receivable. F- 13 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 2026 2025 Property acquisition costs: Proved $ 809,401 $ 1,984,243 Unproved - - Exploration 80,892 31,934 Development 1,170,674 1,417,163 Capitalized asset retirement obligations 9,592 5,231 Total costs incurred for oil and gas properties $ 2,070,559 $ 3,438,571 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 2026 2025 Proved oil and gas properties $ 53,664,668 $ 51,611,782 Unproved oil and gas properties: subject to amortization - - not subject to amortization - - Oil and gas properties, gross $ 53,664,668 $ 51,611,782 Less accumulated DD&A 39,040,201 36,517,279 Total oil and gas properties $ 14,624,467 $ 15,094,503 DD&A amounted to $ 11.02 and $ 13.74 per BOE of production for the years ended March 31, 2026 and 2025, 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 2026 2025 Net income $ 1,305,722 $ 1,712,368 Shares outstanding: Weighted avg. common shares outstanding – basic 2,046,000 2,064,147 Effect of the assumed exercise of dilutive stock options 34,503 43,628 Weighted avg. common shares outstanding – dilutive 2,080,503 2,107,775 Income per common share: Basic $ 0.64 $ 0.83 Diluted $ 0.63 $ 0.81 For the years ended March 31, 2026 and 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, 2026. F- 14 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 has no expiration date and may be modified, suspended, or terminated at any time by the Board. Under the repurchase program, 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. As of March 31, 2026, the Company’s repurchase program approved in April 2024 had $ 296,784 in remaining funds. Subsequently, in June 2026, the Board authorized the use of an additional $ 250,000 to repurchase shares of the Company’s common stock, par value $ 0.50 , for the treasury account. To date, the Company’s repurchase program has $ 546,784 remaining. During the year ended March 31, 2026, no shares of common stock were repurchased for the treasury account. 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. 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. The Company recognized compensation expense of $ 174,000 and $ 205,639 related to vesting stock options in general and administrative expense in the Consolidated Statements of Operations for fiscal 2026 and 2025, respectively. The total cost related to non-vested awards not yet recognized at March 31, 2026 totals $ 106,173 , which is expected to be recognized over a weighted average of 0.82 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 that the value realized by an optionee will be at or near the value estimated by the Binomial model. During the years ended March 31, 2026 and 2025, there were no stock options granted. The plan also provides for the granting of stock awards. No stock awards were granted during fiscal 2026 and 2025. F- 15 No forfeiture rate is assumed for stock options granted to directors or employees due to the Company’s historically low forfeiture experience for these types of awards. During the year ended March 31, 2026, there were no stock options forfeited or expired. During the year ended March 31, 2025, 1,875 unvested stock options and 625 vested stock options were forfeited due to the resignation of an employee. The following table is a summary of activity of stock options for the years ended March 31, 2026 and 2025: 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, 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 $ - Granted - - Exercised - - Forfeited or Expired - - Outstanding at March 31, 2026 150,883 $ 9.52 4.98 $ 105,825 Vested at March 31, 2026 128,133 $ 8.64 4.65 $ 202,065 Exercisable at March 31, 2026 128,133 $ 8.64 4.65 $ 202,065 During the year ended March 31, 2026, no stock options were exercised. 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. Other information pertaining to option activity was as follows during the year ended March 31: Schedule of Other Information Pertaining to Option Activity 2026 2025 Weighted average grant-date fair value of stock options granted (per share) $ - $ - Total fair value of options vested $ - $ 205,241 Total intrinsic value of options exercised $ - $ 92,316 The following table summarizes information about options outstanding at March 31, 2026: 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 4.98 $ - Outstanding options at March 31, 2026 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 consists of shared office expenditures, as well as administrative and operating expenses paid on behalf of the principal stockholder. The total amount billed to and reimbursed by the principal stockholder for the years ended March 31, 2026 and 2025 were $ 49,661 and $ 31,506 , 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 years ending March 31, 2026 and 2025 were $ 10,175 and $ 11,974 , 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 not currently involved in any legal proceedings that it considers probable to result in, or reasonably likely 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 expires on July 31, 2027 . The Company determines that an arrangement is a lease at inception. Operating leases are recorded as operating lease right-of-use asset, operating lease liability, current, and operating lease liability, long-term on the consolidated balance sheets. 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 judgment 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, 2026 Assets Operating lease right-of-use asset, beginning balance $ 126,525 Current period amortization ( 51,003 ) Lease extension - Total operating lease right-of-use asset $ 75,522 Liabilities Operating lease liability, current $ 55,787 Operating lease liability, long term 19,735 Total lease liabilities $ 75,522 Future minimum lease payments as of March 31, 2026 under non-cancellable operating leases are as follows: Schedule of Future Minimum Lease Payments Lease Obligation Fiscal Year Ended March 31, 2027 60,320 Fiscal Year Ended March 31, 2028 20,107 Total lease payments $ 80,427 Less: imputed interest ( 4,905 ) Operating lease liability 75,522 Less: operating lease liability, current ( 55,787 ) Operating lease liability, long term $ 19,735 Net cash paid for our operating lease for the years ended March 31, 2026 and 2025 was $ 50,145 and $ 47,653 , respectively. Operating lease expense, including amortization of the operating lease right of use asset, and rent expense, less sublease income of $ 10,175 , are included in general and administrative expenses on the consolidated statements of operations. F- 17 14. Acquisitions During the year ended March 31, 2026, the Company incurred approximately $ 818,000 in acquisition costs to acquire various royalty interests in approximately 270 producing wells in Colorado, Louisiana, New Mexico, and Texas. These costs also included the purchase of additional royalty interests in 24 properties in which we already hold an interest in Louisiana and Texas, as well as 40 undeveloped net acres in New Mexico. 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 in Colorado, Louisiana, Montana, Nebraska, New Mexico, North and South Dakota, Texas, and Wyoming. 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, 2026 and 2025 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 market prices used for oil and gas reserve preparation, based on SEC guidelines. Schedule of Weighted Average First-day-of-the-month Prices Used for Oil and Gas Reserve March 31, 2026 2025 % Change Prices utilized in the reserve estimates before adjustments: Oil per Bbl $ 59.79 $ 71.00 ( 16 )% Natural gas per MMBtu $ 3.72 $ 2.44 52 % F- 18 The Company’s total estimated proved reserves at March 31, 2026 were approximately 1.437 MMBOE, of which 46 % was oil and 54 % 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, 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 Revision of previous estimates ( 106,000 ) 315,000 Purchase of minerals in place 18,000 124,000 Extensions and discoveries 155,000 557,000 Sales of minerals in place ( 1,000 ) ( 3,000 ) Production ( 82,000 ) ( 682,000 ) As of March 31, 2026 659,000 4,671,000 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. The reduction in proved undeveloped reserves was primarily attributable to properties in Lea County, New Mexico, due to changes in the timing of future development in wells in which we own a working interest. These interests are held by production and remain in place for future development. Summary of Proved Developed and Undeveloped Reserves as of March 31, 2026 and 2025 : Summary of Proved Developed and Undeveloped Reserves Oil (Bbls) Natural Gas (Mcf) Proved Developed Reserves: As of April 1, 2024 444,610 3,566,240 As of March 31, 2025 405,840 3,654,900 As of March 31, 2026 462,780 4,204,610 Proved Undeveloped Reserves: As of April 1, 2024 346,330 970,880 As of March 31, 2025 269,000 704,810 As of March 31, 2026 195,840 466,060 At March 31, 2026, the Company reported estimated PUDs of 274 MBOE, which accounted for 19 % of its total estimated proved oil and gas reserves. This figure primarily consists of a projected 62 new wells (221 MBOE) operated by others. Of these wells, 41 wells are planned to be drilled in fiscal 2027, 17 wells in fiscal 2029, and 4 wells in fiscal 2030. The cost of these projects is expected to 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. F- 19 The following table discloses the Company’s progress toward the conversion of PUDs during fiscal 2026. 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 386,462 $ 4,011,975 Revision of previous estimates ( 106,667 ) ( 1,713,376 ) Sales of reserves - - Conversions to PD reserves ( 66,539 ) ( 119,475 ) Additional PUDs added 60,261 1,179,554 PUDs, end of year 273,517 $ 3,358,678 Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2026 and 2025, 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. Estimated future development costs associated with the Company’s proved undeveloped properties through March 31, 2030 are $ 3,358,678 . 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 contracts that include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant. The SEC reporting rules require that year-end reserve estimates and related future net cash flows be calculated using the unweighted arithmetic average of the first-day-of-the-month market prices for oil and natural gas during the 12-month period and discounted at 10 % per year and assuming continuation of existing economic and operating conditions. The average prices used for fiscal 2026 were $ 62.76 per bbl of oil and $ 2.24 per mcf of natural gas. The average prices used for fiscal 2025 were $ 73.79 per bbl of oil and $ 2.14 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 flows 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, 2026 and 2025 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. F- 20 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 2026 2025 March 31 2026 2025 Future cash inflows $ 51,791,000 $ 59,135,000 Future production costs and taxes ( 15,010,000 ) ( 18,172,000 ) Future development costs ( 3,858,000 ) ( 4,137,000 ) Future income taxes ( 3,843,000 ) ( 4,982,000 ) Future net cash flows 29,080,000 31,844,000 Annual 10% discount for estimated timing of cash flows ( 10,415,000 ) ( 11,769,000 ) Standardized measure of discounted future net cash flows $ 18,665,000 $ 20,075,000 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 2026 2025 March 31 2026 2025 Sales of oil and gas produced, net of production costs $ ( 5,120,000 ) $ ( 5,511,000 ) Net changes in price and production costs ( 1,807,000 ) ( 2,735,000 ) Changes in previously estimated development costs 7,000 ( 1,111,000 ) Revisions of quantity estimates ( 3,438,000 ) ( 5,155,000 ) Net change due to purchases and sales of minerals in place 838,000 1,996,000 Extensions and discoveries, less related costs 4,727,000 1,713,000 Net change in income taxes 675,000 1,309,000 Accretion of discount 2,322,000 2,321,000 Changes in timing of estimated cash flows and other 386,000 2,620,000 Changes in standardized measure ( 1,410,000 ) ( 4,553,000 ) Standardized measure, beginning of year 20,075,000 24,628,000 Standardized measure, end of year $ 18,665,000 $ 20,075,000 16. Employee 401(k) Plan In January 2026, the Company adopted a defined contribution 401(k) retirement savings plan for eligible employees. As of March 31, 2026, the plan had not commenced operations, and no employee salary deferrals or employer matching contributions had been made. Accordingly, no expense related to the plan was recognized during the year ended March 31, 2026. 17. Subsequent Events In April 2026, effective May 1, 2026, the Company acquired royalty interests in 144 producing wells in Weld County, Colorado and Atascosa, Howard, LaSalle, Martin, and Yoakum Counties, Texas, and additional royalty interests in 3 properties in which we already hold an interest in Howard County, Texas, for an aggregate purchase price of $ 1,028,600 . In May 2026, Mexco expended approximately $ 460,000 to participate in the drilling and completion of six horizontal wells in the Wolfcamp A formation of the Delaware Basin in Reeves County, Texas. On June 4, 2026, 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 15, 2026. The dividend in the amount of $204,600 is to be paid on June 30, 2026. In June 2026, effective July 1, 2026, the Company acquired royalty interests in 256 producing wells in Adams and Larimer Counties, Colorado; Caddo and DeSoto Parishes, Louisiana; Karnes, McMullen, Panola, and Winkler Counties, Texas; and Ashtabula County, Ohio for an aggregate purchase of $ 1,066,600 . 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- 21 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. 10.6 Third Amendment to Loan Agreement dated March 28, 2026 to the Loan Agreement between West Texas National Bank and Mexco Energy Corporation filed as Exhibit 10.6 to the Company’s Annual Report on Form 10-K dated June 26, 2026, 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 Interactive Data File (embedded within the Inline XBRL and contained in Exhibit 101) F- 22