{"url_path":"/sec/mxc/10-k/2026/item-16","section_key":"item-16","section_title":"Item 16 ****FORM","topic":"sec","document":{"doc_type":"10-K","doc_date":"2026-06-29","source_url":"https://www.sec.gov/Archives/edgar/data/66418/0001493152-26-030386-index.html","accession_number":"0001493152-26-030386","cik":"0000066418","ticker":"MXC","issuer_name":"MEXCO ENERGY CORP","edgar_url":"https://www.sec.gov/Archives/edgar/data/66418/0001493152-26-030386-index.html","primary_entity_key":"0000066418","primary_entity_name":"MEXCO ENERGY CORP"},"word_count":11613,"has_tables":true,"body_markdown":"**ITEM\n16.****FORM\n10-K SUMMARY**\n\n \n\nNone\n\n \n\n31\n\n \n\n \n\n**SIGNATURES**\n\n** **\n\nPursuant\nto 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\non its behalf by the undersigned, thereunto duly authorized.\n\n \n\nMEXCO\nENERGY CORPORATION\n\n \n\nBy:\n/s/ Nicholas C. Taylor\n \nBy:\n/s/ Tamala L. McComic\n\n \nChairman of the Board and Chief Executive Officer\n \n \nPresident and Chief Financial Officer\n\n \n \n \n \n \n\nDated: June 29, 2026\n \n \n \n\n \n\nPursuant\nto the requirements of the Securities Exchange Act of 1934, this report has been signed below as of June 29, 2026, by the following persons\non behalf of the Registrant and in the capacity indicated.\n\n \n\n*/s/ Nicholas C.\nTaylor*\n \n\nNicholas C. Taylor\n \n\nChief Executive Officer, Chairman of the Board of Directors\n \n\n \n \n\n*/s/ Tamala\nL. McComic*\n \n\nTamala L. McComic\n \n\nChief Financial Officer, President, Treasurer and Assistant\nSecretary\n \n\n \n \n\n*/s/ Michael J. Banschbach*\n \n\nMichael J. Banschbach\n \n\nDirector\n \n\n \n \n\n*/s/ Kenneth L. Clayton*\n \n\nKenneth L. Clayton\n \n\nDirector\n \n\n \n \n\n*/s/ Thomas R. Craddick*\n \n\nThomas R. Craddick\n \n\nDirector\n \n\n \n \n\n*/s/ Thomas H. Decker*\n \n\nThomas H. Decker\n \n\nDirector\n \n\n \n \n\n*/s/ Christopher\nM. Schroeder*\n \n\nChristopher M. Schroeder\n \n\nDirector\n \n\n \n\n32\n\n \n\n \n\nGlossary\nof Abbreviations and Terms\n\n \n\nThe\nfollowing are abbreviations and definitions of terms commonly used in the oil and gas industry and this report.\n\n \n\n*Basin.*A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.\n\n* *\n\n*Bbl*.\nOne stock tank barrel, or 42 U.S. gallons of liquid volume, used herein in reference to crude oil, condensate, or natural gas liquids.\n\n \n\n*BOE.*Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.\n\n \n\n*BTU.*British thermal unit.\n\n \n\n*Completion*.\nThe installation of permanent equipment for the production of oil or natural gas.\n\n \n\n*Condensate.*\nLiquid hydrocarbons associated with the production of a primarily natural gas reserve.\n\n \n\n*Credit\nFacility.* A line of credit provided by a bank or group of banks, secured by oil and gas properties.\n\n \n\n*DD&A.*\nRefers to depreciation, depletion and amortization of the Company’s property and equipment.\n\n \n\n*Developed\nacreage*. The number of acres which are allocated or assignable to producing wells or wells capable of production.\n\n \n\n*Development\ncosts.*Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by\nproved reserve additions and revisions to proved reserves.\n\n \n\n*Development\nwell*. A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.\n\n \n\n*Dry\nhole*. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production\nexceed production expenses and taxes.\n\n \n\n*Exploration.*The search for natural accumulations of oil and natural gas by any geological, geophysical or other suitable means.\n\n \n\n*Exploratory\nwell*. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field\npreviously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.\n\n \n\n*Extensions\nand discoveries*. As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties\nor revisions of previous estimates.\n\n \n\n*Field.*An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological\nstructural feature and/or stratigraphic condition.\n\n \n\n*Formation.*A layer of rock that has distinct characteristics differing from nearby rock.\n\n \n\n*Gross\nacres 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.\n\n \n\n*Lease.*\nAn instrument which grants to another (the lessee) the exclusive right to enter and explore for, drill for, produce, store and remove\noil and natural gas from the mineral interest, in consideration for which the lessor is entitled to certain rents and royalties payable\nunder the terms of the lease. Typically, the duration of the lessee’s authorization is for a stated term of years and “for\nso long thereafter” as minerals are producing.\n\n \n\n*Mcf*.\nOne thousand cubic feet of natural gas.\n\n \n\n33\n\n \n\n \n\n*MBOE*.\nOne thousand barrels of oil equivalent.\n\n \n\n*MMBOE*.\nOne million barrels of oil equivalent.\n\n \n\n*MMBtu*.\nOne million British thermal units of energy commonly used to measure heat value or energy content of natural gas.\n\n \n\n*Natural\ngas liquids (“NGLs”)*. Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane\nand natural gasoline.\n\n \n\n*Net\nacres or wells.*Refers to gross acres or wells multiplied, in each case, by the percentage interest owned by the Company.\n\n \n\n*Net\nproduction*. Oil and gas production that is owned by the Company, less royalties and production due others.\n\n \n\n*Net\nrevenue interest.*An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding\ninterests.\n\n \n\n*Oil*.\nCrude oil or condensate.\n\n \n\n*Operator*.\nThe individual or company responsible for the exploration, development and production of an oil or natural gas well or lease.\n\n \n\n*Overriding\nroyalty interest (“ORRI”).*A royalty interest that is created out of the operating or working interest. Its term is coextensive\nwith that of the operating interest from which it was created.\n\n \n\n*Plugging\nand abandonment.*Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will\nnot escape into another or to the surface. Regulations of all states require plugging of abandoned wells.\n\n* *\n\n*Productive\nwell.*A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the\nproduction exceed operating and production expenses and taxes.\n\n \n\n*Prospect.*A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis\nusing reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.\n\n \n\n*Proved\ndeveloped nonproducing reserves (“PDNP”)*. Reserves that consist of (i) proved reserves from wells which have been completed\nand tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved\nreserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics\nand analogous production in the immediate vicinity of the wells.\n\n \n\n*Proved\ndeveloped producing reserves (“PDP”).* Proved reserves that can be expected to be recovered from currently producing zones\nunder the continuation of present operating methods.\n\n \n\n*Proved\ndeveloped reserves.* The combination of proved developed producing and proved developed nonproducing reserves.\n\n \n\n*Proved\nreserves.*The estimated quantities of oil, natural gas, and natural gas liquids which can be estimated\nwith reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating\nconditions.\n\n \n\n*Proved\nundeveloped reserves (“PUD”)*. Proved reserves that are expected to be recovered from new wells on undrilled acreage or\nfrom existing wells where a relatively major expenditure is required for recompletion.\n\n \n\n34\n\n \n\n \n\n*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\nof proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the\ndetermination date, before income taxes, and without giving effect to non-property-related expenses except for specific general and administrative\nexpenses incurred to operate the properties, discounted to a present value using an annual discount rate of 10%.\n\n \n\n*Recompletion.*A process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt\nto establish or increase existing production.\n\n \n\n*Reservoir.*A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined\nby impermeable rock or water barriers and is separate from other reservoirs.\n\n \n\n*Royalty*.\nAn 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\nthe leased acreage, or of the proceeds of the sale thereof, but generally does not require the owner to pay any portion of the costs\nof drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by\nthe owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of\nthe leasehold in connection with a transfer to a subsequent owner.\n\n \n\n*Standardized\nmeasure of discounted future net cash flows*. The discounted future net cash flows relating to proved reserves based on prices used\nin estimating the reserves, year-end costs, and statutory tax rates, and a 10% annual discount rate. The information for this calculation\nis included in the note regarding disclosures about oil and gas reserve data contained in the Notes to Consolidated Financial Statements\nincluded in this Form 10-K.\n\n \n\n*Undeveloped\nacreage*. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial\nquantities of oil and natural gas regardless of whether such acreage contains proved reserves.\n\n \n\n*Unit.*The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development\nand operation without regard to separate property interests. Also, the area covered by a unitization agreement.\n\n \n\n*Wellbore.*The\nhole drilled by the bit that is equipped for crude oil or natural gas production on a completed well. Also called a well or\nborehole.\n\n \n\n*Working\ninterest*. 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\ngas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production\nto which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to\nthe extent of any royalty burden.\n\n \n\n35\n\n \n\n** **\n\n**INDEX\nTO CONSOLIDATED FINANCIAL STATEMENTS**\n\n \n\n[Report\nof Independent Registered Public Accounting Firm (PCAOB ID Number 410)](#a_001)\nF-2\n\n[Consolidated Balance Sheets](#a_002)\nF-4\n\n[Consolidated Statements of Operations](#a_003)\nF-5\n\n[Consolidated Statements of Changes in Stockholders’ Equity](#a_004)\nF-6\n\n[Consolidated Statements of Cash Flows](#a_005)\nF-7\n\n[Notes to Consolidated Financial Statements](#a_006)\nF-8\n\n \n\nF-1\n\n \n\n \n\n**Report\nof Independent Registered Public Accounting Firm**\n\n** **\n\nTo the Board\nof Directors and Shareholders of Mexco Energy Corporation\n\n \n\n**Opinion\non the Financial Statements**\n\n* *\n\nWe\nhave audited the accompanying consolidated balance sheets of Mexco Energy Corporation (a Colorado corporation) and subsidiaries (the\n“Company”) as of March 31, 2026 and 2025, and the related consolidated statements of operations, changes in\nstockholders’ equity, and cash flows for each of the two years in the period ended March 31, 2026, and the related notes\n(collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in\nall material respects, the financial position of the Company as of March 31, 2026 and 2025, and the results of its operations and\nits cash flows for each of the two years in the period ended March 31, 2026, in conformity with accounting principles generally\naccepted in the United States of America.\n\n \n\n**Basis\nfor Opinion**\n\n** **\n\nThese\nfinancial statements are the responsibility of the entity’s management. Our responsibility is to express an opinion on these financial\nstatements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United\nStates) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities\nlaws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.\n\n \n\nWe\nconducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain\nreasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company\nis not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits,\nwe are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion\non the effectiveness of the entity’s internal control over financial reporting. Accordingly, we express no such opinion.\n\n \n\nOur\naudits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error\nor fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding\nthe amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant\nestimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits\nprovide a reasonable basis for our opinion.\n\n \n\n**Critical Audit Matters**\n\n* *\n\nThe\ncritical audit matter communicated below is a matter arising from the current period audit of the financial statements that were\ncommunicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material\nto the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a\ncritical audit matter does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by\ncommunicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or\ndisclosures to which it relates.\n\n \n\nEstimation\nof proved reserves impacting the recognition and valuation of depletion expense and impairment of oil and gas properties.\n\n* *\n\nF-2\n\n \n\n* *\n\n**Critical\nAudit Matter Description**\n\n** **\n\nAs\ndescribed in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting\nwhich requires management to make estimates of proved reserve volumes and future revenues and expenses to calculate depletion expense.\nTo estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting\nthe production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s\ndevelopment plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s\njudgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected,\nwith reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion expense.\nWe identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense and impairment evaluation,\nas a critical audit matter.\n\n \n\nThe\nprincipal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain\ninputs and assumptions, which require a high degree of subjectivity necessary to estimate the volume and future revenues of the Company’s\nproved reserves could have a significant impact on the measurement of depletion expense or the impairment assessment. In turn, auditing\nthose inputs and assumptions required subjective and complex auditor judgment.\n\n \n\n**How\nthe Critical Audit Matter Was Addressed in the Audit**\n\n** **\n\nWe\nobtained an understanding of the design and implementation of management’s controls, and our audit procedures related to the estimation\nof proved reserves included the following, among others.\n\n \n\n●We\nevaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering\nspecialists and their relationship to the Company, made inquiries of those reservoir engineers\nregarding the process followed and judgments made to estimate the Company’s proved\nreserve volumes, and read the reserve report prepared by the Company’s specialists.\n\n   \n\n●To\nthe extent key, sensitive inputs and assumptions used to determine proved reserve volumes\nand other cash flow inputs and assumptions are derived from the Company’s accounting\nrecords, such as commodity pricing, historical pricing differentials, operating costs, estimated\ncapital costs and working and net revenue interests, we tested management’s process\nfor determining the assumptions, including examining the underlying support, on a sample\nbasis. Specifically, our audit procedures involved testing management’s assumptions\nas follows:\n\n \n\n○Compared\nthe estimated pricing differentials used in the reserve report to realized prices related\nto revenue transactions recorded in the current year;\n\n   \n\n○Evaluated\nthe models used to estimate the operating costs at year-end compared to historical operating\ncosts;\n\n   \n\n○Compared\nthe models used to determine the future capital expenditures and compared estimated future\ncapital expenditures used in the reserve report to amounts expended for recently drilled\nand completed wells;\n\n   \n\n○Evaluated\nthe working and net revenue interests used in the reserve report by inspecting a sample of\nownership interests, historical pricing differentials, and operating costs to underlying\nsupport from the Company’s accounting records.\n\n   \n\n○Evaluated\nthe Company’s evidence supporting the amount of proved undeveloped properties reflected\nin the reserve report by examining historical conversion rates and support for the Company’s\nor the operator’s intent to develop the proved undeveloped properties;\n\n   \n\n○Applied\nanalytical procedures to the reserve report by comparing to historical actual results and\nto the prior year reserve report.\n\n \n\n/s/\nWEAVER AND TIDWELL, L.L.P.\n\n \n\nWe\nhave served as the Company’s auditor since 2017.\n\n \n\nDenver, Colorado\n\nJune\n29, 2026\n\n \n\nF-3\n\n \n\n \n\n**Mexco\nEnergy Corporation and Subsidiaries**\n\nCONSOLIDATED BALANCE SHEETS\n\n \n\n  \nMarch 31,  \nMarch 31, \n\n  \n2026  \n2025 \n\nASSETS \n    \n   \n\nCurrent assets \n    \n   \n\nCash and cash equivalents \n$2,775,976  \n$1,753,955 \n\nAccounts receivable: \n    \n   \n\nOil and natural gas sales \n 1,287,841  \n 1,113,588 \n\nTrade \n 111,494  \n 67,951 \n\nPrepaid drilling \n 204,218  \n 24,381 \n\nPrepaid costs and expenses \n 68,846  \n 60,981 \n\nTotal current assets \n 4,448,375  \n 3,020,856 \n\nProperty and equipment, at cost \n    \n   \n\nOil and gas properties, using the full cost method \n 53,664,668  \n 51,611,782 \n\nOther \n 125,501  \n 121,926 \n\nAccumulated depreciation, depletion and amortization \n (39,161,357) \n (36,637,530)\n\nProperty and equipment, net \n 14,628,812  \n 15,096,178 \n\nInvestment – cost basis \n 2,527,429  \n 2,100,000 \n\nOperating lease right-of-use asset \n 75,522  \n 126,525 \n\nOther noncurrent assets \n 12,325  \n 4,298 \n\nTotal assets \n$21,692,463  \n$20,347,857 \n\n  \n    \n   \n\nLIABILITIES AND STOCKHOLDERS’ EQUITY \n    \n   \n\nCurrent liabilities \n    \n   \n\nAccounts payable and accrued expenses \n$379,929  \n$307,387 \n\nIncome tax payable \n 17,203  \n 192,802 \n\nOperating lease liability, current \n 55,787  \n 51,003 \n\nTotal current liabilities \n 452,919  \n 551,192 \n\nLong-term liabilities \n    \n   \n\nOperating lease liability, long-term \n 19,735  \n 75,522 \n\nDeferred income tax liability \n 533,673  \n 320,604 \n\nAsset retirement obligations \n 699,317  \n 688,842 \n\nTotal long-term liabilities \n 1,252,725  \n 1,084,968 \n\nTotal liabilities \n 1,705,644  \n 1,636,160 \n\n  \n    \n   \n\nCommitments and contingencies \n -  \n - \n\n  \n    \n   \n\nStockholders’ equity \n    \n   \n\nPreferred stock - $1.00 par value;\n\n10,000,000 shares authorized; none outstanding\n \n -  \n - \n\nCommon stock - $0.50 par value;\n\n40,000,000 shares authorized; 2,239,283 shares issued and 2,046,000 shares outstanding as of March 31, 2026 and 2025\n \n 1,119,641  \n 1,119,641 \n\nAdditional paid-in capital \n 9,018,953  \n 8,844,953 \n\nRetained earnings \n 11,726,971  \n 10,625,849 \n\nTreasury stock, at cost (193,283 shares) \n (1,878,746) \n (1,878,746)\n\nTotal stockholders’ equity \n 19,986,819  \n 18,711,697 \n\nTotal liabilities and stockholders’ equity \n$21,692,463  \n$20,347,857 \n\n \n\nThe\naccompanying notes to the consolidated financial statements are an integral part of these statements.\n\n \n\nF-4\n\n \n\n** **\n\n**Mexco Energy Corporation and Subsidiaries**\n\nCONSOLIDATED STATEMENTS OF OPERATIONS\n\nYears ended March 31,\n\n \n\n  \n2026  \n2025 \n\nOperating revenues: \n    \n   \n\nOil sales \n$5,276,981  \n$6,145,674 \n\nNatural gas sales \n 1,271,067  \n 970,811 \n\nOther \n 13,276  \n 23,954 \n\nTotal operating revenues \n 6,561,324  \n 7,140,439 \n\n  \n    \n   \n\nOperating expenses: \n    \n   \n\nProduction \n 1,428,353  \n 1,605,096 \n\nAccretion of asset retirement obligation \n 32,168  \n 29,983 \n\nDepreciation, depletion and amortization \n 2,523,827  \n 2,452,694 \n\nGeneral and administrative \n 1,306,275  \n 1,320,074 \n\nTotal operating expenses \n 5,290,623  \n 5,407,847 \n\n  \n    \n   \n\nOperating income \n 1,270,701  \n 1,732,592 \n\n  \n    \n   \n\nOther income (expenses): \n    \n   \n\nIncome from investments in LLCs \n 329,102 \n 217,627 \n\nInterest income \n 89,341  \n 72,629 \n\nInterest expense \n (4,379) \n (6,150)\n\nNet other income \n 414,064  \n 284,106 \n\n  \n    \n   \n\nIncome before provision for income taxes \n 1,684,765  \n 2,016,698 \n\n  \n    \n   \n\nProvision for income taxes \n 379,043  \n 304,330 \n\n  \n    \n   \n\nNet income \n$1,305,722  \n$1,712,368 \n\n  \n    \n   \n\nIncome per common share: \n    \n   \n\nBasic: \n$0.64  \n$0.83 \n\nDiluted: \n$0.63  \n$0.81 \n\n  \n    \n   \n\nWeighted average common shares outstanding: \n    \n   \n\nBasic: \n 2,046,000  \n 2,064,147 \n\nDiluted: \n 2,080,503  \n 2,107,775 \n\n  \n    \n   \n\nDividends declared per share \n$0.10  \n$0.10 \n\n \n\nThe\naccompanying notes to the consolidated financial statements are an integral part of these statements.\n\n \n\nF-5\n\n \n\n \n\n**Mexco\nEnergy Corporation and Subsidiaries**\n\nCONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY\n\nYears ended March 31, 2026 and 2025\n\n \n\n  \n\nCommon\n\nStock Par\n\nValue\n  \n\nAdditional\n\nPaid-In\n\nCapital\n  \n\nRetained\n\nEarnings\n  \n\nTreasury\n\nStock\n  \n\nTotal\n\nStockholders’\n\nEquity\n \n\nBalance at April 1, 2024 \n$1,113,458  \n$8,567,856  \n$9,122,481  \n$(1,175,530) \n$17,628,265 \n\nNet income \n -  \n -  \n 1,712,368  \n -  \n 1,712,368 \n\nIssuance of stock through options exercised \n 6,183  \n 71,458  \n -  \n -  \n 77,641 \n\nDividends paid \n    \n    \n (209,000) \n    \n (209,000)\n\nPurchase of stock \n    \n    \n    \n (703,216) \n (703,216)\n\nStock based compensation \n -  \n 205,639  \n -  \n -  \n 205,639 \n\nBalance at March 31, 2025 \n$1,119,641  \n$8,844,953  \n$10,625,849  \n$(1,878,746) \n$18,711,697 \n\nNet income \n -  \n -  \n 1,305,722  \n -  \n 1,305,722 \n\nDividends paid \n -  \n -  \n (204,600) \n -  \n (204,600)\n\nStock based compensation \n -  \n 174,000  \n -  \n -  \n 174,000 \n\nBalance at March 31, 2026 \n$1,119,641  \n$9,018,953  \n$11,726,971  \n$(1,878,746) \n$19,986,819 \n\n \n\nSHARE ACTIVITY \n   \n  \n\n  \n2026  \n2025 \n\nCommon stock shares, issued: \n    \n   \n\nAt beginning of year \n 2,239,283  \n 2,226,916 \n\nIssued \n -  \n 12,367 \n\nAt end of year \n 2,239,283  \n 2,239,283 \n\n  \n    \n   \n\nCommon stock shares, held in treasury: \n    \n   \n\nAt beginning of year \n (193,283) \n (135,517)\n\nAcquisitions \n -  \n (57,766)\n\nAt end of year \n (193,283) \n (193,283)\n\n  \n    \n   \n\nCommon stock shares, outstanding \n    \n   \n\nAt end of year \n 2,046,000  \n 2,046,000 \n\n \n\nThe\naccompanying notes to the consolidated financial statements are an integral part of these statements.\n\n \n\nF-6\n\n \n\n \n\n**Mexco Energy Corporation and Subsidiaries**\n\nCONSOLIDATED STATEMENTS OF CASH FLOWS\n\nYears ended March 31,\n\n \n\n  \n2026  \n2025 \n\nCash flows from operating activities: \n    \n   \n\nNet income \n$1,305,722  \n$1,712,368 \n\nAdjustments to reconcile net income to net cash provided by operating\nactivities: \n    \n   \n\nDeferred income tax expense \n 213,069  \n 8,943 \n\nStock-based compensation \n 174,000  \n 205,639 \n\nDepreciation, depletion and amortization \n 2,523,827  \n 2,452,694 \n\nAccretion of asset retirement obligations \n 32,168  \n 29,983 \n\nAmortization of debt issuance costs \n 4,343  \n 4,299 \n\nChanges in operating assets and liabilities: \n    \n   \n\nIncrease in accounts receivable \n (217,796) \n (170,644)\n\nDecrease (increase) in right-of-use asset \n 51,003  \n (107,262)\n\nIncrease in prepaid expenses \n (7,866) \n (4,788)\n\n(Decrease) increase in accounts payable and accrued expenses \n (33,087) \n 69,059 \n\n(Decrease) increase in operating lease liability \n (51,003) \n 107,262 \n\n(Decrease) increase in income tax payable \n (175,599) \n 3,548 \n\nSettlement of asset retirement obligations \n (39,629) \n (41,480)\n\nNet cash provided by operating activities \n 3,779,152  \n 4,269,621 \n\n  \n    \n   \n\nCash flows from investing activities: \n    \n   \n\nAdditions to oil and gas properties \n (2,189,426) \n (3,416,616)\n\nAdditions to other property and equipment \n (3,575) \n - \n\nDrilling refund \n 54,368  \n 59,471 \n\nInvestment in limited liability companies at cost \n (427,429) \n (1,000,000)\n\nProceeds from sale of oil and gas properties and equipment \n 25,901  \n 202,570 \n\nNet cash used in investing activities \n (2,540,161) \n (4,154,575)\n\n  \n    \n   \n\nCash flows from financing activities: \n    \n   \n\nProceeds from exercise of stock options \n -  \n 77,641 \n\nProceeds from long-term debt \n -  \n 650,000 \n\nDebt issuance costs \n (12,370) \n - \n\nDividends paid \n (204,600) \n (209,000)\n\nAcquisition of treasury stock \n -  \n (703,216)\n\nReduction of long-term debt \n -  \n (650,000)\n\nNet cash used in financing activities \n (216,970) \n (834,575)\n\n  \n    \n   \n\nNet increase (decrease) in cash and cash equivalents \n 1,022,021  \n (719,529)\n\n  \n    \n   \n\nCash and cash equivalents at beginning of year \n 1,753,955  \n 2,473,484 \n\n  \n    \n   \n\nCash and cash equivalents at end of year \n$2,775,976  \n$1,753,955 \n\n  \n    \n   \n\nSupplemental disclosure of cash flow information: \n    \n   \n\nCash paid for interest \n$36  \n$1,852 \n\nCash paid for income taxes \n$362,802  \n$228,487 \n\nAccrued capital expenditures included in accounts payable \n$144,047  \n$38,417 \n\n  \n    \n   \n\nNon-cash investing and financing activities: \n    \n   \n\nAsset retirement obligations \n$9,592  \n$5,231 \n\n** **\n\nThe\naccompanying notes to the consolidated financial statements are an integral part of these statements.\n\n \n\nF-7\n\n \n\n \n\n**MEXCO\nENERGY CORPORATION AND SUBSIDIARIES**\n\n**NOTES\nTO CONSOLIDATED FINANCIAL STATEMENTS**\n\n**Years\nEnded March 31, 2026 and 2025**\n\n** **\n\n1.\nNature of Operations\n\n \n\nMexco\nEnergy Corporation (a Colorado corporation) and its wholly owned subsidiaries, Forman Energy Corporation (a New York corporation), Southwest\nTexas Disposal Corporation (a Texas corporation) and TBO Oil & Gas, LLC (a Texas limited liability company) (collectively, the “Company”)\nare engaged in the acquisition, exploration, development and production of crude oil, natural gas, condensate and natural gas liquids\n(“NGLs”). Most of the Company’s oil and gas interests are centered in West Texas and Southeastern New Mexico; however,\nthe Company owns producing properties and undeveloped acreage in fourteen states. All of the Company’s oil and gas interests are\noperated by others.\n\n \n\n2.\nSummary of Significant Accounting Policies\n\n \n\n**Principles\nof Consolidation**. The consolidated financial statements include the accounts of Mexco Energy Corporation and its wholly owned subsidiaries.\nAll significant intercompany balances and transactions associated with the consolidated operations have been eliminated.\n\n \n\n**Estimates\nand Assumptions**. In preparing financial statements in conformity with accounting principles generally accepted in the United States\nof America (“GAAP”), management is required to make informed judgments, estimates and assumptions that affect the reported\namounts of assets and liabilities as of the date of the consolidated financial statements and affect the reported amounts of revenues\nand expenses during the reporting period. In addition, significant estimates are used in determining proved oil and gas reserves. Although\nmanagement believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates. The estimate\nof the Company’s oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment of\noil and gas properties, is the most significant of the estimates and assumptions that affect these reported results.\n\n \n\n**Cash\nand Cash Equivalents**. The Company considers all highly liquid debt instruments purchased with maturities of three months or less\nand money market funds to be cash equivalents. The Company maintains cash in bank deposit accounts that may, at times, exceed federally\ninsured limits. At March 31, 2026, the Company had on deposit all of its cash and cash equivalents with three financial institutions.\nThe Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk.\n\n \n\n**Accounts\nReceivable.** Accounts receivable include trade receivables from joint interest owners and oil and gas purchasers. The\nopening balance of accounts receivable from contracts with customers as of April 1, 2024, was $1,001,709. Credit is extended based\non an evaluation of a customer’s financial condition and is generally uncollateralized. The collectibility of receivables is\nassessed, and an allowance is made for any credit losses. The allowance for credit losses is determined based on a number of\nfactors, including the length of time accounts receivable are past due, the Company’s previous loss history, the\ndebtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a\nwhole. The Company has not experienced any significant credit losses. For the years ended March 31, 2026 and 2025, no\nallowance has been made for any credit losses.\n\n \n\n**Oil\nand Gas Properties**. The Company accounts for its oil and natural gas properties using the full cost method of accounting. Under this\nmethod, all costs incurred in the acquisition, exploration, and development of oil and natural gas properties are capitalized and amortized\nusing the unit-of-production method based on proved reserves. Costs directly related to exploration and development activities are capitalized,\nwhile production costs, general corporate overhead, and similar activities are expensed as incurred.\n\n \n\nThe\ncarrying value of oil and natural gas properties includes asset retirement costs associated with the fair value of asset retirement obligations\n(“ARO”) when incurred.\n\n \n\nSales\nor other dispositions of oil and natural gas properties, whether or not currently being amortized, are generally accounted for as adjustments\nto capitalized costs, with no gain or loss recognized unless the disposition significantly alters the relationship between capitalized\ncosts and proved reserves. This treatment includes transactions involving Term Assignments and Assignments, Bills of Sale and Conveyances.\n\n \n\nDepletion\nof evaluated oil and natural gas properties is calculated using the unit-of-production method, whereby capitalized costs plus estimated\nfuture development costs are amortized over total proved reserves.\n\n \n\nF-8\n\n \n\n \n\n**Excluded\nCosts**. Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments\nin unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined\nthat the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of\nany impairment is transferred to the capitalized costs being amortized (the depreciation, depletion and amortization (“DD&A”)\npool). Impairments transferred to the DD&A pool increase the DD&A rate. No costs were excluded for the years ended March 31,\n2026 and 2025.\n\n \n\n**Ceiling\nTest**. Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is\nan impairment test to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is the after-tax\npresent value of the future net cash flows from proved crude oil and natural gas reserves, and using an unweighted arithmetic\naverage of the first-day-of-the-month prices for the preceding 12-month period, held constant for the life of production, plus the lower\nof cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the\nceiling limit, the Company must charge the amount of the excess to earnings as an expense reflected in additional accumulated\nDD&A. This is called a “ceiling limitation write-down.” This impairment of our oil and gas properties does not\naffect 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.\n\n \n\n**Depreciation,\nDepletion and Amortization**. The depreciable base for oil and gas properties includes the sum of capitalized costs, net of accumulated\nDD&A, estimated future development costs, and asset retirement costs not accrued in oil and gas properties, less costs excluded from\namortization and salvage. The depreciable base of oil and gas properties is amortized using the unit-of-production method.\n\n \n\n**Asset\nRetirement Obligations**. The Company accrues the estimated costs of plugging, restoration, and removal of facilities by recognizing\nthe fair value of a liability for an asset retirement obligation (“ARO”) in the period in which the obligation is incurred,\ntypically at the inception of a well’s life, with a corresponding increase in the carrying amount of the related long-lived asset.\nThe initial fair value is determined using the present value of estimated future cash flows, which incorporates management assumptions\nregarding ultimate plugging and abandonment costs, inflation factors, credit-adjusted risk-free discount rates, and the timing of settlement.\nCapitalized asset retirement costs are subsequently allocated to expense over the useful life of the related assets utilizing the units-of-production\nmethod, while the discounted ARO liability is accreted over time to its expected settlement value, with such changes reflected as accretion\nexpense within the Consolidated Statements of Operations. Management continuously evaluates its estimates against changes in the legal,\nregulatory, environmental, and political environments; any subsequent revisions to the timing or amount of undiscounted estimated cash\nflows result in a corresponding adjustment to both the ARO liability and the carrying value of the related asset. Settlement of the liability\nis accounted for as an adjustment to the Company’s full cost pool with no gain or loss recognized, and for all periods presented,\nestimated future costs of abandonment and dismantlement are included in the full cost amortization base pursuant to SEC Regulation S-X\nRule 4-10 and amortized as a component of depletion, depreciation, and amortization expense.\n\n \n\n**Income\nTaxes**. The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the\ncarrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted\ntax rates applicable to the years in which those differences are expected to be settled. The effect on deferred tax assets and liabilities\nof a change in tax rates is recognized in net income in the period that includes the enactment date. Any interest and penalties are recorded\nas interest expense and general and administrative expense, respectively.\n\n \n\n**Other\nProperty and Equipment**. Provisions for depreciation\nof office furniture and equipment are computed on the straight-line method based on estimated useful lives of three3\nto ten\nyears.\n\n \n\nF-9\n\n \n\n \n\n**Income\nPer Common Share**. Basic net income per share is computed by dividing net income by the weighted average number of common shares outstanding\nduring the period. Diluted net income per share assumes the exercise of all stock options having exercise prices less than the average\nmarket price of the common stock during the period using the treasury stock method and is computed by dividing net income by the weighted\naverage number of common shares and dilutive potential common shares (stock options) outstanding during the period. In periods where\nlosses are reported, the weighted-average number of common shares outstanding excludes potential common shares, because their inclusion\nwould be anti-dilutive.\n\n \n\n**Revenue\nRecognition.**Revenues from our royalty and non-operated working interest properties are recorded in accordance with ASC 606, Revenue from Contracts\nwith Customers. Revenue is reported net of post-production costs when such costs are contractually deducted by the operator prior to distribution.\nSince revenue checks are generally received two to three months after the production month, the Company accrues revenue earned but not\nyet received by estimating production volumes and product prices. Any identified differences between its revenue estimates and actual\nrevenue received historically have not been significant.\n\n \n\n**Stock-based\nCompensation**. The Company uses the Binomial option pricing model to estimate the grant-date fair value of stock-based awards. Compensation\nexpense is recognized within general and administrative expense in the Consolidated Statements of Operations using the graded-vesting\nmethod over the applicable vesting period.\n\n \n\n**Reclassifications.**Certain amounts in prior periods’ consolidated financial statements have been reclassified to conform with the current period’s\npresentation. These reclassifications had no effect on previously reported results of operations, retained earnings, or net cash flows.\n\n \n\n**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.\n\n \n\n**Segments.**\nThe Company’s chief operating decision maker (“CODM”), comprised of the Chairman of the Board and the President, evaluates\noperating results and allocates capital resources on a consolidated basis. Accordingly, the Company has one reportable segment: crude oil and natural gas development,\nexploration, and production.\n\n \n\n**Liquidity\nand Capital Resources.**Historically, we have funded our operations, acquisitions, exploration, and development expenditures from\ncash generated by operating activities, bank borrowings, sales of non-core properties, and issuance of common stock. Our long-term strategy\nis to increase profit margins while concentrating on obtaining reserves with low-cost operations by acquiring and developing oil and\ngas properties with potential for long-lived production. We focus our efforts on the acquisition of royalties and non-operated working\ninterests in areas with significant development potential.\n\n \n\n**New\nAccounting Pronouncements Not Yet Adopted.**In November 2024, the FASB issued ASU 2024-03, Topic 220 Income Statement – Reporting\nComprehensive Income – Expense Disaggregation Disclosures: Disaggregation of the Income Statement Expenses. The amendments in this\nupdate require disclosure in the Company’s annual and interim consolidated financial statements of specified information about\ncertain costs and expenses, including depletion, depreciation and amortization recognized as part of crude oil and natural gas producing\nactivities, and employee compensation. This ASU is effective for fiscal years beginning after December 15, 2026, and interim reporting\nperiods beginning after December 15, 2027. While the adoption of this ASU will modify the Company’s disclosures, it will not have\nan impact on the Company’s financial position, results of operations, or liquidity.\n\n \n\nF-10\n\n \n\n \n\n3.\nLong-Term Debt\n\n \n\nOn\nDecember 28, 2018, the Company entered into a loan agreement (the “Agreement”) with West Texas National Bank (“WTNB”),\nwhich originally provided for a $1,000,000 credit facility with a maturity date of December 28, 2021. The Agreement has no monthly commitment\nreduction and a borrowing base to be evaluated annually. On February 28, 2020, the Agreement was amended to increase the credit facility\nto $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\nwas amended to extend the maturity date to March 28, 2026. On September 17, 2025, WTNB reaffirmed the borrowing base at $1,500,000. On\nMarch 28, 2026, the Agreement was amended to extend the maturity date to March 28, 2029.\n\n \n\nUnder\nthe Agreement, interest on the facility accrues at a rate equal to the prime rate as quoted in the Wall Street Journal plus one-half\nof one percent (.5%), floating daily. Interest on the outstanding amount under the Agreement is payable monthly. In addition, the Company\nwill pay an unused commitment fee in an amount equal to one-half of one percent (.5%) times the daily average of the unadvanced amount\nof the commitment. The unused commitment fee is payable quarterly in arrears on the last day of each calendar quarter. As of March 31,\n2026, the Company had $1,500,000 available to borrow under the facility.\n\n \n\nNo\nprincipal payments are anticipated to be required through the maturity date of the credit facility, March 28, 2029. Upon closing the\nthird amendment to the Agreement, the Company paid a loan origination fee of $9,000 plus legal expenses totaling $12,200, which are amortized\nover the life of the credit facility.\n\n \n\nAmounts\nborrowed under the Agreement are collateralized by the common stock of the Company’s wholly owned subsidiaries and substantially\nall of the Company’s oil and gas properties.\n\n \n\nThe\nAgreement contains customary covenants for credit facilities of this type, including limitations on changes in control, disposition\nof assets, mergers, and reorganizations. The Company is also obligated to meet certain financial covenants under the Agreement\nincluding requirements that senior debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”)\nratios (Senior Debt/EBITDA) is less than or equal to 4.00 to 1.00 measured with respect to the four trailing quarters and minimum\ninterest coverage ratios (EBITDA/Interest Expense) of 2.00 to 1.00 for each quarter. Commencing with the fiscal quarter ending June\n30, 2026, the amended Agreement requires the Company to maintain Senior Debt to EBITDA ratios less than or equal to 3.00 to 1.00\nmeasured with respect to the four trailing quarters.\n\n \n\nIn\naddition, the Agreement prohibits the Company from paying cash dividends on its common stock without prior written permission of WTNB.\nThe Company obtained written permission from WTNB prior to declaring the regular annual dividend in 2025 and special dividend in 2024,\nas discussed in Note 9. The Agreement does not permit the Company to enter into hedge agreements covering crude oil and natural gas prices\nwithout prior WTNB approval.\n\n \n\nThere\nwas no balance outstanding on the credit facility as of March 31, 2026 and 2025. The following table is a summary of activity on the\nWTNB credit facility for the years ended March 31, 2026 and 2025:\n\n Summary\nof Line of Credit Activity\n\n  \nPrincipal \n\nBalance at April 1, 2024: \n$- \n\nBorrowings \n 650,000 \n\nRepayments \n (650,000)\n\nBalance at March 31, 2025: \n$- \n\nBorrowings \n - \n\nRepayments \n - \n\nBalance at March 31, 2026: \n$- \n\n \n\nF-11\n\n \n\n \n\n4.\nAsset Retirement Obligations\n\n \n\nThe\nCompany’s asset retirement obligations relate to the plugging of wells, the removal of facilities and equipment, and site restoration\non oil and gas properties. The ARO is included on the consolidated balance sheets, with the current portion included in accounts payable\nand accrued expenses.\n\n \n\nThe\nfollowing table provides a rollforward of the asset retirement obligations for fiscal years ended March 31:\n\n Schedule of Rollforward of Asset Retirement Obligations\n\n  \n2026  \n2025 \n\nCarrying amount of asset retirement obligations, beginning of year \n$718,842  \n$718,808 \n\nLiabilities incurred \n 9,592  \n 5,231 \n\nLiabilities settled \n (31,285) \n (35,180)\n\nAccretion expense \n 32,168  \n 29,983 \n\nRevisions \n -  \n - \n\nCarrying amount of asset retirement obligations, end of year \n 729,317  \n 718,842 \n\nLess: Current portion \n 30,000  \n 30,000 \n\nNon-Current asset retirement obligation  \n$699,317  \n$688,842 \n\n \n\n5.\nIncome Taxes\n\n \n\nOn\nJuly 4, 2025, the “One Big Beautiful Bill” (“OBBB”) was enacted. The OBBB is a comprehensive piece of legislation\nthat includes significant changes to federal tax policy, environmental funding, and energy development regulations. Key provisions relevant\nto the crude oil and natural gas industry include (i) tax policy changes that extend and expand components of the 2017 Tax Cuts and Jobs\nAct and (ii) the introduction of fee and royalty-related provisions aimed at reducing financial and administrative burdens on domestic\nenergy producers. The Company has evaluated the impact of the OBBB; however, certain provisions continue to be assessed for their impact\non our consolidated financial statements in future periods.\n\n \n\nThe\nCompany files a consolidated federal income tax return and various state income tax returns. The amount of income taxes the Company records\nrequires the interpretation of complex rules and regulations of federal and state taxing jurisdictions. With few exceptions, the earliest\nyear open to examination by U.S. federal and state income tax jurisdictions is 2021.\n\n \n\nThe\nincome tax provision consists of the following for the years ended March 31, 2026 and 2025:\n\n Schedule of Income Tax Provision\n\n  \n2026  \n2025 \n\n  \nYear Ended \n\n  \nMarch 31 \n\n  \n2026  \n2025 \n\nCurrent income tax expense: \n    \n   \n\nFederal \n$107,292  \n$232,035 \n\nState \n 58,682  \n 63,352 \n\nTotal current income tax expense \n$165,974  \n$295,387 \n\nDeferred income tax expense (benefit): \n    \n   \n\nFederal \n 224,910  \n 56,614 \n\nState \n (11,841) \n (47,671)\n\nTotal deferred income tax expense \n$213,069  \n$8,943 \n\nTotal income tax expense: \n$379,043  \n$304,330 \n\n \n\nIncome\ntax for the year ended March 31, 2026 was $379,043. Income tax for the year ended March 31, 2025 was $304,330.\n\n \n\nF-12\n\n \n\n \n\nGAAP\nrequires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences\nare to be realized or settled. Significant components of net deferred tax assets (liabilities) at March 31 are as follows:\n\n Schedule of Components of Net Deferred Tax Assets (Liabilities)\n\n  \n2026  \n2025 \n\nDeferred tax assets: \n    \n   \n\nPercentage depletion carryforwards \n$1,108,633  \n$1,283,374 \n\nStock-based compensation \n 15,745  \n 15,745 \n\nAsset retirement obligation \n 153,157  \n 150,957 \n\nOther \n 94,650  \n 82,083 \n\nTotal\ndeferred tax assets \n$1,372,185  \n$1,532,159 \n\n  \n    \n   \n\nDeferred tax liabilities: \n    \n   \n\nExcess financial accounting bases over tax bases of property and equipment \n (1,905,858) \n (1,852,763)\n\nDeferred tax liability, net \n$(533,673) \n$(320,604)\n\nValuation allowance \n -  \n - \n\nNet deferred tax liabilities \n$(533,673) \n$(320,604)\n\n \n\nAs\nof March 31, 2026, the Company has a statutory depletion carryforward of approximately $5,300,000, which does not expire.\n\n \n\nA\nreconciliation of the provision for income taxes to income taxes computed using the federal statutory rate for years ended March 31 follows:\n\n Schedule of Reconciliation of Provision for Income Taxes\n\n  \n2026  \n\n% of Income Before\n\nIncome Taxes\n  \n2025  \n\n% of Income Before\n\nIncome Taxes\n \n\nTax expense at federal statutory rate (1) \n$353,801  \n 21.0% \n$423,507  \n 21.0%\n\nExcess percentage depletion \n (63,000) \n (3.7)% \n (153,438) \n (7.6)%\n\nPermanent differences \n 30,966  \n 1.8% \n 22,206  \n 1.1%\n\nState income expense, net of federal benefit \n 37,004  \n 2.2% \n 50,048  \n 2.5%\n\nOther \n 20,272  \n 1.2% \n (37,993) \n (1.9)%\n\nTotal income tax \n$379,043  \n 22.5% \n$304,330  \n 15.1%\n\n \n\n(1)The\nfederal statutory rate was 21% for fiscal years ending March 31, 2026 and 2025.\n\n \n\nFor\nthe years ended March 31, 2026 and 2025, the Company did not have any uncertain tax positions.\n\n \n\n6.\nMajor Customers\n\n \n\nCurrently,\nthe Company operates exclusively within the United States, and its revenues and operating profit are derived from the oil and gas industry.\nOil and gas production is sold to various purchasers, and the receivables are unsecured. Historically, the Company has not experienced\nsignificant credit losses on its oil and gas accounts, and management is of the opinion that significant credit risk does not exist. Management\nis 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\nand gas production.\n\n \n\nIn\nfiscal 2026, BTA Oil Producers, LLC accounted for 33% of the total operating revenues and 37% of the total oil and natural gas accounts\nreceivable; Apex Natural Gas LLC accounted for 2% of the total operating revenues and 11% of the total oil and natural gas accounts receivable;\nand Exxon Mobil Corporation accounted for 15% of the total operating revenues and 7% of the total oil and natural gas accounts receivable.\nIn 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;\nPermian 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.\n\n \n\nF-13\n\n \n\n \n\n7.\nOil and Natural Gas Costs\n\n \n\nThe\ncosts related to the Company’s oil and natural gas activities were incurred as follows for the years ended March 31:\n\n Schedule of Cost Related to Oil and Gas Activities\n\n  \n2026  \n2025 \n\nProperty acquisition costs: \n    \n   \n\nProved \n$809,401  \n$1,984,243 \n\nUnproved \n -  \n - \n\nExploration \n 80,892  \n 31,934 \n\nDevelopment \n 1,170,674  \n 1,417,163 \n\nCapitalized asset retirement obligations \n 9,592  \n 5,231 \n\nTotal costs incurred for oil and gas properties \n$2,070,559  \n$3,438,571 \n\n \n\nThe\nCompany had the following aggregate capitalized costs relating to its oil and gas property activities at March 31:\n\n Schedule\nof Aggregate Capitalized Costs Relating Oil and Gas Property Activities\n\n  \n2026  \n2025 \n\nProved oil and gas properties \n$53,664,668  \n$51,611,782 \n\nUnproved oil and gas properties: \n    \n   \n\nsubject to amortization \n -  \n - \n\nnot subject to amortization \n -  \n - \n\nOil and gas properties,\ngross \n$53,664,668  \n$51,611,782 \n\nLess accumulated DD&A \n 39,040,201  \n 36,517,279 \n\nTotal\noil and gas properties \n$14,624,467  \n$15,094,503 \n\n \n\nDD&A\namounted to $11.02 and $13.74 per BOE of production for the years ended March 31, 2026 and 2025, respectively.\n\n \n\n8.\nIncome Per Common Share\n\n \n\nThe\nfollowing is a reconciliation of the number of shares used in the calculation of basic income per share and diluted income per share\nfor the years ended March 31:\n\n \n\nSchedule of Reconciliation of Basic and Diluted Net Income (Loss) Per Share\n\n  \n2026  \n2025 \n\nNet income \n$1,305,722  \n$1,712,368 \n\n  \n    \n   \n\nShares outstanding: \n    \n   \n\nWeighted avg. common shares outstanding – basic \n 2,046,000  \n 2,064,147 \n\nEffect of the assumed exercise of dilutive stock options \n 34,503  \n 43,628 \n\nWeighted avg. common shares outstanding – dilutive \n 2,080,503  \n 2,107,775 \n\n  \n    \n   \n\nIncome per common share: \n    \n   \n\nBasic \n$0.64  \n$0.83 \n\nDiluted \n$0.63  \n$0.81 \n\n \n\nFor\nthe years ended March 31, 2026 and 2025, 60,500 shares relating to stock options were excluded from the computation of diluted net income\nbecause their inclusion would be anti-dilutive. Anti-dilutive stock options have a weighted average exercise price of $15.34 at March\n31, 2026.\n\n \n\nF-14\n\n \n\n \n\n9.\nStockholders’ Equity\n\n \n\nIn\nApril 2024, the Company’s Board (the “Board”) authorized the use of up to $1,000,000 to repurchase shares of the Company’s\ncommon stock, par value $0.50, for the treasury account. This program has no expiration date and may be modified, suspended,\nor terminated at any time by the Board. Under the repurchase program, common stock may be purchased from time to time through open-market\npurchases or other transactions. The amount and timing of repurchases will be subject to the availability of stock, prevailing market\nconditions, the trading price of stock, our financial performance, and other conditions. Repurchases may also be made from time to time\nin connection with the settlement of our share-based compensation awards. Repurchases will be funded from cash flow. As of March 31,\n2026, the Company’s repurchase program approved in April 2024 had $296,784 in remaining funds.\n\n \n\nSubsequently,\nin June 2026, the Board authorized the use of an additional $250,000 to repurchase shares of the Company’s common stock, par value\n$0.50, for the treasury account. To date, the Company’s repurchase program has $546,784 remaining.\n\n \n\nDuring\nthe year ended March 31, 2026, no shares of common stock were repurchased for the treasury account. During the year ended March 31, 2025,\nthe Company repurchased 57,766 shares for the treasury account at an aggregate cost of $703,216, an average price of $12.17 per share.\n\n \n\n10.\nStock-based Compensation\n\n \n\nIn\nSeptember 2019, the Company adopted the 2019 Employee Incentive Stock Plan (the “2019 Plan”). The 2019 Plan provides for\nthe award of stock options up to 200,000 shares and includes option awards as well as stock awards. Option awards are granted with the\nrestriction of requiring payment for the shares. Stock awards are granted without restrictions and without payment by the recipient.\nNeither option awards nor stock awards may exceed 25,000 shares granted to any one individual in any fiscal year. Stock options may be\nan incentive stock option or a nonqualified stock option. Options to purchase common stock under the plan are granted at the fair market\nvalue 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\nof the date of grant, expire ten years from the date of grant and are subject to forfeiture if employment terminates. The 2019 Plan expires\nten years from the date of adoption. According to the Company’s employee stock incentive plan, new shares will be issued upon the\nexercise of stock options and the Company can repurchase shares exercised under the plan.\n\n \n\nThe\nCompany recognized compensation expense of $174,000 and $205,639 related to vesting stock options in general and administrative expense\nin the Consolidated Statements of Operations for fiscal 2026 and 2025, respectively. The total cost related to non-vested awards not\nyet recognized at March 31, 2026 totals $106,173, which is expected to be recognized over a weighted average of 0.82 years.\n\n \n\nThe\nfair value of each stock option is estimated on the date of grant using the Binomial valuation model. Expected volatilities are based\non historical volatility of the Company’s stock over the contractual term of 120 months and other factors. The Company uses historical\ndata to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived\nfrom the output of the option valuation model and represents the period of time that options granted are expected to be outstanding.\nThe 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\nof grant. No dividend yield was used in the calculation on current options outstanding because at the time of the last issuance of stock\noptions, either no dividend had been declared or the Company had only declared a special one-time dividend. Actual value realized, if\nany, is dependent on the future performance of the Company’s common stock and overall stock market conditions. There is no assurance\nthat the value realized by an optionee will be at or near the value estimated by the Binomial model.\n\n \n\nDuring\nthe years ended March 31, 2026 and 2025, there were no stock options granted.\n\n \n\nThe\nplan also provides for the granting of stock awards. No stock awards were granted during fiscal 2026 and 2025.\n\n \n\nF-15\n\n \n\n \n\nNo\nforfeiture rate is assumed for stock options granted to directors or employees due to the Company’s historically low\nforfeiture experience for these types of awards. During the year ended March 31, 2026, there were no\nstock options forfeited or expired. During the year ended March 31, 2025, 1,875\nunvested stock options and 625\nvested stock options were forfeited due to the resignation of an employee.\n\n \n\nThe\nfollowing table is a summary of activity of stock options for the years ended March 31, 2026 and 2025:\n\nSchedule of Activity of Stock Options  \n\n  \nNumber of Shares  \nWeighted Average Exercise Price Per Share  \nWeighted Aggregate Average Remaining Contract Life\nin Years  \nIntrinsic Value \n\nOutstanding at April 1, 2024 \n 165,750  \n$9.36  \n 6.62  \n$103,275 \n\nGranted \n -  \n -  \n    \n   \n\nExercised \n (12,367) \n 6.28  \n    \n   \n\nForfeited or Expired \n (2,500) \n 14.83  \n    \n   \n\nOutstanding at March 31, 2025 \n 150,883  \n$9.52  \n 5.98  \n$- \n\nGranted \n -  \n -  \n    \n   \n\nExercised \n -  \n -  \n    \n   \n\nForfeited or Expired \n -  \n -  \n    \n   \n\nOutstanding at March 31, 2026 \n 150,883  \n$9.52  \n 4.98  \n$105,825 \n\n  \n    \n    \n    \n   \n\nVested at March 31, 2026 \n 128,133  \n$8.64  \n 4.65  \n$202,065 \n\nExercisable at March 31, 2026 \n 128,133  \n$8.64  \n 4.65  \n$202,065 \n\n \n\nDuring\nthe year ended March 31, 2026, no stock options were exercised. During the year ended March 31, 2025, stock options covering 12,367 shares\nwere exercised with a total intrinsic value of $92,316. The Company received proceeds of $77,641 from these exercises.\n\n \n\nOther\ninformation pertaining to option activity was as follows during the year ended March 31:\n\nSchedule of Other Information Pertaining to Option Activity  \n\n  \n2026  \n2025 \n\nWeighted average grant-date fair value of stock options granted (per share) \n$-  \n$- \n\nTotal fair value of options vested \n$-  \n$205,241 \n\nTotal intrinsic value of options exercised \n$-  \n$92,316 \n\n \n\nThe\nfollowing table summarizes information about options outstanding at March 31, 2026:\n\nSchedule of Information About Options Outstanding  \n\nRange of\n\nExercise Prices\n  \n\nNumber of\n\nOptions\n  \n\nWeighted\n\nAverage\n\nExercise Price\n\nPer Share\n  \n\nWeighted Average\n\nRemaining\n\nContract Life in\n\nYears\n  \n\nAggregate\n\nIntrinsic\n\nValue\n \n\n$3.34 – 4.83  \n 25,677  \n$3.34  \n    \n   \n\n 4.84\n– 5.97  \n 35,000  \n 4.84  \n    \n   \n\n 5.98 – 8.51  \n 29,706  \n 8.51  \n    \n   \n\n 8.52\n– 18.05  \n 60,500  \n 15.34  \n    \n   \n\n$3.34 – 18.05  \n 150,883  \n$9.52  \n 4.98  \n$- \n\n \n\nOutstanding\noptions at March 31, 2026 expire between September 2028 and April 2033 and have exercise prices ranging from $3.34 to $18.05.\n\n \n\n11.\nRelated Party Transactions\n\n \n\nRelated\nparty transactions for the Company consists of shared office expenditures, as well as administrative and operating expenses paid on\nbehalf of the principal stockholder. The total amount billed to and reimbursed by the principal stockholder for the years ended\nMarch 31, 2026 and 2025 were $49,661\nand $31,506,\nrespectively. The principal stockholder pays for his share of the lease amount for the shared office space directly to the lessor.\nAmounts paid by the principal stockholder directly to the lessor for the years ending March 31, 2026 and 2025 were $10,175\nand $11,974,\nrespectively.\n\n \n\nF-16\n\n \n\n \n\n12.\nCommitments and Contingencies\n\n \n\nFrom\ntime to time, the Company is a party to litigation or other legal proceedings that the Company considers to be part of the ordinary\ncourse of business. The Company is not currently involved in any legal proceedings that it considers probable to result in, or\nreasonably likely to result in, a material adverse effect on its financial condition, results of\noperations, or liquidity.\n\n \n\n13.\nLeases\n\n \n\nThe\nCompany leases approximately 4,160 rentable square feet of office space from an unaffiliated third party for the corporate office located\nin Midland, Texas. This includes 702 square feet of office space shared with and paid by our principal shareholder. In June 2024, the\nCompany agreed to extend its current lease at a flat (unescalated) rate for 36 months. The amended lease expires on July 31, 2027.\n\n \n\nThe\nCompany determines that an arrangement is a lease at inception. Operating leases are recorded as operating lease right-of-use asset,\noperating lease liability, current, and operating lease liability, long-term on the consolidated balance sheets.\n\n \n\nOperating\nlease right-of-use assets represent the Company’s right to use an underlying asset for the lease term, and lease liabilities represent\nits obligation to make lease payments arising from the lease. Operating lease assets and liabilities are recognized at the commencement\ndate based on the present value of lease payments over the lease term. As the Company’s lease does not provide an implicit rate,\nthe Company uses the incremental borrowing rate based on the information available at commencement date in determining the present value\nof lease payments. The incremental borrowing rate used at adoption was 9%. Significant judgment is required when determining the incremental\nborrowing rate. Rent expense for lease payments is recognized on a straight-line basis over the lease term.\n\n \n\nThe\nbalance sheet classification of lease assets and liabilities was as follows:\n\nSchedule\nof Operating Lease Assets and Liabilities  \n\n  \nMarch 31,\n2026 \n\nAssets \n   \n\nOperating lease right-of-use asset, beginning balance \n$126,525 \n\nCurrent period amortization \n (51,003)\n\nLease extension \n - \n\nTotal operating lease right-of-use asset \n$75,522 \n\n  \n   \n\nLiabilities \n   \n\nOperating lease liability, current \n$55,787 \n\nOperating lease liability, long term \n 19,735 \n\nTotal lease liabilities \n$75,522 \n\n \n\nFuture\nminimum lease payments as of March 31, 2026 under non-cancellable operating leases are as follows:\n\n Schedule of Future Minimum Lease Payments \n\n  \nLease Obligation \n\nFiscal Year Ended March 31, 2027 \n 60,320 \n\nFiscal Year Ended March 31, 2028 \n 20,107 \n\nTotal lease payments \n$80,427 \n\nLess: imputed interest \n (4,905)\n\nOperating lease liability \n 75,522 \n\nLess: operating lease liability, current \n (55,787)\n\nOperating lease liability, long term \n$19,735 \n\n \n\nNet\ncash paid for our operating lease for the years ended March 31, 2026 and 2025 was $50,145\nand $47,653,\nrespectively. Operating lease expense, including amortization of the operating lease right of use asset, and rent expense, less\nsublease income of $10,175,\nare included in general and administrative expenses on the consolidated statements of operations.\n\n \n\nF-17\n\n \n\n \n\n14.\nAcquisitions\n\n \n\nDuring\nthe year ended March 31, 2026, the Company incurred approximately $818,000 in acquisition costs to acquire various royalty interests\nin 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\nwhich we already hold an interest in Louisiana and Texas, as well as 40 undeveloped net acres in New Mexico.\n\n \n\nDuring\nthe year ended March 31, 2025, the Company incurred approximately $2,000,000 in acquisition costs to acquire various royalty interests\nin approximately 840 producing wells in Colorado, Louisiana, Montana, Nebraska, New Mexico, North and South Dakota, Texas, and Wyoming.\n\n \n\n15.\nOil and Gas Reserve Data (Unaudited)\n\n \n\nThe\nestimates of the Company’s proved oil and gas reserves, which are located entirely within the United States, were prepared in accordance\nwith the generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The\nestimates as of March 31, 2026 and 2025 were based on evaluations prepared by Russell K. Hall and Associates, Inc. The services provided\nby Russell K. Hall and Associates, Inc. are not audits of our reserves but instead consist of complete engineering evaluations of the\nrespective properties. For more information about their evaluations performed, refer to the copy of their report filed as an exhibit\nto this Annual Report on Form 10-K. Management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries\nare more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change\nas additional information becomes available in the future.\n\n \n\nThe\nfollowing table presents the weighted-average first-day-of-the-month market prices used for oil and gas reserve preparation, based on\nSEC guidelines.\n\n Schedule of Weighted Average First-day-of-the-month Prices Used for Oil and Gas Reserve\n\n  \nMarch 31,  \n  \n\n  \n2026  \n2025  \n% Change \n\nPrices utilized in the reserve estimates before adjustments: \n    \n    \n   \n\nOil per Bbl \n$59.79  \n$71.00  \n (16)%\n\nNatural gas per MMBtu \n$3.72  \n$2.44  \n 52%\n\n \n\nF-18\n\n \n\n \n\nThe\nCompany’s total estimated proved reserves at March 31, 2026 were approximately 1.437 MMBOE, of which 46% was oil and 54% was natural\ngas.\n\n \n\n**Changes\nin Proved Reserves**:\n\n Schedule of Changes in Proved Reserve\n\n  \nOil\n(Bbls)  \nNatural Gas\n(Mcf) \n\nProved Developed and Undeveloped Reserves: \n    \n   \n\nAs of April 1, 2024 \n 791,000  \n 4,537,000 \n\nRevision of previous estimates \n (132,000) \n (71,000)\n\nPurchase of minerals in place \n 40,000  \n 221,000 \n\nExtensions and discoveries \n 60,000  \n 243,000 \n\nSales of minerals in place \n -  \n - \n\nProduction \n (84,000) \n (570,000)\n\nAs of March 31, 2025 \n 675,000  \n 4,360,000 \n\nRevision of previous estimates \n (106,000) \n 315,000 \n\nPurchase of minerals in place \n 18,000  \n 124,000 \n\nExtensions and discoveries \n 155,000  \n 557,000 \n\nSales of minerals in place \n (1,000) \n (3,000)\n\nProduction \n (82,000) \n (682,000)\n\nAs of March 31, 2026 \n 659,000  \n 4,671,000 \n\n \n\nProved\ndeveloped reserves are those expected to be recovered through existing wells, equipment, and operating methods. Proved undeveloped\nreserves (“PUD”) are proved reserves that are expected to be recovered from new wells on undrilled acreage or from\nexisting wells where a relatively major expenditure is required for recompletion within five years of the date of their initial\nrecognition. Moreover, the Company may be required to write down its proved undeveloped reserves if the operators do not drill on\nthe reserves within the required five-year timeframe. The reduction in proved undeveloped reserves was primarily attributable to\nproperties in Lea County, New Mexico, due to changes in the timing of future development in wells in which we own a working\ninterest. These interests are held by production and remain in place for future development.\n\n \n\n**Summary\nof Proved Developed and Undeveloped Reserves as of March 31, 2026 and 2025**:\n\nSummary of Proved Developed and Undeveloped Reserves** **\n\n  \nOil\n(Bbls)  \nNatural Gas\n(Mcf) \n\nProved Developed Reserves: \n    \n   \n\nAs of April 1, 2024 \n 444,610  \n 3,566,240 \n\nAs of March 31, 2025 \n 405,840  \n 3,654,900 \n\nAs of March 31, 2026 \n 462,780  \n 4,204,610 \n\nProved Undeveloped Reserves: \n    \n   \n\nAs of April 1, 2024 \n 346,330  \n 970,880 \n\nAs of March 31, 2025 \n 269,000  \n 704,810 \n\nAs of March 31, 2026 \n 195,840  \n 466,060 \n\n \n\nAt\nMarch 31, 2026, the Company reported estimated PUDs of 274 MBOE, which accounted for 19% of its total estimated proved oil and gas reserves.\nThis 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\n2027, 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\ncash balances, cash flow from operations, and bank borrowings. The remainder may be funded through non-core asset sales and/or sales\nof our common stock.\n\n \n\nF-19\n\n \n\n \n\nThe\nfollowing table discloses the Company’s progress toward the conversion of PUDs during fiscal 2026.\n\n \n\n**Progress\nof Converting Proved Undeveloped Reserves**:\n\n \n\nSchedule\nof Progress of Converting Proved Undeveloped Reserves\n\n  \n\nOil & Natural Gas\n\n(BOE)\n  \n\nFuture\n\nDevelopment Costs\n \n\nPUDs, beginning of year \n 386,462  \n$4,011,975 \n\nRevision of previous estimates \n (106,667) \n (1,713,376)\n\nSales of reserves \n -  \n - \n\nConversions to PD reserves \n (66,539) \n (119,475)\n\nAdditional PUDs added \n 60,261  \n 1,179,554 \n\nPUDs, end of year \n 273,517  \n$3,358,678 \n\n \n\nEstimated\nfuture net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2026\nand 2025, along with estimates of the operating costs, production taxes, and future development costs necessary to produce such reserves.\nNo deduction has been made for depreciation, depletion, or any indirect costs such as general corporate overhead or interest expense.\n\n \n\nOperating\ncosts and production taxes are estimated based on current costs with respect to producing oil and natural gas properties. Future development\ncosts, including abandonment costs, are based on the best estimate of such costs assuming current economic and operating conditions.\nEstimated future development costs associated with the Company’s proved undeveloped properties through March 31, 2030\nare $3,358,678.\n\n \n\nIncome\ntax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production\nand development costs over the current tax basis of the properties involved, less applicable carryforwards.\n\n \n\nThe\nfuture net revenue information assumes no escalation of costs or prices, except for oil and natural gas sales made under contracts that\ninclude fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions\nin the future could be significant.\n\n \n\nThe\nSEC reporting rules require that year-end reserve estimates and related future net cash flows be calculated using the unweighted\narithmetic average of the first-day-of-the-month market prices for oil and natural gas during the 12-month period and discounted at 10%\nper year and assuming continuation of existing economic and operating conditions. The average prices used for fiscal 2026 were $62.76\nper 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\nof natural gas.\n\n \n\nThe\nstandardized measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first day of\nthe month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements)\nto the estimated future production of proved oil and natural gas reserves, less estimated future expenditures (based on year-end costs)\nto be incurred in developing and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing\nof the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and\nnatural gas properties plus available carryforwards and credits and applying the current tax rate to the difference.\n\n \n\nThe\nbasis for this table is the reserve studies prepared by an independent petroleum engineering consultant, which contain imprecise estimates\nof quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results.\nAlso, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates\nof proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flows is not necessarily indicative\nof the fair value of proved oil and gas properties.\n\n \n\nThe\nfollowing information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future\nNet Cash Flows as of March 31, 2026 and 2025 in accordance with ASC 932, “Extractive Activities – Oil and Gas”, which\nrequires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value\nof future cash flows of the Company’s proved oil and gas reserves.\n\n \n\nF-20\n\n \n\n \n\n**Standardized\nMeasure of Discounted Future Net Cash Flows Relating to Proved Reserves:**\n\nSchedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves ** **\n\n  \n2026  \n2025 \n\n  \nMarch 31 \n\n  \n2026  \n2025 \n\nFuture cash inflows \n$51,791,000  \n$59,135,000 \n\nFuture production costs and taxes \n (15,010,000) \n (18,172,000)\n\nFuture development costs \n (3,858,000) \n (4,137,000)\n\nFuture income taxes \n (3,843,000) \n (4,982,000)\n\nFuture net cash flows \n 29,080,000  \n 31,844,000 \n\nAnnual 10% discount for estimated timing of cash flows \n (10,415,000) \n (11,769,000)\n\nStandardized measure of discounted future net cash flows \n$18,665,000  \n$20,075,000 \n\n \n\n**Changes\nin Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:**\n\nSchedule of Changes in Standardized Measure of Discounted Future Net Cash Flows to Proved Oil and Gas Reserves** **** **\n\n  \n2026  \n2025 \n\n  \nMarch 31 \n\n  \n2026  \n2025 \n\nSales of oil and gas produced, net of production costs \n$(5,120,000) \n$(5,511,000)\n\nNet changes in price and production costs \n (1,807,000) \n (2,735,000)\n\nChanges in previously estimated development costs \n 7,000  \n (1,111,000)\n\nRevisions of quantity estimates \n (3,438,000) \n (5,155,000)\n\nNet change due to purchases and sales of minerals in place \n 838,000  \n 1,996,000 \n\nExtensions and discoveries, less related costs \n 4,727,000  \n 1,713,000 \n\nNet change in income taxes \n 675,000  \n 1,309,000 \n\nAccretion of discount \n 2,322,000  \n 2,321,000 \n\nChanges in timing of estimated cash flows and other \n 386,000  \n 2,620,000 \n\nChanges in standardized measure \n (1,410,000) \n (4,553,000)\n\nStandardized measure, beginning of year \n 20,075,000  \n 24,628,000 \n\nStandardized measure, end of year \n$18,665,000  \n$20,075,000 \n\n** **\n\n**16.\nEmployee 401(k) Plan**\n\n** **\n\nIn\nJanuary 2026, the Company adopted a defined contribution 401(k) retirement savings plan for eligible employees. As of March 31, 2026,\nthe plan had not commenced operations, and no employee salary deferrals or employer matching contributions had been made. Accordingly,\nno expense related to the plan was recognized during the year ended March 31, 2026.\n\n \n\n**17.\nSubsequent Events**\n\n** **\n\nIn\nApril 2026, effective May 1, 2026, the Company acquired royalty interests in 144 producing wells in Weld County, Colorado and Atascosa,\nHoward, LaSalle, Martin, and Yoakum Counties, Texas, and additional royalty interests in 3 properties in which we already hold an interest\nin Howard County, Texas, for an aggregate purchase price of $1,028,600.\n\n \n\nIn\nMay 2026, Mexco expended approximately $460,000 to participate in the drilling and completion of six horizontal wells in the Wolfcamp\nA formation of the Delaware Basin in Reeves County, Texas.\n\n \n\nOn\nJune 4, 2026, the Company announced that its Board declared a regular annual dividend of $0.10 per common share to its shareholders of\nrecord 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.\n\n \n\nIn June 2026, effective July 1, 2026, the Company acquired royalty interests in 256 producing wells in Adams and Larimer Counties,\nColorado; Caddo and DeSoto Parishes, Louisiana; Karnes, McMullen, Panola, and Winkler Counties, Texas; and Ashtabula County, Ohio\nfor an aggregate purchase of $1,066,600.\n\n \n\nThe\nCompany completed a review and analysis of all events that occurred after the consolidated balance sheet date to determine if any such\nevents must be reported and has determined that there are no other subsequent events to be disclosed.\n\n** **\n\nF-21\n\n \n\n** **\n\n**INDEX\nTO EXHIBITS**\n\n** **\n\n**Exhibit Number**\n  \n\n3.1\n [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.](https://www.sec.gov/Archives/edgar/data/66418/0000930661-98-001436.txt)\n\n \n  \n\n3.2\n [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.](https://www.sec.gov/Archives/edgar/data/66418/000139834411002146/fp0003462_ex3-1.htm)\n\n \n  \n\n10.1\n [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.](https://www.sec.gov/Archives/edgar/data/66418/000139834409000714/fp0000863_def14a.htm)\n\n \n  \n\n10.2\n [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.](https://www.sec.gov/Archives/edgar/data/66418/000149315219010702/def14a.htm#a_032)\n\n \n  \n\n10.3\n [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.](https://www.sec.gov/Archives/edgar/data/66418/000149315218018107/ex10-1.htm)\n\n \n  \n\n10.4\n [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.](https://www.sec.gov/Archives/edgar/data/66418/000149315220011905/ex10-4.htm)\n\n \n  \n\n10.5\n [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.](https://www.sec.gov/Archives/edgar/data/66418/000149315223022509/ex10-5.htm)\n\n \n  \n\n10.6\n [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.](ex10-6.htm)\n\n \n  \n\n14.1\n [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.](https://www.sec.gov/Archives/edgar/data/66418/000114420404019070/v08581_exhibit14.txt)\n\n \n  \n\n21.1\n [Subsidiaries of Mexco Energy Corporation](ex21-1.htm)\n\n \n  \n\n23.1\n [Consent of Weaver and Tidwell, L.L.P., Independent Registered Public Accounting Firm](ex23-1.htm)\n\n \n  \n\n23.2\n [Consent of Russell K. Hall & Associates, Inc., Independent Petroleum Engineers](ex23-2.htm)\n\n \n  \n\n31.1\n [Certification of the Chief Executive Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.](ex31-1.htm)\n\n \n  \n\n31.2\n [Certification of the Chief Financial Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.](ex31-2.htm)\n\n \n  \n\n32.1\n [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.](ex32-1.htm)\n\n \n  \n\n99.1\n [Report of Russell K. Hall & Associates, Inc., Independent Petroleum Engineering Firm](ex99-1.htm)\n\n \n  \n\n101.INS\n Inline\nXBRL Instance Document\n\n \n  \n\n101.SCH\n Inline\nXBRL Taxonomy Extension Schema Document\n\n \n  \n\n101.CAL\n Inline\nXBRL Taxonomy Extension Calculation Linkbase Document\n\n \n  \n\n101.DEF\n Inline\nXBRL Taxonomy Extension Definition Linkbase Document\n\n \n  \n\n101.LAB\n Inline\nXBRL Taxonomy Extension Label Linkbase Document\n\n \n  \n\n101.PRE\n Inline\nXBRL Taxonomy Extension Presentation Linkbase Document\n\n \n  \n\n104\n Cover\nPage Interactive Data File (embedded within the Inline XBRL and contained in Exhibit 101)\n\n \n\nF-22"}