{"url_path":"/sec/mxc/10-k/2026/item-1","section_key":"item-1","section_title":"Item 1 Business – Company Profile.","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":1193,"has_tables":true,"body_markdown":"Item 1. Business – Company Profile.\n\n \n\n(2)PV-10\nrepresents the present value of estimated future net cash flows attributable to our proved\noil and natural gas reserves, before income taxes, discounted at 10% per annum. PV-10 is\na non-GAAP financial measure. It is relevant to investors because it provides a standardized\nbasis for comparing the relative size and value of proved reserves across companies and excludes\nthe impact of future income taxes. We use PV-10 internally to evaluate the economic attractiveness\nof our oil and natural gas properties. The standardized measure of discounted future net\ncash flows is derived from PV-10 after deducting estimated future income taxes.\n\n \n\n(3)In\naccordance with SEC requirements, the standardized measure of discounted future net cash\nflows is calculated using 12-month average first-day-of-the-month prices for oil and natural\ngas. Future cash flows are estimated based on expected production from proved reserves, reduced\nby estimated future development and production costs (based on year-end costs) and estimated\nfuture income taxes (based on year-end statutory tax rates, including consideration of enacted\nfuture rate changes and available tax attributes). All calculations assume continuation of\nexisting economic conditions and constant prices and costs over the life of the reserves.\n\n \n\n(4)These\nprices reflect adjustments by lease for quality, transportation fees, and market differentials.\n\n \n\nDuring fiscal 2026, we added proved reserves of 247 thousand BOE (“MBOE”) through extensions and discoveries, added 39 MBOE\nthrough acquisitions, and added 53 MBOE for upward revisions of previous estimates. Such upward revisions are primarily attributable to\nimproved well performance, revisions to estimated future recoveries based on additional production history, and changes in the timing\nof future development activities. The reduction in proved undeveloped reserves was primarily attributable to properties in Lea County,\nNew Mexico, due to changes in the timing of future development in wells in which we own a working interest. These interests are held by\nproduction and remain in place for future development.\n\n \n\nDuring\nthe fiscal year ending March 31, 2026, we had a working or royalty interest in the development of 25 wells, converting reserves of approximately\n48,000 BOE from proved undeveloped to proved developed – producing with a capital cost of approximately $119,000.\n\n \n\nOil\nand natural gas prices significantly impact the calculation of PV-10 and the standardized measure of discounted future net cash flows.\nThese measures do not represent an estimate of the fair value of the Company’s proved reserves. Any estimate of fair value would\nalso consider, among other factors, expected changes in future prices and costs, recovery of reserves beyond proved reserves, and a discount\nrate more reflective of the time value of money and associated risks.\n\n \n\nFuture\nprices and costs may differ materially from those used in these estimates. The 10% discount rate required by Financial Accounting Standards\nBoard (“FASB”) Accounting Standards Codification (“ASC”) 932, *Extractive Activities—Oil and Gas*,\nmay not be the most appropriate rate for all purposes. In addition, the present value calculations are highly sensitive to assumptions\nregarding the timing of future production, which may prove inaccurate.\n\n \n\nWe\nhave not filed any other oil or gas reserve estimates or included any such estimates in reports to other federal or foreign governmental\nauthorities or agencies during the year ended March 31, 2026, and no major discovery is believed to have caused a significant change\nin our estimates of proved reserves since that date.\n\n \n\n17\n\n \n\n \n\nDrilling\nActivities\n\n \n\nThe\nfollowing table sets forth our drilling activity in wells in which we own a working interest for the years ended March 31:\n\n \n\n  \nYear\nEnded March 31, \n\n  \n2026  \n2025 \n\n  \nGross  \nNet  \nGross  \nNet \n\nExploratory Wells \n    \n    \n    \n   \n\nBeginning wells in progress \n -  \n -  \n -  \n - \n\nWells spud \n 1  \n .02  \n 1  \n .10 \n\nSuccessful\nwells \n 0  \n -  \n 0  \n - \n\nEnding\nwells in progress \n -  \n -  \n -  \n - \n\n  \n    \n    \n    \n   \n\nDevelopment Wells \n    \n    \n    \n   \n\nBeginning wells in progress \n 17  \n .03  \n 16  \n .17 \n\nWells spud \n 58  \n .19  \n 38  \n .09 \n\nSuccessful\nwells \n (55) \n (.08) \n (37) \n (.23)\n\nEnding\nwells in progress \n 20  \n .14  \n 17  \n .03 \n\n \n\nThe\ninformation contained in the foregoing table should not be considered indicative of future drilling performance, nor should it be assumed\nthat there is any necessary correlation between the number of productive wells drilled and the amount of oil and gas that may ultimately\nbe recovered by us.\n\n \n\nIn\naddition to the working interests mentioned above, other operators drilled 177 gross wells (.07 net wells) on Company-owned minerals\nand royalties at no expense to the Company. We expect production from our mineral interests to increase as operators continue to drill,\ncomplete, and develop our acreage. We expect to capitalize on this development, which requires no capital expenditure funding from us,\nand believe the anticipated aggregate royalty receipts will enable us to grow our cash flows. A number of the horizontal wells in which\nthe Company participates involve longer laterals that are more efficient and have greater estimated ultimate recovery.\n\n \n\n**Productive\nWells and Acreage**\n\n \n\nProductive\nwells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections. Wells that are completed\nin more than one producing zone are counted as one well. As of March 31, 2026, we held an interest in approximately 8,100 gross (26.1\nnet) productive wells, including approximately 7,000 wells in which we held an overriding or royalty interest and 1,100 wells in which\nwe held a working interest.\n\n \n\n18\n\n \n\n \n\nA\ngross acre is an acre in which an interest is owned. A net acre is deemed to exist when the sum of fractional ownership interests in\ngross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres. The following table sets\nforth the approximate developed acreage in which we held a leasehold mineral or other interest as of March 31, 2026:\n\n \n\n  \nAcreage \n\n  \nGross  \nNet \n\nTexas \n 387,100  \n 1,497 \n\nNorth Dakota \n 68,600  \n 27 \n\nOklahoma \n 66,900  \n 800 \n\nLouisiana \n 55,600  \n 101 \n\nOhio \n 35,800  \n 4 \n\nWyoming \n 30,700  \n 15 \n\nNew Mexico \n 30,700  \n 182 \n\nColorado \n 10,300  \n 21 \n\nKansas \n 8,500  \n 41 \n\nMontana \n 7,200  \n 1 \n\nArkansas \n 1,600  \n 5 \n\nAlabama \n 1,000  \n 2 \n\nSouth Dakota \n 600  \n - \n\nVirginia \n 100  \n 1 \n\nTotal \n 704,700  \n 2,697 \n\n \n\nNet\nProduction, Unit Prices and Costs\n\n \n\nThe\nfollowing table summarizes our net oil and natural gas production, the average sales price per barrel (“bbl”) of oil and\nper thousand cubic feet (“mcf”) of natural gas produced, and the average production (lifting) cost per unit of production\nfor the years ended March 31:\n\n \n\n  \nYears\nEnded March 31, \n\n  \n2026  \n2025 \n\nOil (a): \n    \n   \n\nProduction\n(Bbls) \n 82,133  \n 83,564 \n\nRevenue \n$5,276,981  \n$6,145,674 \n\nAverage Bbls per day\n(d) \n 225  \n 229 \n\nAverage sales price\nper Bbl \n$64.25  \n$73.54 \n\nGas (b): \n    \n   \n\nProduction (Mcf) \n 681,794  \n 570,012 \n\nRevenue \n$1,271,067  \n$970,811 \n\nAverage Mcf per day\n(d) \n 1,868  \n 1,562 \n\nAverage sales price\nper Mcf \n$1.86  \n$1.70 \n\nTotal BOE (c) \n 195,765  \n 178,566 \n\nProduction costs: \n    \n   \n\nProduction expenses: \n$936,975  \n$1,043,202 \n\nProduction expenses\nper BOE \n$4.09  \n$5.84 \n\nProduction expenses\nper sales dollar \n$0.14  \n$0.15 \n\nProduction and ad valorem\ntaxes: \n$491,378  \n$561,894 \n\nProduction and ad valorem\ntaxes per BOE \n$2.14  \n$3.15 \n\nProduction and ad valorem\ntaxes per sales dollar \n$0.08  \n$0.08 \n\nTotal oil and gas revenue \n$6,548,048  \n$7,116,485 \n\n \n\n \n(a)\nIncludes condensate.\n\n \n(b)\nIncludes natural gas liquids.\n\n \n(c)\nNatural gas production is\nconverted to oil production at a ratio of six Mcf to one Bbl of oil.\n\n \n(d)\nCalculated on a 365-day year."}