EDGAR 10-K Filing

Company CIK: 66418
Filing Year: 2024
Filename: 66418_10-K_2024_0001493152-24-025472.json

---

ITEM 1. BUSINESS
ITEM 1. BUSINESS
General
Mexco Energy Corporation, a Colorado corporation, is an independent oil and gas company engaged in the acquisition, exploration, development and production of crude oil and natural gas properties located in the United States. Incorporated in April 1972 under the name Miller Oil Company, the Company changed its name to Mexco Energy Corporation effective April 30, 1980. At that time, the shareholders of the Company also approved amendments to the Articles of Incorporation resulting in a one-for-fifty reverse stock split of the Company’s common stock.
Our total estimated proved reserves at March 31, 2024 were approximately 1.547 million barrels of oil equivalent (“MMBOE”) of which 51% was oil and natural gas liquids and 49% was natural gas, and our estimated present value of proved reserves was approximately $29 million based on estimated future net revenues excluding taxes discounted at 10% per annum, pricing and other assumptions set forth in “Item 2 - Properties” below.
Nicholas C. Taylor beneficially owns approximately 45% of the outstanding shares of our common stock. Mr. Taylor is also our Chairman of the Board and Chief Executive Officer. As a result, Mr. Taylor has significant influence in matters voted on by our shareholders, including the election of our Board members. Mr. Taylor participates in all facets of our business and has a significant impact on both our business strategy and daily operations.
Company Profile
Since our inception, we have been engaged in acquiring and developing oil and gas properties and the exploration for and production of natural gas, crude oil, condensate and natural gas liquids (“NGLs”) within the United States. We especially seek to acquire proved reserves that fit well with existing operations or in areas where Mexco has established production. Acquisitions preferably will contain most of their value in producing wells, behind pipe reserves and high quality proved undeveloped locations. Competition for the purchase of proved reserves is intense. Sellers often utilize a bid process to sell properties. This process usually intensifies the competition and makes it extremely difficult to acquire reserves without assuming significant price and production risks. We actively search for opportunities to acquire proved oil and gas properties. However, because the competition is intense, we cannot give any assurance that we will be successful in our efforts during fiscal 2025.
While we own oil and gas properties in other states, the majority of our activities are centered in West Texas and Southeastern New Mexico. The Company also owns producing properties and undeveloped acreage in fourteen states. We acquire interests in producing and non-producing oil and gas leases from landowners and leaseholders in areas considered favorable for oil and gas exploration, development and production. In addition, we may acquire oil and gas interests by joining in oil and gas drilling prospects generated by third parties. We may also employ a combination of the above methods of obtaining producing acreage and prospects. In recent years, we have placed primary emphasis on the evaluation and purchase of producing oil and gas properties, including working, royalty and mineral interests, and prospects that could have a potentially meaningful impact on our reserves. All of the Company’s oil and gas interests are operated by others.
From 1983 to 2024, Mexco Energy Corporation made numerous acquisitions of royalties, overriding royalties, minerals and working interests in producing oil and gas properties including the following most significant acquisitions:
1990-1994 Royalty interests, aggregate purchase price of approximately $501,000 covering multiple wells in the Gomez (Ellenberger) Field of Pecos County, Texas.
1993-2014 Tabbs Bay Oil Company and Thompson Brothers Lumber Company, respectively dissolved in 1957 and 1947. Purchase covering thousands of acres located respectively in 19 counties of Texas, 3 parishes of Louisiana and one county in Arkansas and 8 counties of Texas, respectively consisting of various mineral, royalty and overriding royalty interests.
Forman Energy Corporation, purchase price of $1,591,000 consisting primarily of working interests in approximately 634 wells located in 12 states.
Royalty interests, purchase price $304,000 covering 37 producing wells in the Cotton Valley formation in Limestone County, Texas and the Lower Cotton Valley formation in Jackson Parish, Louisiana. This acreage also contains additional potential undrilled locations.
Royalty interests, purchase price $500,000 covering 4 producing gas units in Freestone County, Texas containing 33 producing wells and additional potential undeveloped locations in the Cotton Valley formation.
Royalty interests, purchase price $550,000 covering 75 producing wells and additional potential undeveloped locations in the Cotton Valley formation of Freestone and Limestone Counties, Texas.
Non-operated working interests, purchase price $425,000 covering 2 properties in Lea County, New Mexico.
Royalty (mineral) acreage, purchase price $1,850,000 covering 122 mineral acres in the Newark East (Barnett Shale) Field of Tarrant County, Texas amounting to approximately 21.45% royalty interest.
Royalty (mineral) acreage, purchase price $429,000 covering 522 mineral acres in the Newark East (Barnett Shale) Field of Tarrant County, Texas containing 6 producing natural gas wells and additional potential undeveloped well locations. In March 2009, purchased additional interests, $49,000.
Southwest Texas Disposal Corporation, purchase price $478,000 consisting of royalty interests in over 300 wells located in 60 counties and parishes of 6 states.
Overriding royalty interests, purchase price $1,650,000 covering 5,120 gross acres over 8 sections in the Haynesville trend area of DeSoto Parish, Louisiana containing 6 horizontal producing wells and additional potential undeveloped drill sites. The Company paid $1.46 million in cash and the remainder was paid as 26,833 shares of its common stock issued from treasury shares.
Non-operating working interests, purchase price $670,000 covering 160 gross acres in the Fuhrman-Mascho Field of Andrews County, Texas containing 5 producing wells in the Grayburg and San Andres formations and additional potential drill sites. In March 2012, purchased additional working interests, $275,000.
TBO Oil and Gas, LLC, purchase price of $1,150,000 consisting of working interests in approximately 280 wells located in 16 counties of 3 states.
Royalty interests, purchase price $200,000 covering 43 wells in 12 counties of 8 states, primarily in Texas.
Royalty interests, purchase price $580,000 covering 580 wells in 87 counties of 8 states. Approximately 90% of the net revenue from these royalties is produced by 157 wells located in the Barnett Shale of the Fort Worth Basin of Texas.
Royalty and mineral interests, purchase price $1,000,000 covering approximately 1,800 wells in 27 counties of Texas. Of these oil and gas reserves, approximately 60% is natural gas and 40% oil.
Non-Operated working interests, purchase price $840,000 in 70 Natural gas producing wells located in 5 counties of Oklahoma.
Non-Operated working interests, purchase price $200,000 covering 80 wells located in Hockley and Pecos Counties, Texas.
Non-Operated working interests, purchase price $450,000 covering 43 wells in Webster Parish, Louisiana; Eddy County, New Mexico; and, Nolan and Smith Counties, Texas.
Royalty interest investment, $300,000 for a less than 1% investment commitment in a limited liability company, capitalized at approximately $50 million to purchase royalty interests consisting of minerals located in the Marcellus and Utica areas of Ohio. This LLC has returned $276,098 and 92% of the total investment since inception in fiscal 2020.
2022-2023 Overriding royalty interests, purchase price of $567,000 covering 53 producing wells and several additional potential locations for development in Atascosa and Karnes Counties, Texas.
Royalty interests, purchase price of $939,000 covering 22 producing wells and several additional potential locations for development in the Eagleford area of Dimmit County, Texas.
Royalty interest investment, $2,000,000 for an approximate 2% investment commitment in a limited liability company, capitalized at approximately $100 million to purchase royalty interests consisting of minerals located in the Marcellus and Utica areas of Ohio. As of the date of this report, $1,000,000 of the commitment has been expended.
Royalty interests, purchase price of $117,200 covering 28 producing wells in 6 counties in the Haynesville trend area of Louisiana and 5 counties in Texas.
2023-2024 Royalty interests, purchase price of $455,000 covering 8 producing wells and additional potential locations for development in Reeves County, Texas.
Royalty interests, purchase price of $367,500 covering 84 producing wells and additional potential locations for development in 6 counties in Texas.
Royalty interest, purchase price of $575,600 covering 9 producing wells with additional potential locations for development and 4 producing wellbores in Weld County, Colorado.
Royalty interests, purchase price of $390,300 covering 255 producing wells in the Haynesville trend area of Caddo Parish, Louisiana.
Industry Environment and Outlook
The commodity price environment was challenging in fiscal 2024. The war in Ukraine and the Israel-Hamas war, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession and measures to combat persistent inflation and instability in the financial sector have contributed to recent economic and pricing volatility and may continue to impact pricing throughout fiscal 2025. In light of these challenges facing our industry and in response to the continued challenging environment, our primary business strategies for fiscal 2025 will continue to include: (1) optimizing cash flows through operating efficiencies and cost reductions, (2) divesting of non-core assets, and (3) working to balance capital spending with cash flows to minimize borrowings and maintain ample liquidity.
See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for discussion of our fiscal 2024 operating results and potential impact on fiscal 2025 operating results due to commodity price changes.
Oil and Gas Operations
As of March 31, 2024, oil constituted approximately 83% of our oil and natural gas sales and approximately 51% of our total proved reserves volumes for fiscal 2024. Revenues from oil and gas royalty interests accounted for approximately 28% of our total operating revenues for fiscal 2024.
There are two primary areas in which the Company is focused, 1) the Delaware Basin located in the Western portion of the Permian Basin including Lea and Eddy Counties, New Mexico and Reeves and Loving Counties, Texas and 2) the Midland Basin located in the Eastern portion of the Permian Basin including Reagan, Upton, Midland, Martin, Howard and Glasscock Counties, Texas. The Permian Basin in total accounts for 85% of our discounted future net cash flows from proved reserves and 87% of our gross revenues.
The Permian Basin is one of the oldest and most prolific producing basins in North America which has been a significant source of oil production since the 1920s. The Permian Basin is known to have a number of zones of oil and natural gas bearing rock throughout.
The Delaware Basin properties, encompassing 39,112 gross acres, 213 net acres, 742 gross producing wells or 4 net wells account for approximately 70% of our discounted future net cash flows from proved reserves as of March 31, 2024. For fiscal 2024, these properties accounted for 62% of our gross revenues. Of these discounted future net cash flows from proved reserves, approximately 29% are attributable to proven undeveloped reserves which would be developed through new drilling.
The Midland Basin properties, encompassing 115,030 gross acres, 249 net acres, 1,731 gross producing wells or 5 net wells account for approximately 13% of our discounted future net cash flows from proved reserves as of March 31, 2024. For fiscal 2024, these properties accounted for 23% of our gross revenues. Of these discounted future net cash flows from proved reserves, approximately 5% are attributable to proven undeveloped reserves which would be developed through new drilling.
Mexco believes its most important properties for future development by horizontal drilling and hydraulic fracturing area are located in Lea and Eddy Counties, New Mexico of the Delaware Basin and the Midland Basin in Midland, Reagan and Upton Counties, Texas.
For more on these and other operations in this area see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources Commitments”.
We own partial interests in approximately 6,800 producing wells all of which are located within the United States in the states of Texas, New Mexico, Oklahoma, Louisiana, Alabama, Mississippi, Arkansas, Wyoming, Kansas, Colorado, Montana, Virginia, North Dakota, and Ohio. Additional information concerning these properties and our oil and gas reserves is provided below.
The following table indicates our oil and gas production in each of the last five years:
Year Oil(Bbls) Gas (Mcf)
69,999 502,879
73,968 534,363
61,689 393,841
50,327 324,205
44,301 294,007
Competition and Markets
The oil and gas industry is a highly competitive business. Competition for oil and gas reserve acquisitions is significant. We may compete with major oil and gas companies, other independent oil and gas companies and individual producers and operators, some of which have financial and personnel resources substantially in excess of those available to us. As a result, we may be placed at a competitive disadvantage. Competitive factors include price, contract terms and types and quality of service, including pipeline distribution. The price for oil and gas is widely followed and is generally subject to worldwide market factors. Our ability to acquire and develop additional properties in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment in a timely manner.
In addition, the oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources could adversely affect our revenue.
Market factors affect the quantities of oil and natural gas production and the price we can obtain for the production from our oil and natural gas properties. Such factors include: the extent of domestic production; the level of imports of foreign oil and natural gas; the general level of market demand on a regional, national and worldwide basis; domestic and foreign economic conditions that determine levels of industrial production; political events in foreign oil-producing regions; and variations in governmental regulations including environmental, energy conservation and tax laws or the imposition of new regulatory requirements upon the oil and natural gas industry.
The market for our oil, gas and natural gas liquids production depends on factors beyond our control including: domestic and foreign political conditions; the overall level of supply of and demand for oil, gas and natural gas liquids; the price of imports of oil and gas; weather conditions; the price and availability of alternative fuels; the proximity and capacity of gas pipelines and other transportation facilities; and overall economic conditions.
Major Customers
We made sales that amounted to 10% or more of operating revenues as follows for the years ended March 31:
Company A 59 % 53 %
Historically, the Company has not experienced significant credit losses on our oil and gas accounts and management is of the opinion that significant credit risk does not exist. Because a ready market exists for oil and gas production, we do not believe the loss of any individual purchaser would have a material adverse effect on our financial position or results of operations.
Environmental Regulation
The oil and gas industry is extensively regulated at the federal, state, and local levels. Regulations affecting elements of the energy sector are under constant review for amendment or expansion and frequently more stringent requirements are imposed. Various federal and state agencies, including the Texas Railroad Commission, the Bureau of Land Management (the “BLM”), an agency of the U.S Department of the Interior (“DOI”), the Federal Energy Regulatory Commission (“FERC”), the U.S. Environmental Protection Agency (the “EPA”), the Department of Transportation (“DOT”) and the U.S. Occupational Safety and Health Administration (“OSHA”), have legal and regulatory authority and oversight over the operations on the properties in which the Company owns an interest.
Under certain environmental laws and regulations, the operators of the Company properties could be subject to strict, joint and several liability for the removal or remediation of property contamination, whether at a drill site or a waste disposal facility, even when the operators did not cause the contamination or their activities were in compliance with all applicable laws at the time the actions were taken. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund” law, for example, imposes liability, regardless of fault or the legality of the original conduct, on certain classes of persons for releases into the environment of a “hazardous substance.” Liable persons may include the current or previous owner and operator of a site where a hazardous substance has been disposed and persons who arranged for the disposal of a hazardous substance at a site. Under CERCLA and similar statutes, government authorities or private parties may take actions in response to threats to the public health or the environment or sue responsible persons for the associated costs. In the course of operations, the working interest owner and/or the operator of the Company properties may have generated and may generate materials that could trigger cleanup liabilities. In addition, the Company properties have produced oil and/or natural gas for many years, and previous operators may have disposed or released hydrocarbons, wastes or hazardous substances at the Company properties. The operator of the Company properties or the working interest owners may be responsible for all or part of the costs to clean up any such contamination. Although the Company is not the operator of such properties, its ownership of the properties could cause it to be responsible for all or part of such costs to the extent CERCLA or any similar statute imposes responsibility on such parties as “owners.”
Various state governments and regional organizations comprising state governments already have enacted legislation and promulgated rules restricting greenhouse gases (“GHGs”) emissions or promoting the use of renewable energy, and additional such measures are frequently under consideration. Although it is not possible at this time to estimate how potential future requirements addressing GHG emissions would impact operations on the Company properties and revenue, either directly or indirectly, any future federal, state or local laws or implementing regulations that may be adopted to address GHG emissions could require the operators of our properties to incur new or increased costs to obtain permits, operate and maintain equipment and facilities, install new emission controls, acquire allowances to authorize GHG emissions, pay taxes related to GHG emissions or administer a GHG emissions program. Regulation of GHGs could also result in a reduction in demand for and production of oil and natural gas. Additionally, to the extent that unfavorable weather conditions are exacerbated by global climate change or otherwise, the Company properties may be adversely affected to a greater degree than previously experienced.
We did not incur any material capital expenditures for remediation or pollution control activities for the year ended March 31, 2024. Additionally, as of the date of this report, we are not aware of any environmental issues or claims that will require material capital expenditures during fiscal 2025.
Other Regulation
Other agencies with certain authority over the Company’s business include the Internal Revenue Service (the “IRS”), the SEC and NYSE. Ensuring compliance with the rules, regulations and orders promulgated by such entities requires extensive effort and incremental costs to comply, which affects the Company’s profitability. Because public policy changes are commonplace, and existing laws and regulations are frequently amended, the Company is unable to predict the future cost or impact of compliance. However, the Company does not expect that any of these laws and regulations will affect its operations materially differently than they would affect other companies with similar operations, size and financial strength.
Title to Properties
The leasehold properties we own are subject to royalty, overriding royalty and other outstanding interests customary in the industry. The properties may be subject to burdens such as liens incident to operating agreements and current taxes, development obligations under oil and gas leases and other encumbrances, easements and restrictions. We do not believe any of these burdens will materially interfere with the use of these properties.
Prior to drilling of an oil and natural gas well, it is normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our operators’ failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest. We believe the title to our properties is good and defensible in accordance with standards generally acceptable in the oil and gas industry subject to such exceptions that, in the opinion of counsel employed in the various areas in which we have activities, are not so material as to detract substantially from the use of such properties.
Substantially all of our properties are currently mortgaged under a deed of trust to secure funding through a credit facility.
Insurance
Our operations are subject to all the risks inherent in the exploration for and development and production of oil and gas including blowouts, fires and other casualties. We maintain insurance coverage customary for operations of a similar nature, but losses could arise from uninsured risks or in amounts in excess of existing insurance coverage.
Executive Officers
The following table sets forth certain information concerning the executive officers of the Company as of March 31, 2024.
Name
Age
Position
Nicholas C. Taylor
Chairman and Chief Executive Officer
Tamala L. McComic
President, Chief Financial Officer, Treasurer, and Assistant Secretary
Donna Gail Yanko
Vice President
Stacy D. Hardin
Secretary and Assistant Treasurer
Set forth below is a description of the principal occupations during at least the past five years of each executive officer of the Company.
Nicholas C. Taylor was elected Chairman of the Board and Chief Executive Officer of the Company in September 2011 and continues to serve in such capacity on a part time basis, as required. He served as Chief Executive Officer, President and Director of the Company from 1983 to 2011. From July 1993 to the present, Mr. Taylor has been involved in the independent practice of law and other business activities. In November 2005 he was appointed by the Speaker of the House to the Texas Ethics Commission and served until February 2010.
Tamala L. McComic, a Certified Public Accountant and Chartered Global Management Accountant, became Controller for the Company in July 2001 and was elected President and Chief Financial Officer in September 2011. She served the Company as Executive Vice President and Chief Financial Officer from 2009 to 2011 and Vice President and Chief Financial Officer from 2003 to 2009. Prior thereto, Ms. McComic served as Treasurer and Assistant Secretary of the Company.
Donna Gail Yanko was appointed to the position of Vice President of the Company in 1990. She also served as Corporate Secretary from 1992 to 2021 and from 1986 to 1992 was Assistant Secretary. From 1986 to 2015, on a part-time basis, she assisted the Chairman of the Board of the Company in his personal business activities. Ms. Yanko also served as a director of the Company from 1990 to 2008.
Stacy D. Hardin joined the Company in 2006 and was elected Corporate Secretary of the Company in September 2021. She has also served the Company as Assistant Treasurer of the Company since 2010 and from 2006 to 2021 was Assistant Secretary. Prior thereto, Ms. Hardin served as Assistant Controller.
Employees
As of March 31, 2024, we had three full-time and three part-time employees. We believe that relations with these employees are generally satisfactory. From time to time, we utilize the services of independent geological, land and engineering consultants on a limited basis and expect to continue to do so in the future.
Office Facilities
Our principal offices are located at 415 W. Wall, Suite 475, Midland, Texas 79701 and our telephone number is (432) 682-1119. We believe our facilities are adequate for our current operations and future needs.
Access to Company Reports
Mexco Energy Corporation files annual, quarterly and current reports, proxy statements and other information with the SEC. The SEC maintains an internet website (www.sec.gov) that contains annual, quarterly and current reports, proxy statements and other information that issuers, including Mexco, file electronically with the SEC.
We also maintain an internet website at www.mexcoenergy.com. In the Investor Relations section, our website contains our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other reports and amendments to those reports as soon as reasonably practicable after such material is electronically filed with the SEC. Information on our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. Additionally, our Code of Business Conduct and Ethics and the charters of our Audit Committee, Compensation Committee and Nominating Committee are posted on our website. Any of these corporate documents as well as any of the SEC filed reports are available in print free of charge to any stockholder who requests them. Requests should be directed to our Corporate Secretary by mail to P.O. Box 10502, Midland, Texas 79702 or by email to mexco@sbcglobal.net.

---

ITEM 1A. RISK FACTORS
ITEM 1A.
RISK FACTORS
The Company is subject to various risks and uncertainties in the ordinary course of business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. We could also face additional risks and uncertainties not currently known to us or that we currently deem to be immaterial. If any of these risks actually occurs, it could materially harm our business, financial condition or results of operations and the trading price of our shares could decline. Investors should carefully consider each of the following risk factors and all of the other information set forth in this Annual Report on Form 10-K.
RISKS RELATED TO OUR BUSINESS AND INDUSTRY
Volatility of oil and gas prices significantly affects our results and profitability.
Prices for oil and natural gas fluctuate widely. We cannot predict future oil and natural gas prices with any certainty. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile. Factors that can cause price fluctuations include the level of global demand for petroleum products; foreign supply and pricing of oil and gas; the actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls; nature and extent of governmental regulation and taxation, including environmental regulations; level of domestic and international exploration, drilling and production activity; the cost of exploring for, producing and delivering oil and gas; speculative trading in crude oil and natural gas derivative contracts; availability, proximity and capacity of oil and gas pipelines and other transportation facilities; weather conditions; the price and availability of alternative fuels; technological advances affecting energy consumption; national and international pandemics; and, overall political and economic conditions in oil producing countries.
Increases and decreases in prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow from banks may be subject to redetermination based on changes in prices. In addition, we may have ceiling test writedowns when prices decline. Lower prices may also reduce the amount of crude oil and natural gas that can be produced economically. Thus, we may experience material increases or decreases in reserve quantities solely as a result of price changes and not as a result of drilling or well performance.
Changes in oil and gas prices impact both estimated future net revenue and the estimated quantity of proved reserves. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our credit facility and adversely affect the amount of cash flow available for capital expenditures and our ability to obtain additional capital for our exploration and development activities.
Oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. Lower prices or lack of storage may have an adverse affect on our financial condition due to reduction of our revenues, operating income and cash flows; curtailment or shut-in of our production due to lack of transportation or storage capacity; cause certain properties in our portfolio to become economically unviable; and, limit our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations.
Our results of operations may be negatively impacted by current global events.
The United States and certain countries in Europe and Asia are facing economic struggles or slowing economic growth. If these conditions worsen, combined with a decline in economic growth in other parts of the world, there could be a significant adverse effect on global financial markets and commodity prices. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. Global or national health concerns may adversely affect the Company by (i) reducing demand for its oil, NGLs and gas because of reduced global or national economic activity, (ii) impairing its supply chain (for example, by limiting manufacturing of materials used in operations) and (iii) affecting the health of its workforce, rendering employees unable to work or travel. Deteriorating economic climate in the United States or abroad due to inflation, rising interest rates or otherwise, demand for petroleum products could diminish or stagnate, which could depress the prices at which the Company could sell its oil, NGLs and gas, affect the ability of the Company’s vendors, suppliers and customers to continue operations and ultimately decrease the Company’s cash flows and profitability. In addition, reduced worldwide demand for debt and equity securities issued by oil and gas companies may make it more difficult for the Company to raise capital to fund its operations or refinance its debt obligations.
Changes in environmental laws could increase our operators’ costs and adversely impact our business, financial condition and cash flows.
President Biden has indicated that he is supportive of, and has issued executive orders promoting various programs and initiatives designed to, among other things, curtail climate change, control the release of methane from new and existing oil and natural gas operations, and decarbonize electric generation and the transportation sector. In recent years the U.S. Congress has considered legislation to reduce emissions of GHGs, including methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas. For example, the Inflation Reduction Act of 2022 (the “IRA”), which appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a fee on GHG emissions from certain facilities, was signed into law in August 2022. The emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations.
Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates elected to public office. President Biden has issued several executive orders focused on addressing climate change, including items that may impact costs to produce, or demand for, oil and gas.
Lower oil and gas prices and other factors may cause us to record ceiling test writedowns.
Lower oil and gas prices increase the risk of ceiling limitation write-downs. We use the full cost method to account for oil and gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop crude oil and natural gas properties including the cost of abandoned properties, dry holes, geophysical costs and annual lease rentals. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded. Depletion of evaluated oil and natural gas properties is computed in the units of production method, whereby capitalized costs are amortized over total proved reserves. Under the full cost accounting rules, the net capitalized cost of crude oil and natural gas properties may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10% plus the lower of cost or fair market value of unproved properties. If net capitalized costs of oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess against earnings. This is called a “ceiling test writedown.” We use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net reserves. Under the accounting rules, we are required to perform a ceiling test each quarter. A ceiling test writedown does not impact cash flow from operating activities, but does reduce stockholders’ equity and earnings. The risk that we will be required to write down the carrying value of oil and natural gas properties increases when oil and natural gas prices are low. There were no ceiling test impairments on our oil and gas properties during fiscal 2024 and 2023.
We must replace reserves we produce.
Our future success depends upon our ability to find, develop or acquire additional, economically recoverable oil and gas reserves. Our proved reserves will generally decline as reserves are depleted, except to the extent that we can find, develop or acquire replacement reserves. One offset to the obvious benefits afforded by higher product prices especially for small to mid-cap companies in this industry, is that quality domestic oil and gas reserves are hard to find.
Approximately 33% and 26% of our total estimated net proved reserves at March 31, 2024 and 2023, respectively, were undeveloped, and those reserves may not ultimately be developed.
Recovery of undeveloped reserves requires significant capital expenditures and successful drilling. Our reserve data assumes that we can and will make these expenditures and conduct these operations successfully. These assumptions, however, may not prove correct. Delays in the development of our reserves, increases in costs to develop such reserves, or decreases in commodity prices will reduce the future net revenues or our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, if we or the outside operators of our properties choose not to spend the capital to develop these reserves, or if we are not able to successfully develop these reserves, we will be required to write-off these reserves. Any such write-offs of our reserves could reduce our ability to borrow money and could reduce the value of our common stock.
Information concerning our reserves and future net revenues estimates is inherently uncertain.
Estimates of oil and gas reserves, by necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, such as future production, oil and gas prices, operating costs, development costs and remedial costs, all of which may vary considerably from actual results. As a result, estimates of the economically recoverable quantities of oil and gas and of future net cash flows expected therefrom may vary substantially. As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on a twelve month un-weighted first-day-of-the-month average oil and gas prices for the twelve months prior to the date of the report. Actual future prices and costs may be materially higher or lower.
An increase in the differential between NYMEX and the reference or regional index price used to price our oil and gas would reduce our cash flow from operations.
Our oil and gas is priced in the local markets where it is produced based on local or regional supply and demand factors. The prices we receive for our oil and gas are typically lower than the relevant benchmark prices, such as The New York Mercantile Exchange (“NYMEX”). The difference between the benchmark price and the price we receive is called a differential. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, upsets in the midstream or downstream sectors of the industry, trade restrictions and governmental regulations. Additionally, insufficient pipeline capacity, lack of demand in any given operating area or other factors may cause the differential to increase in a particular area compared with other producing areas. During fiscal 2024, differentials averaged $2.68 per Bbl of oil and ($0.15) per Mcf of gas. Increases in the differential between the benchmark prices for oil and gas and the wellhead price we receive could significantly reduce our revenues and our cash flow from operations.
Drilling and operating activities are high risk activities that subject us to a variety of factors that we cannot control.
These factors include availability of workover and drilling rigs, well blowouts, cratering, explosions, fires, formations with abnormal pressures, pollution, releases of toxic gases and other environmental hazards and risks. Any of these operating hazards could result in substantial losses to us. In addition, we incur the risk that no commercially productive reservoirs will be encountered, and there is no assurance that we will recover all or any portion of our investment in wells drilled or re-entered.
We may not be able to fund the capital expenditures that will be required for us to increase reserves and production.
We must make capital expenditures to develop our existing reserves and to acquire new reserves. Historically, we have used our cash flow from operations and borrowings under our credit facility to fund our capital expenditures, however, lower oil and gas prices may prevent these options. Volatility in oil and gas prices, the timing of our drilling programs and drilling results will affect our cash flow from operations. Lower prices and/or lower production will also decrease revenues and cash flow, thus reducing the amount of financial resources available to meet our capital requirements, including reducing the amount available to pursue our drilling opportunities.
The borrowing base under our credit facility will be determined from time to time by the lender. Reductions in estimates of oil and gas reserves could result in a reduction in the borrowing base, which would reduce the amount of financial resources available under the credit facility to meet our capital requirements. Such a reduction could be the result of lower commodity prices and/or production, inability to drill or unfavorable drilling results, changes in oil and gas reserve engineering, the lender’s inability to agree to an adequate borrowing base or adverse changes in the lender’s practices regarding estimation of reserves. If cash flow from operations or our borrowing base decrease for any reason, our ability to undertake exploration and development activities could be adversely affected. As a result, our ability to replace production may be limited.
Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
Our management and outside operators have specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling in these projects. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations.
Our business depends on oil and natural gas transportation facilities which are owned by others.
The marketability of our production depends in part on the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions could all affect our ability to produce and market our oil and gas.
We own non-operating interests in properties developed and operated by third parties and, as a result, we are unable to control the operation and profitability of such properties.
We participate in the drilling and completion of wells with third-party operators that exercise exclusive control over such operations. As a participant, we rely on third-party operators to successfully operate these properties pursuant to joint operating agreements and other similar contractual arrangements. As a participant in these operations, we may not be able to maximize the value associated with these properties in the manner we believe appropriate, or at all. For example, we cannot control the success of drilling and development activities on properties operated by third-parties, which depend on a number of factors under the control of a third-party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology. In addition, the third-party operator’s operational expertise and financial resources and its ability to gain the approval of other participants in drilling wells will impact the timing and potential success of drilling and development activites in a manner that we are unable to control. A third-party operator’s failure to adequately perform operations, breach of the applicable agreements or failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our financial condition and results of operations.
Acquiring reserves in the oil and gas industry is highly competitive.
Competition for oil and gas reserve acquisitions is significant. We may compete with major oil and gas companies, other independent oil and gas companies and individual producers and operators, some of which have financial and personnel resources substantially in excess of those available to us. As a result, we may be placed at a competitive disadvantage. Our ability to acquire and develop additional properties in the future will depend upon our ability to select and acquire suitable producing properties and prospects for future development activities.
We may not be insured against all of the operating hazards to which our business is exposed.
Our operations are subject to all the risks inherent in the exploration for, and development and production of oil and gas including blowouts, fires and other casualties. We maintain insurance coverage customary for operations of a similar nature, but losses could arise from uninsured risks or in amounts in excess of existing insurance coverage.
Our effective tax rate may change in the future, which could adversely impact us.
The Tax Cuts and Jobs Act of 2017 (“TCJA”) significantly changed the U.S. federal income taxation of U.S. corporations, including by reducing the U.S. corporate tax rate, limiting interest deductions and certain deductions for executive compensation, permitting immediate expensing of certain capital expenditures, and revising the rules governing net operating losses. The TCJA remains unclear in some respects and continues to be subject to potential amendments and technical corrections. The U.S. Treasury Department and the IRS have issued significant guidance since the TCJA was enacted, interpreting the TCJA and clarifying some the uncertainties, and are continuing to issue new guidance. There are still significant aspects of the TCJA for which further guidance is expected, and both the timing and contents of any such future guidance are uncertain.
Further, changes to the U.S. federal income tax laws are proposed regularly and there can be no assurance that, if enacted, any such changes would not have an adverse impact on us. For example, President Biden has suggested the reversal or modification of some portions of the TCJA and certain of these proposals, if enacted, could increase our effective tax rate. There can be no assurance that any such proposed changes will be introduced as legislation or, if introduced, later enacted and, if enacted, what form such enacted legislation would take. Such changes could potentially have retroactive effect. In light of these factors, there can be no assurance that our effective tax rate will not change in future periods. If the effective tax rates were to increase as a result of the future legislation, our business could be adversely affected.
Our reliance on information technology, including those hosted by third parties, exposes us to cyber security risks that could affect our business, financial condition or reputation.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities, including digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate energy assets might be specific targets of cyber security threats. Our and our operators’ technologies, systems, networks, and those of vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business activities. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.
The loss of our chief executive officer or president could adversely impact our ability to execute our business strategy.
We depend, and will continue to depend in the foreseeable future, upon the continued services of our Chief Executive Officer, Nicholas C. Taylor and our President and Chief Financial Officer, Tamala L. McComic, who have extensive experience and expertise in evaluating and analyzing producing oil and gas properties and drilling prospects, maximizing production from oil and gas properties and developing and executing acquisitions and financing. As of March 31, 2024, we do not have key-man insurance on the lives of Mr. Taylor and Ms. McComic. The unexpected loss of the services of one or more of these individuals could, therefore, significantly and adversely affect our operations.
We may be affected by one substantial shareholder.
Nicholas C. Taylor beneficially owns approximately 45% of the outstanding shares of our common stock. Mr. Taylor is also our Chairman of the Board and Chief Executive Officer. As a result, Mr. Taylor has significant influence in matters voted on by our shareholders, including the election of our Board members. Mr. Taylor participates in all facets of our business and has a significant impact on both our business strategy and daily operations. The retirement, incapacity or death of Mr. Taylor, or any change in the power to vote shares beneficially owned by Mr. Taylor, could result in negative market or industry perception and could have an adverse effect on our business.
RISKS RELATED TO OUR COMMON STOCK
We may issue additional shares of common stock in the future, which could cause dilution to all shareholders.
We may seek to raise additional equity capital in the future. Any issuance of additional shares of our common stock will dilute the percentage ownership interest of all shareholders and may dilute the book value per share of our common stock.
Control by our executive officers and directors may limit your ability to influence the outcome of matters requiring stockholder approval and could discourage our potential acquisition by third parties.
As of March 31, 2024, our executive officers and directors beneficially owned approximately 48% of our common stock. These stockholders, if acting together, would be able to influence significantly all matters requiring approval by our stockholders, including the election of our board of directors and the approval of mergers or other business combination transactions.
The price of our common stock has been volatile and could continue to fluctuate substantially.
Mexco common stock is traded on the New York Stock Exchange’s NYSE American. The market price of our common stock has and could continue to experience volatility due to reasons unrelated to our operating performance. These reasons include: supply and demand for oil and natural gas; political conditions in oil and natural gas producing regions; demand for our common stock and limited trading volume; investor perception of our industry; fluctuations in commodity prices; variations in our results of operations; legislative or regulatory changes; general trends in the oil and natural gas industry; market conditions and analysts’ estimates; and, other events in the oil and gas industry.
Many of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. We cannot assure you that the market price of our common stock will not fluctuate or decline significantly in the future. In addition, the stock markets in general can experience considerable price and volume fluctuations.

---

ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None.

---

ITEM 2. PROPERTIES
ITEM 2.
PROPERTIES
Our properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped. As of March 31, 2024, we had interests in approximately 6,800 gross (25.7 net) producing oil and gas wells and owned leasehold mineral, royalty and other interests in approximately 579,000 gross (2,709 net) acres.
Oil and Natural Gas Reserves
In accordance with current SEC rules, the average prices used in computing reserves at March 31, 2024 were $76.88 per bbl of oil compared to $92.02 in 2023, a decrease of 16%, and $2.75 per mcf of natural gas compared to $5.68 in 2023, a decrease of 52%, such prices are based on the 12-month unweighted arithmetic average market prices for sales of oil and natural gas on the first calendar day of each month during fiscal 2024. The benchmark price of $73.96 per bbl of oil at March 31, 2024 versus $87.45 at March 31, 2023, was adjusted by lease for gravity, transportation fees and market differentials and did not give effect to derivative transactions. The benchmark price of $2.45 per mcf of natural gas at March 31, 2024 versus $5.96 at March 31, 2023, was adjusted by lease for BTU content, transportation fees and market differentials.
For information concerning our costs incurred for oil and gas operations, net revenues from oil and gas production, estimated future net revenues attributable to our oil and gas reserves, present value of future net revenues discounted at 10% and changes therein, see Notes to the Company’s consolidated financial statements.
Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.
The engineering report with respect to Mexco’s estimates of proved oil and gas reserves as of March 31, 2024 and 2023 is based on evaluations prepared by Russell K. Hall and Associates, Inc. Environmental Engineering Consultants, based in Midland, Texas (“Hall and Associates”), a summary of which is filed as Exhibit 99.1 to this annual report.
Management maintains internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported in accordance with rules and regulations provided by the SEC. As stated above, Mexco retained Hall and Associates to prepare estimates of our oil and gas reserves. Management works closely with this firm, and is responsible for providing accurate operating and technical data to it. Our Chief Financial Officer who has over 26 years experience in the oil and gas industry reviews the final reserves estimate and consults with a degreed geological consultant with extensive geological experience and if necessary, discusses the process used and findings with Alan Neal, the technical person at Hall and Associates responsible for evaluating the proved reserves covered by this report. Mr. Neal is a member of the Society of Petroleum Engineers and has over 36 years of experience in the oil and gas industry. Our Chairman and Chief Executive Officer who has over 46 years of experience in the oil and gas industry also reviews the final reserves estimate.
Numerous uncertainties exist in estimating quantities of proved reserves. Reserve estimates are imprecise and subjective and may change at any time as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates. Any significant variance could materially affect the estimated quantities and value of our oil and gas reserves, which in turn may adversely affect our cash flow, results of operations and the availability of capital resources.
Per the current SEC rules, the prices used to calculate our proved reserves and the present value of proved reserves set forth herein are made using the 12-month unweighted arithmetic average of the first-day-of-the-month price. All prices are held constant throughout the life of the properties. Actual future prices and costs may be materially higher or lower than those as of the date of the estimate. The timing of both the production and the expenses with respect to the development and production of oil and gas properties will affect the timing of future net cash flows from proved reserves and their present value. Except to the extent that we acquire additional properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced.
Our estimated proved oil and gas reserves and present value of estimated future net revenues from proved oil and gas reserves in the periods ended March 31 are summarized below.
PROVED RESERVES
March 31,
Oil (Bbls):
Proved developed - Producing 394,000 451,000
Proved developed - Non-producing 50,620 35,770
Proved undeveloped 346,330 240,060
Total 790,950 726,830
Natural gas (Mcf):
Proved developed - Producing 3,346,460 3,826,370
Proved developed - Non-producing 219,780 145,000
Proved undeveloped 970,880 978,010
Total 4,537,120 4,949,380
Total net proved reserves (BOE) (1) 1,547,127 1,551,725
PV-10 Value (2) $ 29,078,000 $ 39,473,000
Present value of future income tax discounted at 10% (4,450,000 ) (6,658,000 )
Standardized measure of discounted future net cash flows (3) $ 24,628,000 $ 32,815,000
Prices used in Calculating Reserves: (4)
Natural gas (per Mcf) $ 2.75 $ 5.68
Oil (per Bbl) $ 76.88 $ 92.02
(1) These reserve estimates do not include the Company’s interest in two LLCs referred to in Item 1. Business - Company Profile on page 4 hereto. The first LLC has returned $276,098 and 92% of the total investment since inception in fiscal 2020.
(2) The PV-10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10% per annum, which is the most directly comparable GAAP financial measure. PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. Our reconciliation of this non-GAAP financial measure is shown in the table as the PV-10, less future income taxes, discounted at 10% per annum, resulting in the standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%.
(3) In accordance with SEC requirement, the standardized measure of discounted future net cash flows was computed by applying 12-month first day of the month average prices for oil and gas during the fiscal year to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions.
(4) These prices reflect adjustment by lease for quality, transportation fees and market differentials.
During fiscal 2024, we added proved reserves of 272 thousand BOE (“MBOE”) through extensions and discoveries, added 44 MBOE through acquisitions, subtracted 163 MBOE for downward revisions of previous estimates. Such downward revisions are primarily attributable to a decrease in crude oil and natural gas prices and partially the result of reserves written off due to the five-year limitation and the change in the timing of new development. The reserves written off were primarily royalty interests on leases in DeSoto Parish, Louisiana and Karnes County, Texas which are held by production and still in place to be developed in the future.
During the fiscal year ending March 31, 2024, we had a working or royalty interest in the development of 43 wells converting reserves of approximately 62,000 BOE from proved undeveloped to proved developed - producing with capital cost of approximately $940,000.
Oil and gas prices significantly impact the calculation of the PV-10 and the standardized measure of discounted future net cash flows. The present value of future net cash flows does not purport to be an estimate of the fair market value of the Company’s proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 932, “Extractive Activities - Oil and Gas”, may not necessarily be the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.
We have not filed any other oil or gas reserve estimates or included any such estimates in reports to other federal or foreign governmental authority or agency during the year ended March 31, 2024, and no major discovery is believed to have caused a significant change in our estimates of proved reserves since that date.
Drilling Activities
The following table sets forth our drilling activity in wells in which we own a working interest for the years ended March 31:
Year Ended March 31,
Gross Net Gross Net
Exploratory Wells
Beginning wells in progress - - - -
Wells spud - - - -
Successful wells - - - -
Ending wells in progress - - - -
Development Wells
Beginning wells in progress .05 .04
Wells spud .22 .36
Successful wells (53 ) (.09 ) (44 ) (.35 )
Ending wells in progress .17 .05
The information contained in the foregoing table should not be considered indicative of future drilling performance, nor should it be assumed that there is any necessary correlation between the number of productive wells drilled and the amount of oil and gas that may ultimately be recovered by us.
In addition to the working interests mentioned above, other operators drilled 101 gross wells (.02 net wells) on company-owned minerals and royalties at no expense to the Company. We expect the production of our mineral interests will increase as operators continue to drill, complete and develop our acreage. We expect to capitalize on this development, which requires no capital expenditure funding from us, and believe the anticipated aggregate royalty receipts will enable us to grow our cash flows. A number of the horizontal wells in which the Company participates involve longer lateral which are more efficient and have greater estimated ultimate recovery.
Productive Wells and Acreage
Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections. Wells that are completed in more than one producing zone are counted as one well. As of March 31, 2024, we held an interest in approximately 6,800 gross (25.7 net) productive wells, including approximately 5,700 wells in which we held an overriding or royalty interest and 1,100 wells in which we held a working interest.
A gross 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 gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres. The following table sets forth the approximate developed acreage in which we held a leasehold mineral or other interest as of March 31, 2024:
Acreage
Gross Net
Texas 373,500 1,531
Oklahoma 69,300
Louisiana 38,900
New Mexico 31,000
North Dakota 22,400
Ohio 20,300
Kansas 8,500
Montana 5,000
Wyoming 3,800
Colorado 3,000
Arkansas 1,600
Alabama 1,000
Mississippi
Virginia
Total 579,000 2,709
Net Production, Unit Prices and Costs
The following table summarizes our net oil and natural gas production, the average sales price per barrel (“bbl”) of oil and per thousand cubic feet (“mcf”) of natural gas produced and the average production (lifting) cost per unit of production for the years ended March 31:
Years Ended March 31,
Oil (a):
Production (Bbls) 69,999 73,968
Revenue $ 5,348,257 $ 6,522,163
Average Bbls per day (d)
Average sales price per Bbl $ 76.40 $ 88.18
Gas (b):
Production (Mcf) 502,879 534,363
Revenue $ 1,114,390 $ 2,858,460
Average Mcf per day (d) 1,378 1,464
Average sales price per Mcf $ 2.22 $ 5.35
Total BOE (c) 153,812 163,029
Production costs:
Production expenses: $ 1,029,279 $ 1,039,893
Production expenses per BOE $ 6.69 $ 6.38
Production expenses per sales dollar $ 0.16 $ 0.11
Production and ad valorem taxes: $ 497,193 $ 679,826
Production and ad valorem taxes per BOE $ 3.23 $ 4.17
Production and ad valorem taxes per sales dollar $ 0.08 $ 0.07
Total oil and gas revenue $ 6,462,647 $ 9,380,623
(a) Includes condensate.
(b) Includes natural gas products.
(c) Natural gas production is converted to oil production using a ratio of six Mcf to one Bbl of oil.
(d) Calculated on a 365 day year.

---

ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
We may, from time to time, be a party to various proceedings and claims incidental to our business. While many of these matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future results of operations.

---

ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II

---

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
In September 2003, our common stock began trading on the NYSE American, formerly the American Stock Exchange and more recently the NYSE MKT, under the symbol “MXC”. Prior to September 2003, the Company’s common stock was traded on the over-the-counter bulletin board market under the symbol “MEXC”. The registrar and transfer agent is Issuer Direct Corporation, 500 Perimeter Park Drive, Suite D, Morrisville, North Carolina, 27560 (Tel: 877-481-4014). The following table sets forth certain information as to the high and low sales price quoted for Mexco’s common stock on the NYSE American.
High Low
2024: April - June 2023 $ 13.84 $ 10.30
July - September 2023 13.63 11.36
October - December 2023 13.50 9.05
January - March 2024 10.49 9.02
2023: April - June 2022 $ 24.18 $ 13.79
July - September 2022 20.84 14.43
October - December 2022 18.25 12.40
January - March 2023 15.39 10.50
On March 31, 2024, the closing sales price of our common stock on the NYSE American was $9.98 per share.
Stockholders
As of March 31, 2024, we had 2,226,916 shares issued and 827 shareholders of record which does not include shareholders for whom shares are held in a “nominee” or “street” name. Of these issued shares, 135,517 are held in the treasury.
Dividends
As of March 31, 2023, the Company had never paid a cash dividend to the Company’s shareholders. Payment of dividends are at the discretion of our Board of Directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion. In addition, our current bank loan prohibits us from paying cash dividends on our common stock without written permission.
On April 10, 2023, the Company announced that its Board of Directors declared a special dividend of $0.10 per common share to its shareholders of record at the close of business on May 1, 2023. The special dividend was paid on May 15, 2023. The Company obtained written permission from WTNB prior to declaring the special dividend.
The Company can provide no assurance that dividends will be authorized or declared in the future or as to the amount or type of any future dividends. Our board of directors’ determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination.
Subsequently, on April 30, 2024, the Company announced that its Board of Directors declared a regular annual dividend of $0.10 per common share to its shareholders of record at the close of business on May 21, 2024. The dividend was paid on June 4, 2024. The Company obtained written permission from WTNB prior to declaring the regular annual dividend.
Securities Authorized for Issuance Under Compensation Plans
The following table includes certain information about our Employee Incentive Stock Plan as of March 31, 2024, which has been approved by our stockholders.
Number of Shares Authorized for Issuance under Plan Number of Shares to be Issued upon Exercise of Outstanding Options Weighted Average Exercise Price of Outstanding Options Number of Shares Remaining Available for Future Issuance under Plan
2009 Plan 200,000 45,250 $ 5.27 -
2019 Plan 200,000 120,500 10.89 66,000
Total 400,000 165,750 $ 9.36 66,000
Issuer Repurchases
In March 2023, the Board of Directors authorized the use of up to $1,000,000 to repurchase shares of the Company’s common stock for the treasury account. This program does not have an expiration date and may be modified, suspended or terminated at any time by the Board. Under the repurchase program, share of common stock may be purchased from time to time through open market purchases or other transactions. The amount and timing of repurchases will be subject to the availability of stock, prevailing market conditions, the trading price of stock, our financial performance and other conditions. Repurchases may also be made from time-to-time in connection with the settlement of our share-based compensation awards. Repurchases will be funded from cash flow.
The following table provides information related to repurchases of our common stock for the treasury account during the year ended March 31, 2024:
Total Number of Shares Purchased Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Program Approximate Dollar Value of Shares that May Yet be Purchased Under the Program
July 1-31, 2023 9,500 $ 12.28 9,500 $ 883,293
August 1-31, 2023 9,500 $ 12.69 9,500 $ 762,742
September 1-30, 2023 7,000 $ 12.57 7,000 $ 674,744
October 1-31, 2023 6,000 $ 12.58 6,000 $ 599,267
November 1-30, 2023 1,839 $ 11.49 1,839 $ 578,141
December 1-31, 2023 3,322 $ 10.02 3,322 $ 544,867
January 1-31, 2024 1,501 $ 10.01 1,501 $ 529,849
February 1-28, 2024 4,266 $ 9.98 4,266 $ 487,288
March 1-31, 2024 7,173 $ 10.08 7,173 $ 414,965
Total 50,101
$ 11.68
50,101
During the year ended March 31, 2024, the Company repurchased 50,101 shares for the treasury account at an aggregate cost of $585,035, an average price of $11.68 per share. During the year ended March 31, 2023, the Company repurchased 18,416 shares for the treasury account at an aggregate cost of $244,494, an average price of $13.28 per share.
Subsequently, in April 2024, the Company’s Board of Directors authorized the use of up to $1,000,000 to repurchase shares of the Company’s common stock, par value, $0.50, for the treasury account. This authorization replaced the previously authorized $1,000,000 common stock repurchase program which had $414,965 remaining at the time it was replaced.
Also in April 2024, the Company repurchased 13,766 shares for the treasury account at an aggregate cost of $188,637, an average price of $13.70 per share.
On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA 2022”). The IRA 2022, among other tax provisions, establishes a 1% excise tax on stock repurchases made by publicly traded U.S. corporations, effective for stock repurchases after December 31, 2022. The IRA 2022 does provide for certain exceptions for repurchases of stock including an exception as long as the aggregate value of the repurchases for the tax year does not exceed $1,000,000.

---

ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. RESERVED

---

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-K.
Liquidity and Capital Resources and Commitments
Historically, we have funded our operations, acquisitions, exploration and development expenditures from cash generated by operating activities, bank borrowings, sales of non-core properties and issuance of common stock. Our primary financial resource is our base of oil and gas reserves. We have pledged our producing oil and gas properties to secure our credit facility. We do not have any delivery commitments to provide a fixed and determinable quantity of our oil and gas under any existing contract or agreement.
Our long-term strategy is on increasing profit margins while concentrating on obtaining reserves with low-cost operations by acquiring and developing oil and gas properties with potential for long-lived production. We focus our efforts on the acquisition of royalties and working interests and non-operated properties in areas with significant development potential.
Cash Flows
Changes in the net funds provided by or (used in) each of our operating, investing and financing activities are set forth in the table below:
For the Years Ended March 31,
Change
Net cash provided by operating activities $ 4,433,935 $ 6,515,895 $ (2,081,960 )
Net cash used in investing activities $ (3,416,499 ) $ (5,441,075 ) $ (2,024,576 )
Net cash used in financing activities $ (779,723 ) $ (209,815 ) $ 569,908
Cash Flow Provided by Operating Activities. Cash flow from operating activities is primarily derived from the production of our crude oil and natural gas reserves and changes in the balances of non-cash accounts, receivables, payables or other non-energy property asset account balances. Cash flow provided by our operating activities for the year ended March 31, 2024 was $4,433,935 in comparison to $6,515,895 for the year ended March 31, 2023. This decrease of $2,081,960 in our cash flow operating activities consisted of increase in our non-cash expenses of $505,448; a decrease in our accounts receivable of $426,598; an increase of $49,673 of our accounts payable and accrued expenses; and, a decrease in our net income for the current year of $3,317,518. Variations in cash flow from operating activities may impact our level of exploration and development expenditures.
Our expenditures in operating activities consist primarily of production expenses and engineering services. Our expenses also consist of employee compensation, accounting, insurance and other general and administrative expenses that we have incurred in order to address normal and necessary business activities of a public company in the crude oil and natural gas production industry.
Cash Flow Used in Investing Activities. Cash flow from investing activities is derived from changes in oil and gas property balances. For the year ended March 31, 2024, we had net cash of $3,016,499 used for additions to oil and gas properties and a $400,000 investment in two limited liability companies compared to $5,014,357 and $425,000, respectively, for the year ended March 31, 2023.
Cash Flow Used in Financing Activities. Cash flow from financing activities is derived from our changes in long-term debt and in equity account balances. Net cash flow used in our financing activities was $779,723 for the year ended March 31, 2024 compared to net cash flow used in our financing activities of $209,815 for the year ended March 31, 2023. During the year ended March 31, 2024, we expended $213,600 to pay the annual dividend, expended $585,035 to purchase 50,101 shares of our stock for the treasury account, and received proceeds of $19,662 for the exercise of employee and director stock options. During the year ended March 31, 2023, we received proceeds of $16,700 from the exercise of director stock options, received payment of $30,179 from a director for profits on purchase of stock within the six-month window of a previous stock sale, expended $244,494 for the purchase of 18,416 shares of our stock for the treasury and, expended $12,200 for the renewal of our credit facility.
Accordingly, net cash increased $237,713, leaving cash and cash equivalents on hand of $2,473,484 as of March 31, 2024.
We had working capital of $3,259,200 as of March 31, 2024 compared to working capital of $3,475,776 as of March 31, 2023, a decrease of $216,576 for the reasons set forth below.
Oil and Natural Gas Property Development.
New Participations in Fiscal 2024. The Company participated in the drilling and completion of 51 horizontal wells and 1 vertical well at a cost of approximately $2,300,000, of which $2,000,000 was expended during the fiscal year ending March 31, 2024. Nineteen of these wells have not been completed. Forty-eight of these horizontal wells are in the Delaware Basin located in the western portion of the Permian Basin in Lea and Eddy Counties, New Mexico. The remaining three horizontal wells are in the Bakken formation in McKenzie County, North Dakota and the vertical well is in Irion County, Texas.
In addition to the above working interests, there were 101 gross wells (.025 net wells) drilled by other operators on Mexco’s royalty interests and 348 gross wells (7.65 net wells) obtained through acquisitions.
Mexco expended approximately $264,000 to participate in the drilling of four horizontal wells in the Wolfcamp Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .52%. Two of these wells began producing in November 2023 and the other two in March 2024 with initial average production rates of 822 barrels of oil, 4,159 barrels of water and 2,574,000 cubic feet of gas per day, or 1,251 barrels of oil equivalent (“BOE”) per day.
Mexco expended approximately $152,000 to participate in the drilling of two horizontal wells in the Penn Shale formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .4%. These wells began producing in November 2023 with initial average production rates of 837 barrels of oil, 1,794 barrels of water and 659,000 cubic feet of gas per day, or 947 BOE per day.
Mexco expended approximately $105,000 to participate in the drilling and completion of two horizontal wells in the Penn Shale formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is approximately .285%. These wells began producing in September 2023 with initial average production rates of 582 barrels of oil, 1,488 barrels of water and 791,000 cubic feet of gas per day, or 714 BOE per day.
Mexco expended approximately $870,000 to participate in the drilling of five horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is approximately 1.16%. Subsequently, in April 2024, two of these wells were completed with initial average production rates of 1,065 barrels of oil, 2,107 barrels of water and 706,500 cubic feet of gas per day, or 1,183 BOE per day.
In July 2023, Mexco expended approximately $36,000 to participate in the drilling and completion of two horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is approximately .1%. These wells began producing in September 2023 with initial average production rates of 898 barrels of oil, 1,969 barrels of water and 503,000 cubic feet of gas per day, or 982 BOE per day.
In November 2023, Mexco expended approximately $32,000 to participate in the drilling and completion of one horizontal well in the Penn Shale formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in this well is .165%.
In February 2024, Mexco expended approximately $74,000 to participate in the drilling of two horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .53%. Subsequently, in May 2024, Mexco expended approximately $90,000 to complete these wells.
In February 2024, Mexco expended approximately $170,000 to participate in the drilling of four horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .45%.
In February 2024, Mexco expended approximately $153,000 to participate in an exploratory well in the Fusselman Formation of Irion County, Texas. Subsequently, in May 2024, the Company expended $27,000 for additional drilling costs. This well was later determined to be noncommercial and will be plugged and abandoned in fiscal 2025.
In October 2022, the Company made an approximately 2% equity investment commitment in a limited liability company amounting to $2,000,000 of which $800,000 has been funded as of March 31, 2024. The limited liability company is capitalized at approximately $100 million to purchase mineral interests in the Utica and Marcellus areas in the state of Ohio. Subsequently, in May 2024, the Company funded another $200,000 toward this investment. This LLC has returned $81,231 or 8% of the total investment.
Completion of Wells Drilled in Fiscal 2023. The Company expended approximately $450,000 in the completion of 21 horizontal wells in which the Company participated in fiscal 2023.
The Company expended approximately $427,000 for the completion costs of eight horizontal wells in the Wolfcamp Sand formation of the Delaware Basin in Lea County, New Mexico that the Company participated in drilling during fiscal 2023. Mexco’s working interest in these wells is .52%. These wells began producing in October 2023 with initial average production rates of 825 barrels of oil, 3,540 barrels of water and 2,150,000 cubic feet of gas per day, or, 1,183 BOE per day.
Three horizontal wells in the Bone Spring formation of the Delaware Basin in Eddy County, New Mexico in which the Company participated during fiscal 2023 were completed in May 2023 with initial average production rates of 437 barrels of oil, 983 barrels of water and 603,000 cubic feet of gas per day, or, 538 barrels of oil equivalent per day. Mexco’s working interest in these wells is .05%.
Seven horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico in which the Company participated during fiscal 2023 were completed with initial average production rates of 1,827 barrels of oil, 1,945 barrels of water and 2,264,000 cubic feet of gas per day, or, 2,204 barrels of oil equivalent per day. Mexco’s working interest in these wells is .033%.
Acquisitions. During the year, the Company acquired royalty interests in 39 producing wells with additional potential locations for development in Howard and Lee Counties, Texas for an aggregate purchase price of $261,700.
In February 2024, the Company acquired royalty interests in 8 producing wells with additional potential locations for development operated by PDC Energy, Inc. and 4 producing wellbores operated by Chevron Corporation for an aggregate purchase price of $575,600. These wells are located in Weld County, Colorado.
In February 2024, the Company acquired royalty interests in 255 producing wells in the Haynesville trend area of Caddo Parish, Louisiana for a purchase price of $390,300.
In December 2023, the Company acquired royalty (mineral) interests in 7 wells operated by Occidental Petroleum Corporation and located in Reeves County, Texas for a purchase price of $364,000 which is effective November 1, 2023. In January 2024, the Company acquired an additional interest in these same wells for a purchase price of $91,000, effective December 1, 2023.
In November 2023, the Company acquired small royalty interests in 27 producing wells as well as non-producing mineral interests in 1,280 gross acres located in Crane, Ector, Midland and Upton Counties, Texas for an aggregate purchase price of $105,800.
Subsequently, in April 2024, the Company acquired small royalty (mineral) interests in 21 wells operated by Anadarko Petroleum Corporation and Cimarex Energy Company and located in Reeves County, Texas for a purchase price of $158,000 which is effective April 1, 2024.
Sales of Properties. During the first quarter of fiscal 2024, the Company received approximately $280,000 in cash from a sale of joint venture leasehold acreage and marginal producing working interest wells in Reagan County, Texas, marginal producing working interest wells in Pecos County, Texas and interest in surface acreage in Palo Pinto County, Texas.
In December 2023, the Company made on a 3-year Term Assignment of 98% of the Company’s leasehold interest in certain deep rights of 200 acres in Loving and Ward Counties, Texas. The Company received $5,000 per net leasehold acre in the total amount of approximately $980,000. The Company retained the remaining 2% leasehold interest as a participating interest in the full unit at approximately .625% working interest. The Company also retained an overriding royalty interest of 5% proportionately reduced.
Also in December 2023, the Company made on a 3-year Term Assignment of the Company’s leasehold interest in 12.96 net mineral acres located in Lea County, New Mexico. The Company received $2,500 per net leasehold acre in the total amount of $32,400. The Company retained an overriding royalty interest equal to the positive difference between 25% and any existing burdens of record as of the effective date.
Subsequent Participations. In April 2024, Mexco expended approximately $80,000 to participate in the drilling of five horizontal wells in the Bone Spring formation of the Delaware Basin in Lea County, New Mexico and $127,800 to drill four horizontal wells in the Wolfcamp Sand formation of the Delaware Basin in Lea County, New Mexico.
We are participating in other projects and are reviewing projects in which we may participate. The cost of such projects would be funded, to the extent possible, from existing cash balances and cash flow from operations. The remainder may be funded through borrowings on the credit facility and, if appropriate, sales of non-core properties.
Markets. Crude oil and natural gas prices generally remained volatile during the last year. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, in the last twelve months, the NYMEX West Texas Intermediate (“WTI”) posted price for crude oil has ranged from a low of $63.10 per bbl in June 2023 to a high of $89.66 per bbl in September 2023. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $1.25 per MMBtu in March 2024 to a high of $3.34 per MMBtu in October 2023.
On March 31, 2024 the WTI posted price for crude oil was $79.15 per bbl and the Henry Hub spot price for natural gas was $1.54 per MMBtu. See Results of Operations below for realized prices.
Results of Operations
Fiscal 2024 Compared to Fiscal 2023
We had net income of $1,344,952 for the year ended March 31, 2024 compared to $4,662,702 for the year ended March 31, 2023, a 71% decrease as a result of a decrease in operating revenues due to a decrease in oil and natural gas prices and production that is further explained below.
Oil and natural gas sales. Revenue from oil and natural gas sales was $6,462,647 for the year ended March 31, 2024, a 31% decrease from $9,380,623 for the year ended March 31, 2023. This resulted from a decrease in oil and natural gas prices and production volumes. The following table sets forth our oil and natural gas revenues, production quantities and average prices received during the fiscal years ended March 31:
% Difference
Oil:
Revenue $ 5,348,257 $ 6,522,163 (18.0 )%
Volume (bbls) 69,999 73,968 (5.4 )%
Average Price (per bbl) $ 76.40 $ 88.18 (13.4 )%
Gas:
Revenue $ 1,114,390 $ 2,858,460 (61.0 )%
Volume (mcf) 502,879 534,363 (5.9 )%
Average Price (per mcf) $ 2.22 $ 5.35 (58.5 )%
Production and exploration. Production costs were $1,526,472 in fiscal 2024, an 11% decrease from $1,719,719 in fiscal 2023. This was primarily the result of a decrease in production taxes as a result of the decrease in oil and gas revenues.
Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense was $1,969,742 in fiscal 2024, a 6% increase from $1,854,047 in fiscal 2023. This was primarily due to an increase in the full cost pool amortization and a decrease in the oil and gas reserves partially offset by a decrease in oil and gas production.
General and administrative expenses. General and administrative expenses were $1,243,548 for the year ended March 31, 2024, an 11% increase from $1,120,691 for the year ended March 31, 2023. This was primarily due to an increase in employee stock option compensation, salaries and contract services, and accounting fees.
Interest expense. Interest expense was $5,234 in fiscal 2024, a 60% decrease from $13,097 in fiscal 2023, due to a decrease in borrowings.
Income taxes. Federal income tax for fiscal 2024 was $500,915. There was no federal income tax for fiscal 2023 because the Company was in a net deferred tax asset position. State income tax was $119,629 in fiscal 2024, a 27% decrease from $164,510 for fiscal 2023 due to the decrease in oil and natural gas sales in the State of New Mexico. The effective tax rate for state and federal taxes combined for fiscal 2024 and fiscal 2023 was 32% and 3%, respectively. The increase in the effective federal tax rate is the result of the Company now being in a net deferred tax liability position and the reconciliation to the federal tax return.
Contractual Obligations
We have no off-balance sheet debt or unrecorded obligations and have not guaranteed the debt of any other party. The following table summarizes future payments we are obligated to make based on agreements in place as of March 31, 2024:
Payments due in:
Total less than 1 year 1 - 3 years over 3 years
Contractual obligations:
Leases (1) $ 19,413 $ 19,413 - $ -
(1) The lease amount represents the monthly rent amount for our principal office space in Midland, Texas under a 38-month lease agreement effective May 15, 2018 and extended another 36 months to July 31, 2024. Of this total obligation for the remainder of the lease, our majority shareholder will pay $5,191 less than 1 year for his portion of the shared office space.
Alternative Capital Resources
Although we have primarily used cash from operating activities, the sales of assets and funding from the credit facility as our primary capital resources, we have in the past, and could in the future, use alternative capital resources. These could include joint ventures, carried working interests and issuances of our common stock through a private placement or public offering.
Other Matters
Critical Accounting Policies and Estimates
In preparing financial statements, management makes informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to litigation, environmental liabilities, income taxes, fair value and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.
The following represents those policies that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain.
Full Cost Method of Accounting for Crude Oil and Natural Gas Activities. SEC Regulation S-X defines the financial accounting and reporting standards for companies engaged in crude oil and natural gas activities. Two methods are prescribed: the successful efforts method and the full cost method. We have chosen to follow the full cost method under which all costs associated with property acquisition, exploration and development are capitalized. We also capitalize internal costs that can be directly identified with acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation (“ARO”) when incurred.
Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the sale would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of crude oil and natural gas properties are generally calculated on a well by well or lease or field basis versus the “full cost” pool basis. Additionally, gain or loss is generally recognized on all sales of crude oil and natural gas properties under the successful efforts method. As a result our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher DD&A rate on our crude oil and natural gas properties.
At the time it was adopted, management believed that the full cost method would be preferable, as earnings tend to be less volatile than under the successful efforts method. However, the full cost method makes us more susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. These charges are not recoverable when prices return to higher levels. Our crude oil and natural gas reserves have a relatively long life. However, temporary drops in commodity prices can have a material impact on our business including impact from the full cost method of accounting.
Ceiling Test. Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test each quarter. The full cost ceiling test is an impairment test to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after-tax present value of the future net cash flows from proved crude oil and natural gas reserves plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation write-down.” This impairment to our oil and gas properties does not impact cash flow from operating activities, but does reduce our stockholders’ equity and reported earnings.
The risk that we will be required to write down the carrying value of crude oil and natural gas properties increases when crude oil and natural gas prices are depressed or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or if purchasers cancel long-term contracts for natural gas production. An expense recorded in one period may not be reversed in a subsequent period even though higher crude oil and natural gas prices may have increased the ceiling applicable to the subsequent period.
Estimates of our proved reserves are based on the quantities of oil and gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our reserve estimates and the projected cash flows are derived from these reserve estimates, in accordance with SEC guidelines by an independent engineering firm based in part on data provided by us. The accuracy of a reserve estimate is a function of the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgment of the persons preparing the estimate. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.
It should not be assumed that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, the cost ceiling represents the present value (discounted at 10%) of net cash flows from sales of future production using the average price over the prior 12-month period.
The estimates of proved reserves materially impact DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost projects.
Use of Estimates. In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. In addition, significant estimates are used in determining year end proved oil and gas reserves. Although management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates. The estimate of our oil and natural gas reserves, which is used to compute DD&A and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect these reported results.
Excluded Costs. Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the DD&A pool). Impairments transferred to the DD&A pool increase the DD&A rate.
Revenue Recognition - Revenue from Contracts with Customers. Revenues from our royalty and non-operated working interest properties are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received two to three months after the production month, the Company accrues for revenue earned but not received by estimating production volumes and product prices. Any identified differences between its revenue estimates and actual revenue received historically have not been significant.
Asset Retirement Obligations. The estimated costs of plugging, restoration and removal of facilities are accrued. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated by the units of production method. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. For all periods presented, we have included estimated future costs of abandonment and dismantlement in the full cost amortization base and amortize these costs as a component of our depletion expense.
Gas Balancing. Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when our excess takes of natural gas volumes exceed our estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where Mexco has taken less than its ownership share of gas production (under produced).
Stock-based Compensation. We use the Binomial option pricing model to estimate the fair value of stock-based compensation expenses at grant date. This expense is recognized as compensation expense in our financial statements over the vesting period. We recognize the fair value of stock-based compensation awards as wages in the Consolidated Statements of Operations based on a graded-vesting schedule over the vesting period.
Accounts Receivable. Our accounts receivable includes trade receivables from joint interest owners and oil and gas purchasers. Credit is extended based on an evaluation of a customer’s financial condition and, generally, is uncollateralized. Accounts receivable under joint operating agreements have a right of offset against future oil and gas revenues if a producing well is completed. The collectibility of receivables is assessed and an allowance is made for any credit losses. The allowance for credit losses is determined based on a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole.
Income Taxes. The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates applicable to the years in which those differences are expected to be settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income in the period that includes the enactment date. Any interest and penalties are recorded as interest expense and general and administrative expense, respectively.
Other Property and Equipment. Provisions for depreciation of office furniture and equipment are computed on the straight-line method based on estimated useful lives of three to ten years.
Investments. The Company accounts for investments of less than 3% of any limited liability companies at cost. The Company has no control of the limited liability companies. The cost of the investment is recorded as an asset on the consolidated balance sheets and when income from the investment is received, it is immediately recognized on the consolidated statements of operations.
Reclassifications. Certain amounts in prior periods’ consolidated financial statements have been reclassified to conform with the current period’s presentation. These reclassifications had no effect on previously reported results of operations, retained earnings or net cash flows.
Leases. The Company determines an arrangement is a lease at inception. Operating leases are recorded in operating lease right-of-use asset, operating lease liability, current, and operating lease liability, long-term on the consolidated balance sheets.
Operating lease right-of-use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent its obligation to make lease payments arising from the lease. Operating lease assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. As the Company’s lease does not provide an implicit rate, the Company uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The incremental borrowing rate used at adoption was 3.75%. Significant judgement is required when determining the incremental borrowing rate. Rent expense for lease payments is recognized on a straight-line basis over the lease term.
Recent Accounting Pronouncements. In December 2023, the FASB issued Accounting Standards Update (“ASU”) No. 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures,” which requires disaggregated information about the Company’s effective tax rate reconciliation and income taxes paid. This ASU is effective for annual periods beginning after December 15, 2024 on a prospective basis and early adoption is permitted. The Company is currently evaluating the impact of this standard on its tax disclosures.

---

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary source of market risk for us includes fluctuations in commodity prices and interest rates. All of our financial instruments are for purposes other than trading.
Credit Risk. Credit risk is the risk of loss as a result of nonperformance by other parties of their contractual obligations. Our primary credit risk is related to oil and gas production sold to various purchasers and the receivables are generally not collateralized. At March 31, 2024, our largest credit risk associated with any single purchaser was $480,836 or 48% of our total oil and gas receivables. We have not experienced any significant credit losses.
Energy Price Risk. Our most significant market risk is the pricing applicable to our crude oil and natural gas production. Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. Prices for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future.
Factors that can cause price fluctuations include the level of global demand for petroleum products, foreign and domestic supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels and overall political and economic conditions in oil producing and consuming countries.
For example, in the last twelve months, the NYMEX West Texas Intermediate (“WTI”) posted price for crude oil has ranged from a low of $63.10 per bbl in June 2023 to a high of $89.66 per bbl in September 2023. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $1.25 per MMBtu in March 2024 to a high of $3.34 per MMBtu in October 2023. On March 31, 2024 the WTI posted price for crude oil was $79.15 per bbl and the Henry Hub spot price for natural gas was $1.54 per MMBtu. See Results of Operations above for the Company’s realized prices during the fiscal year. Subsequently, on June 18, 2024, the WTI posted price for crude oil was $77.55 and the Henry Hub posted price for natural gas was $2.43.
Declines in oil and natural gas prices will materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Changes in oil and gas prices impact both estimated future net revenue and the estimated quantity of proved reserves. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our credit facility and adversely affect the amount of cash flow available for capital expenditures and our ability to obtain additional capital for our acquisition, exploration and development activities. In addition, a noncash write-down of our oil and gas properties could be required under full cost accounting rules if prices declined significantly, even if it is only for a short period of time. See Critical Accounting Policies and Estimates - Ceiling Test under Item 7 of this report on Form 10-K. Lower prices may also reduce the amount of crude oil and natural gas that can be produced economically. Thus, we may experience material increases or decreases in reserve quantities solely as a result of price changes and not as a result of drilling or well performance.
Similarly, any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. If the average oil price had increased or decreased by ten dollars per barrel for fiscal 2024, our pretax income would have changed by $699,990. If the average gas price had increased or decreased by one dollar per mcf for fiscal 2024, pretax income would have changed by $502,879.

---

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item appears on pages through hereof and are incorporated herein by reference.

---

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.

---

ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Management’s Annual Report on Internal Control over Financial Reporting. The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our internal control over financial reporting is supported by appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel, and a written Code of Conduct adopted by our Board of Directors, applicable to all directors, officers and employees of Mexco.
Our chief executive officer and chief financial officer assessed the effectiveness our internal control over financial reporting using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in the 2013 “Internal Control - Integrated Framework”. Based upon that evaluation, our chief executive officer and chief financial officer concluded that our internal control over financial reporting was effective as of March 31, 2024.
Evaluation of Disclosure Controls and Procedures. We maintain disclosure controls and procedures to ensure that the information we must disclose in our filings with the SEC is recorded, processed, summarized and reported on a timely basis. At the end of the period covered by this report, our principal executive officer and principal financial officer reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e). Based on such evaluation, such officers concluded that, as of March 31, 2024, our disclosure controls and procedures were effective.
Changes in Internal Control over Financial Reporting. No changes in the Company’s internal control over financial reporting occurred during the year ended March 31, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

---

ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None

---

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
See “Mexco Energy Corporation Board of Directors”, “Named Executive Officers Who Are Not Directors”, “Section 16(a) Beneficial Ownership Reporting Compliance”, “Corporate Governance and Code of Business Conduct” and “Meetings and Committees of the Board of Directors” in the Proxy Statement of Mexco Energy Corporation for our Annual Meeting of Stockholders to be held September 10, 2024 (“Proxy Statement”) to be filed with the SEC within 120 days after the end of our fiscal year ended March 31, 2024, which is incorporated herein by reference.
The information required by this item with respect to executive officers of the Company is also set forth in Part I of this report.

---

ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item will be contained in the Proxy Statement under the caption “Executive Compensation”, and is hereby incorporated herein by reference.

---

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this item will be contained in the Proxy Statement under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Employee Incentive Stock Option Plans”, and is hereby incorporated herein by reference.

---

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by this item will be contained in the Proxy Statement under the captions “Certain Relationships and Related Transactions” and “Meetings and Committees of the Board of Directors”, and is hereby incorporated by reference herein.

---

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item will be contained in the Proxy Statement under the caption “Audit Fees and Services”, and is hereby incorporated by reference herein.
PART IV

---

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Consolidated Financial Statements. For a list of the consolidated financial statements filed as part of this Form 10-K, see the “Index to Consolidated Financial Statements” set forth on of this report.
Financial Statement Schedules. All schedules have been omitted because they are not applicable, not required under the instructions or the information requested is set forth in the consolidated financial statements or related notes thereto.
Exhibits. For a list of the exhibits required by this Item and accompanying this Form 10-K see the “Index to Exhibits” set forth on page of this report.