# Mexco Energy Corp: Form 10-K for the period ended Mar 31, 2026

- Company: [Mexco Energy Corp](/companies/mxc.md) (CIK 66418)
- Form: 10-K
- Filed: 2026-06-29
- Accepted by EDGAR: Jun 29, 2026, 06:11 ET
- Period: 2026-03-31
- Accession: 0001493152-26-030386
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/66418/000149315226030386/form10-k.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/66418/000149315226030386/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2026-03-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 12 months, 2025-04-01 to 2026-03-31 | $6.6m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Operating income | 12 months, 2025-04-01 to 2026-03-31 | $1.3m | us-gaap:OperatingIncomeLoss |
| Interest expense | 12 months, 2025-04-01 to 2026-03-31 | $4.4k | us-gaap:InterestExpenseNonoperating |
| Income tax | 12 months, 2025-04-01 to 2026-03-31 | $379.0k | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 12 months, 2025-04-01 to 2026-03-31 | $1.3m | us-gaap:NetIncomeLoss |
| Diluted EPS | 12 months, 2025-04-01 to 2026-03-31 | $0.63 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 12 months, 2025-04-01 to 2026-03-31 | $0.64 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 12 months, 2025-04-01 to 2026-03-31 | 2,080,503 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 12 months, 2025-04-01 to 2026-03-31 | $3.8m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Dividends paid | 12 months, 2025-04-01 to 2026-03-31 | $204.6k | us-gaap:PaymentsOfDividends |
| Cash and equivalents | at 2026-03-31 | $2.8m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2026-03-31 | $4.4m | us-gaap:AssetsCurrent |
| Total assets | at 2026-03-31 | $21.7m | us-gaap:Assets |
| Current liabilities | at 2026-03-31 | $452.9k | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2026-03-31 | $1.7m | us-gaap:Liabilities |
| Shareholders' equity | at 2026-03-31 | $20.0m | us-gaap:StockholdersEquity |

## Business

As filed, 26,036 characters.

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 as Miller Oil Company, the Company changed its name to Mexco Energy Corporation effective April 30, 1980. At that time, the Company’s shareholders 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, 2026 were approximately 1.437 million barrels of oil equivalent (“MMBOE”) of which 46% was oil and 54% was natural gas, and our estimated present value of proved reserves was approximately $21 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 46% 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 crude oil, natural gas, 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 will preferably 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 bidding process to sell properties. This process intensifies the competition and makes it difficult to acquire reserves without assuming significant price and production risks. We actively seek opportunities to acquire proved oil and gas properties. However, given the intense competition, we cannot give any assurance that we will be successful in our efforts during fiscal 2027.

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 evaluating and purchasing producing oil and gas properties, including working, royalty, and mineral interests, as well as prospects that could meaningfully impact on our reserves. All of the Company’s oil and gas interests are operated by others.

From 1983 to 2026, 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 with an 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, which were dissolved in 1957 and 1947, respectively. Purchase covering thousands of acres located in 27 counties in Texas, 3 parishes in Louisiana, and one county in Arkansas, consisting of various mineral, royalty, and overriding royalty interests.

1997 Forman Energy Corporation, purchase price of $1,591,000, consisting primarily of working interests in approximately 634 wells located in 12 states.

2004-2005 Royalty interests, purchase price of $1,354,000, covering 145 producing wells in the Cotton Valley formation in Freestone and Limestone Counties, Texas, and Jackson Parish, Louisiana. This acreage also contains additional potential undeveloped locations.

2007-2008 Non-operated working interests, purchase price of $425,000, covering 2 properties in Lea County, New Mexico.

Royalty (mineral) acreage, purchase price of $2,279,000, consisting of 122 mineral acres in the Newark East Field (Barnett Shale) of Tarrant County, Texas representing an approximate 21.45% royalty interest, and 522 additional mineral acres in the same field containing 6 producing natural gas wells and additional undeveloped drilling locations. Purchased additional interests in March 2009 for $49,000.

2010-2012 Southwest Texas Disposal Corporation, purchase price of $478,000, consisting of royalty interests in over 300 wells located in 60 counties and parishes of 6 states.

Overriding royalty interests, purchase price of $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 of $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. Purchased additional working interests in March 2012 for $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.

2014 Royalty interests, purchase price of $1,780,000, covering approximately 2,400 wells in eight states, primarily in Texas.

Non-operated working interests, purchase price of $1,490,000, covering 193 producing wells located in 11 counties across Louisiana, Oklahoma, New Mexico, and Texas.

2019 Royalty interest investment of $300,000 for a less than 1% investment commitment in a limited liability company (“LLC”), 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 115% of the total investment since inception in fiscal 2020.

2022-2023 Royalty and overriding royalty interests, purchase price of $1,623,000, covering 103 producing wells and several additional undeveloped locations in the Eagle Ford Shale area of Dimmit County, Texas, the Haynesville Shale trend across Louisiana and Texas, and in Atascosa and Karnes Counties, Texas.

Royalty interest investment of $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. During 2025, an additional $227,429 was expended to participate in a voluntary optional cash call and acquire its proportionate share of the resulting non-consenting interests, increasing its capitalized investment. As of the date of this report, this investment is fully funded, and 25% of the investment has been returned.

2023-2024 Royalty interests, purchase price of $1,788,400, covering 360 producing wells and additional potential locations for development in Weld County, Colorado, Caddo Parish, Louisiana, and multiple counties throughout Texas.

2024-2025 Royalty interests, purchase price of $1,972,000, covering approximately 750 producing wells and additional undeveloped drilling locations across multiple counties in Colorado, Louisiana, Montana, New Mexico, Nebraska, North Dakota, South Dakota, Texas, and Wyoming.

2025-2026 Royalty interests, purchase price of $817,700, covering approximately 262 producing wells, additional interests in 19 previously owned wells with additional development potential across counties in Colorado, Louisiana, and Texas, and 40 undeveloped net leasehold in Eddy County, New Mexico.

Industry Environment and Outlook

Commodity prices remained volatile during fiscal 2026 due to shifting global supply-and-demand fundamentals, OPEC+ production decisions, geopolitical tensions, inflationary pressures, interest rate uncertainty, and concerns regarding the pace of global economic growth. In addition, fluctuations in oil and natural gas prices, evolving trade policies, and continued uncertainty in the broader economic environment may continue to impact our industry and operating results. In light of these challenges and the ongoing volatility in commodity markets, our primary business strategies for fiscal 2027 will continue to include: (1) optimizing cash flows through operating efficiencies and cost reductions, (2) divesting 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 2026 operating results and potential impact on fiscal 2027 operating results due to commodity price changes.

Oil and Gas Operations

As of March 31, 2026, oil contributed approximately 81% of our oil and natural gas sales and approximately 46% of our total proved reserves volumes for fiscal 2026. Revenues from oil and gas royalty interests accounted for approximately 49% of our total operating revenues and income from investments in LLCs for fiscal 2026.

The Company is primarily focused on two areas: 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 75% of our discounted future net cash flows from proved reserves and 76% of our operating revenues.

The Permian Basin is one of the oldest and most prolific producing basins in North America and has been a significant source of oil production since the 1920s. The Permian Basin contains numerous oil and gas-bearing formations that have supported commercial production for decades.

The Delaware Basin properties, encompassing 39,129 gross acres, 209 net acres, 769 gross producing wells, or 4 net wells, account for approximately 53% of our discounted future net cash flows from proved reserves as of March 31, 2026. For fiscal 2026, these properties accounted for 54% of our operating revenues. Of these discounted future net cash flows from proved reserves, approximately 14% are attributable to proven undeveloped reserves, which would be developed through new drilling.

The Midland Basin properties, encompassing 115,077 gross acres, 232 net acres, 1,786 gross producing wells, or 4 net wells, account for approximately 21% of our discounted future net cash flows from proved reserves as of March 31, 2026. For fiscal 2026, these properties accounted for 21% of our operating revenues.

Mexco believes its most important properties for future development by horizontal drilling and hydraulic fracturing 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 8,100 producing wells all of which are located within the United States in the states of Texas, New Mexico, Oklahoma, Louisiana, Alabama, Arkansas, Wyoming, Kansas, Colorado, Montana, Virginia, North Dakota, South 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) |
| --- | ---: | ---: |
| 2026 | 82,133 | 681,794 |
| 2025 | 83,564 | 570,012 |
| 2024 | 69,999 | 502,879 |
| 2023 | 73,968 | 534,363 |
| 2022 | 61,689 | 393,841 |

Competition

The oil and gas industry is highly competitive. We compete with major integrated oil and gas companies, other independent oil and gas companies, private equity-backed operators and individual producers, many of which have financial, technical and personnel resources substantially greater than our own. As a result, we may be placed at a competitive disadvantage. Competitive factors include commodity prices, acquisition costs, contract terms, access to capital, operational expertise and the quality and availability of service providers, including drilling, completion and transportation services.

Competition for oil and gas reserve acquisitions and development opportunities is significant. Our ability to acquire and develop additional properties will depend on our ability to identify, evaluate, and consummate transactions in a timely manner in a highly competitive marketplace.

In addition, the oil and gas industry competes with other energy sources to meet the energy requirements of industrial, commercial, and residential consumers. Advances in alternative energy technologies and changes in consumer preferences and governmental policies promoting alternative energy sources may affect demand for oil and natural gas and could adversely impact our revenues and results of operations.

Markets and Major Customers

As a non-operator, we depend on third-party operators to conduct exploration, development, and production activities on our behalf. These operators generally determine drilling schedules, development activities, production levels, and operating practices. Accordingly, our production volumes, operating results, and costs are influenced by the decisions and performance of such operators, over which we have limited control.

Market factors affect both the quantities of oil, natural gas and natural gas liquids production and the prices received for such production. These factors include the level of domestic and international production; imports and exports of crude oil and natural gas; global and regional supply and demand balances; domestic and foreign economic conditions; geopolitical events; trade policies and tariffs; OPEC+ production decisions; weather conditions; transportation and pipeline capacity; and governmental regulations, including environmental, energy conservation, climate-related, and tax laws.

The market for our oil, natural gas, and natural gas liquids production depends on numerous factors beyond our control, including commodity price volatility, domestic and foreign political and economic conditions, and the availability and cost of alternative energy sources.

Our third-party operators market and sell production from properties in which we own a working or royalty interest. Proceeds attributable to our interest are collected and remitted to us either by the operator or by the purchaser, depending on their contractual arrangements. The counterparties, or payors, that remit such proceeds to us represent the sources of our operating revenues and income from investments in LLCs. Sales attributable to payors that amounted to 10% or more for the years ended March 31 were as follows:

|  | 2026 | 2025 |
| --- | ---: | ---: |
| BTA Oil Producers, LLC | 33% | 59% |
| ExxonMobil Corporation | 15% | - |

Historically, the Company has not experienced significant credit losses on its oil and gas accounts, and management is of the opinion that significant credit risk does not exist. Because there is a ready market for oil and gas production, we do not believe the loss of any individual payor would have a material adverse effect on our financial position or results of operations.

### Environmental Regulation

The oil and gas industry is subject to extensive regulation at the federal, state, and local levels. Environmental and energy-related regulations are subject to ongoing review and may be revised or made more stringent over time. 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 (the “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”), as well as state environmental and natural resources agencies, have regulatory authority over aspects of the operations conducted on properties in which the Company owns an interest.

Under certain environmental laws and regulations, including the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), operators and owners of properties may be subject to strict, joint and several liability for investigation, remediation, and removal of contamination, regardless of fault or compliance with applicable laws at the time of the relevant activities. CERCLA and similar statutes may impose liability on current and former owners and operators of a site, as well as on persons who arranged for disposal or treatment of hazardous substances. As a result, government authorities or private parties may seek to recover cleanup costs or require remediation of environmental conditions, including those arising from historical operations by prior operators. Because the Company is a non-operating working interest owner in certain properties, it may, in certain circumstances, be held responsible for a portion of such costs under applicable law.

Various federal, state, and regional initiatives have been adopted or are under consideration to regulate greenhouse gas (“GHG”) emissions, including through permitting requirements, emissions reporting obligations, or other regulatory or market-based mechanisms. These regulations may result in increased compliance costs for operators of the Company’s properties, including costs associated with monitoring, permitting, equipment upgrades, emissions controls, or the purchase of emissions allowances or credits. In addition, such regulations could indirectly affect demand for oil and natural gas over time. The extent and timing of future climate-related regulatory developments and their potential impact on operations and financial results remain uncertain. In addition, future climate-related regulations or disclosure requirements, including those relating to emissions reporting or climate risk disclosure, may increase compliance costs or require changes to the Company’s reporting practices.

We did not incur any material capital expenditures for remediation or pollution control activities for the year ended March 31, 2026. 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 2027.

### Other Regulation

Other federal agencies with regulatory authority over the Company’s business include the Internal Revenue Service (the “IRS”), the U.S. Securities and Exchange Commission (the “SEC”), and national securities exchanges such as the NYSE, as applicable. Compliance with applicable laws, regulations, and reporting requirements administered by these and other regulatory bodies requires ongoing effort and may result in additional costs. Because public policy, regulatory frameworks, and enforcement priorities may change over time, the Company cannot predict the future cost or impact of compliance with such laws and regulations. However, the Company does not expect that these regulatory requirements will affect its operations in a manner materially different from similarly situated companies in the industry.

Title to Properties

The leasehold properties in which we own interests are subject to royalty, overriding royalty, and other burdens customary in the industry. These properties may be subject to liens arising under operating agreements, 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 or operation of such properties.

Prior to drilling an oil and natural gas well, it is customary in our industry for the operator to conduct a preliminary title examination to identify material defects affecting the leasehold or mineral interests. In some cases, curative actions are required to address title defects, which may result in additional expense or delay. The failure to cure such defects could delay or prevent the development of the associated mineral interests. We believe the title to the properties in which we own an interest is generally good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to exceptions that are not expected to materially impair the use or value of such properties.

Substantially all of our properties are currently subject to liens under a deed of trust securing obligations under our credit facility.

Insurance

Our operations are subject to all the risks inherent in the exploration, 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 exceeding existing insurance coverage.

Executive Officers

The following table sets forth certain information concerning the executive officers of the Company as of March 31, 2026.

| Name | Age | Position |
| --- | ---: | --- |
| Nicholas C. Taylor | 88 | Chairman and Chief Executive Officer |
| Tamala L. McComic | 57 | President, Chief Financial Officer, Treasurer, and Assistant Secretary |
| Donna Gail Yanko | 81 | Vice President |
| Stacy D. Hardin | 61 | Secretary and Assistant Treasurer |

8

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. Since July 1993, 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, where he 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 Vice President 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 Company’s Chairman of the Board with 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 in September 2021. She has also served the Company as Assistant Treasurer of the Company since 2010 and, from 2006 to 2021, as Assistant Secretary. Prior thereto, Ms. Hardin served as Assistant Controller.

Employees

As of March 31, 2026, we had two full-time and two 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.

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 reports filed with the SEC 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.

## Risk factors

As filed, 22,687 characters.

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 that are not currently known to us or that we deem immaterial. If any of these risks actually occur, 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 and are influenced by numerous factors beyond our control, including global supply and demand, actions of OPEC and other producing nations, government regulation and taxation (including environmental regulation), levels of exploration and production activity, transportation and storage capacity constraints, availability of alternative fuels, technological developments affecting energy consumption, speculative trading in commodity derivatives, weather conditions, geopolitical developments, pandemics, and overall global economic conditions.

These price fluctuations impact our cash flows, capital expenditure flexibility, and access to capital. Reductions in prices may decrease the borrowing base under our credit facility, trigger ceiling test write-downs, and reduce the amount of oil and natural gas that can be produced economically. As a result, reserve estimates may change significantly due to price movements rather than operational performance.

Changes in commodity prices also affect estimated future net revenues and proved reserve quantities, which in turn can reduce our borrowing capacity and limit access to additional capital for exploration and development activities.

Oil and natural gas prices do not necessarily move in tandem, and periods of low prices or limited storage or transportation capacity may adversely affect our financial condition by reducing revenues, operating income, and cash flows, causing production curtailments or shut-ins, rendering certain properties uneconomic, and limiting our liquidity and ability to fund capital expenditures.

*Our results of operations may be negatively impacted by current global political and economic events, including evolving trade policies, tariffs, and broader geopolitical instability.*

Our business is subject to risks and uncertainties arising from volatility in political, legal, and regulatory environments, including changes in U.S. presidential administrations, shifting energy and trade policies, and increased geopolitical tensions. Ongoing armed conflicts, including the war between Russia and Ukraine and instability in the Middle East, as well as other regional conflicts or civil unrest in crude oil and natural gas producing areas, may contribute to commodity price volatility and supply disruptions.

Escalating trade tensions and a more fragmented global trade environment, including between the United States and key trading partners such as China, Mexico, and Canada, have resulted in, and may continue to result in, tariffs, sanctions, export controls, or other trade restrictions. These measures, as well as efforts to reshore or diversify critical supply chains, may increase costs and limit the availability of equipment, materials, and services required for our operators’ drilling and development activities.

At the same time, energy security policies and regulatory initiatives in the United States and abroad may seek to increase domestic oil and natural gas production, which could alter supply-demand dynamics and exert downward pressure on commodity prices. These factors, individually or collectively, could adversely affect our results of operations, financial condition, and cash flows.

*Changes in environmental laws, could increase our operators’ costs and adversely impact our business, financial condition, and cash flows.*

In recent years, U.S. federal and state governments have considered or implemented legislation and regulatory initiatives aimed at GHG emissions, including methane and carbon dioxide. Such measures, including potential emissions fees, reporting requirements, or performance standards, could increase operating costs and compliance burdens within the oil and natural gas industry.

In addition, produced water and other fluids associated with oil and natural gas production are commonly disposed of through underground injection wells. Regulators have increasingly focused on the potential link between fluid injection and induced seismicity. As a result, state regulatory agencies, including the Texas Railroad Commission, have imposed restrictions or additional permitting requirements on saltwater disposal wells in certain areas, including portions of the Permian Basin. Further regulation of fluid disposal or seismicity concerns could increase operating costs, limit disposal capacity, and adversely impact the economic viability of drilling and production activities.

*Lower oil and gas prices and other factors may cause us to record ceiling test write-downs.*

We account for our oil and natural gas operations using the full cost method, under which acquisition, exploration, and development costs—including costs of abandoned properties, dry holes, geophysical costs, and lease rentals—are capitalized. Sales or dispositions of oil and natural gas properties are recorded as adjustments to capitalized costs, with no gain or loss recognized. Depletion is calculated using the units-of-production method based on total proved reserves.

Under full cost accounting rules, the net capitalized cost of oil and natural gas properties is subject to a “ceiling limitation” based on 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. The ceiling calculation uses the unweighted arithmetic average first-day-of-the-month prices for oil and natural gas over the preceding 12-month period and is performed quarterly. If capitalized costs exceed the ceiling, the excess must be charged to earnings as a noncash “ceiling test write-down.” While such write-downs do not affect cash flows from operations, they reduce net income and stockholders’ equity.

The risk of ceiling test write-downs increases during periods of low commodity prices. There were no ceiling test impairments recorded during fiscal 2026 or 2025.

#### We must replace reserves we produce.

Our future success depends on our ability to find, develop, or acquire additional economically recoverable oil and gas reserves. Proved reserves will generally decline as reserves are depleted, except to the extent that they are replaced through successful exploration, development, or acquisition activities. The availability of high-quality domestic oil and natural gas opportunities is limited, and competition for such assets is intense; as a result, there can be no assurance that we will be able to identify, complete, or integrate acquisitions on acceptable terms, if at all. If we are unable to replace reserves on an economic basis, our production, revenues, and long-term business prospects could be adversely affected.

*Approximately 19% and 28% of our total estimated net proved reserves at March 31, 2026 and 2025, respectively, were undeveloped, and those reserves may not ultimately be developed.*

Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve estimates assume that these expenditures will be made and that development activities will be successful; however, these assumptions may not prove correct. Delays in the development, increased development costs, lower commodity prices, capital constraints, or unsuccessful drilling results could reduce future net revenues, decrease estimated proved undeveloped reserves, or render certain projects uneconomic. If third-party operators or we do not invest the capital required to develop these reserves, or if development efforts are unsuccessful, we may be required to write off such reserves. Any resulting write-offs could reduce our borrowing capacity and adversely affect the value of our common stock.

*Information concerning our reserves and future net revenue estimates is inherently uncertain.*

Reserve estimates are based on engineering and geological data and require significant judgment in interpreting such data and projecting future production rates, development timing, and associated expenditures. Reserve engineering is an inherently subjective process that involves estimates of subsurface oil and gas accumulations that cannot be measured precisely.

Estimates of economically recoverable reserves and future net cash flows depend on a number of assumptions, including future production levels, commodity prices, operating costs, development costs, and remedial expenditures, all of which may differ materially from actual results. As a result, reserve estimates and related cash flow projections may vary significantly over time.

As required by the SEC, estimated future net cash flows from proved reserves are calculated using a 12-month unweighted arithmetic average of first-day-of-the-month oil and gas prices for the period preceding the reporting date. Actual future prices and costs may differ materially from those used in such estimates, which could result in significant revisions to reported reserves and associated valuations.

*A negative 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 local markets based on regional supply and demand conditions. As a result, the prices we receive may differ from benchmark prices such as those of the New York Mercantile Exchange (“NYMEX”), with the difference referred to as a differential. Differentials may be affected by a variety of factors, including refinery and pipeline capacity, pipeline specifications, midstream and downstream disruptions, trade restrictions, governmental regulations, and regional demand conditions. In addition, insufficient pipeline capacity, lack of demand, or other regional factors may cause differentials to widen in certain producing areas. During fiscal 2026, our average differentials were $2.97 per Bbl of oil and ($1.48) per Mcf of gas. Changes in these differentials could materially affect our revenues and cash flow from operations, with favorable differentials increasing realized prices and unfavorable differentials decreasing them.

*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 that are 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 acquire new reserves. Historically, we have funded capital expenditures through cash flow from operations and borrowings under our credit facility; however, lower oil and natural gas prices or production levels may limit these funding sources. Volatility in commodity prices, the timing of drilling programs, and drilling results directly affect cash flow from operations. Lower prices or production levels would reduce revenues and cash flows, thereby limiting the financial resources available to fund capital expenditures and pursue drilling opportunities.

Availability under our credit facility is determined periodically by our lenders and is based in part on estimates of our oil and natural gas reserves. Reductions in reserve estimates (whether due to lower commodity prices, production declines, drilling results, changes in reserve engineering assumptions, or lender determination practices) could reduce the borrowing base and, in turn, the amount available under the facility. Any such reduction could limit our liquidity and ability to fund exploration and development activities.

If cash flow from operations or borrowing availability declines for any reason, our ability to undertake capital programs and replace production could be adversely affected.

*Our business depends on oil and natural gas transportation facilities that 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 policies, 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 operated by third parties that exercise exclusive control over such operations pursuant to joint operating agreements and other contractual arrangements. Accordingly, we rely on third-party operators to conduct operations and may not be able to maximize the value of these properties in the manner we believe appropriate, or at all.

We have limited or no control over key operational decisions, including the timing and nature of drilling and development activities, capital expenditures, and technology selection. The success and timing of operations are also dependent on the operator’s technical expertise, financial resources, and ability to obtain approvals from other participants.

A third-party operator’s failure to perform adequately, breach of applicable agreements, or actions adverse to our interests could reduce production and revenues, adversely affect liquidity, increase capital requirements beyond current plans, and have a material adverse effect on our business, 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 substantially greater financial and personnel resources than we do. As a result, we may be at a competitive disadvantage in acquiring reserves and development opportunities. Our ability to acquire and develop additional properties will depend on our ability to identify, evaluate, and acquire suitable producing properties and development prospects.

*We may not be insured against all of the operating hazards to which our business is exposed.*

Our operations are subject to risks inherent in the exploration, development, and production of oil and gas, including blowouts, fires, and other casualties. Although we maintain insurance coverage customary for similar operations, losses may result from uninsured risks or from claims that exceed our insurance coverage limits.

*Changes in effective tax rates or laws could adversely impact our results of operations.*

Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including changes in the valuation of our deferred tax assets and liabilities, the tax effects of stock-based compensation, or changes in tax laws, regulations, or interpretations thereof.

In particular, U.S. federal tax policy remains subject to significant legislative activity and uncertainty, including comprehensive tax legislation proposals such as the “One Big Beautiful Bill” and other similar measures that may modify corporate tax rates, limit deductions, or otherwise change the taxation of energy companies. In addition, prior and future legislative proposals have considered changes to tax provisions historically utilized by crude oil and natural gas exploration and production companies, including percentage depletion allowances, intangible drilling and development cost deductions, deductions related to production activities, and amortization periods for geological and geophysical expenditures.

The enactment of any such legislation or regulatory changes that alter, eliminate, or defer tax deductions or otherwise increase the tax burden on the industry could adversely affect our business, financial condition, results of operations, and cash flows.

*Our reliance on information technology, including information technologies hosted by third parties, exposes us to cybersecurity risks that could affect our business, financial condition, or reputation.*

Our reliance on information technology, including systems hosted or managed by third parties, exposes us to cybersecurity risks that could adversely affect our business, financial condition, or results of operations. The oil and natural gas industry is increasingly dependent on digital technologies to conduct exploration, development, production, and processing activities, including seismic data interpretation, drilling operations, production equipment and gathering systems management, reservoir modeling and reserves estimation, and the processing and recording of financial and operational data. At the same time, cyber incidents, including deliberate attacks and unintentional events, have increased in frequency and sophistication. The U.S. government has issued public warnings indicating that energy assets may be targeted by cybersecurity threats.

Our systems, as well as those of our operators, vendors, suppliers, and other business partners, may be subject to cyberattacks, information security breaches, or other cybersecurity incidents that could result in unauthorized access to, misuse, loss, or destruction of proprietary and other information, or disruption of business activities. In addition, certain cyber incidents, such as surveillance or other advanced persistent threats, may remain undetected for extended periods. Our existing protective measures may not be sufficient to prevent or detect such incidents, and we may need to expend additional resources to enhance our cybersecurity measures, investigate incidents, or remediate vulnerabilities as threats continue to evolve.

*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, 2026, we do not have key-man insurance for the lives of Mr. Taylor and Ms. McComic. The unexpected loss of the services of one or more of these individuals could significantly and adversely affect our operations.

#### We may be affected by one substantial shareholder.

Nicholas C. Taylor beneficially owns approximately 46% of our common stock and serves as our Chairman of the Board and Chief Executive Officer, giving him 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 perception and adversely affect 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, 2026, our executive officers and directors beneficially owned approximately 49% of our common stock. These stockholders, if acting together, would be able to significantly influence 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. Our common stock has a relatively low trading volume, and the market price of our common stock has experienced, and could continue to experience, volatility due to factors 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.

## Cybersecurity

As filed, 1,992 characters.

Mexco maintains a risk-based cybersecurity program designed to protect the confidentiality, integrity, and availability of information systems and data used in our operations. The program includes technical, administrative, and organizational safeguards intended to identify, assess, and mitigate cybersecurity risks.

***Risk Management and Strategy.*** Cybersecurity risk is integrated into our overall risk management processes. We use internal policies and controls, supported by third-party cybersecurity professionals, to monitor and respond to cybersecurity threats. We maintain systems to detect and respond to potential cybersecurity incidents.

Employees receive periodic cybersecurity awareness training. We implement access controls based on the principle of least privilege. We also conduct periodic testing of our incident response capabilities, including tabletop exercises, and maintain an incident response plan that outlines procedures for identifying, escalating, investigating, and responding to cybersecurity incidents.

***Governance.*** The Board of Directors, through the Audit Committee, oversees cybersecurity risk. Management is responsible for implementing and maintaining cybersecurity controls and for day-to-day risk management activities. The Board and Audit Committee receive periodic updates on cybersecurity risks and are notified of material cybersecurity incidents in accordance with our incident response processes.

***Impact of Risks from Cybersecurity Threats.*** As of the date of this report, we are not aware of any cybersecurity threats that have materially affected, or are reasonably likely to materially affect, the Company’s business, financial condition, or results of operations. However, we may not be able to prevent all cybersecurity incidents, and future incidents could have a material adverse effect on the Company.

For more information on our cybersecurity-related risks, see “Item 1A. Risk Factors” above for additional information.

## Properties

As filed, 13,172 characters.

Our properties consist primarily of oil and gas wells and ownership interests in leasehold acreage, both developed and undeveloped. As of March 31, 2026, we had interests in approximately 8,100 gross (26.1 net) producing oil and gas wells and owned leasehold mineral, royalty and other interests in approximately 705,000 gross (2,697 net) acres.

Oil and Natural Gas Reserves

In accordance with current SEC rules, the average prices used in computing reserves at March 31, 2026 were $62.76 per bbl of oil compared to $73.79 in 2025, a decrease of 15%, and $2.24 per mcf of natural gas compared to $2.14 in 2025, an increase of 5%. These prices are based on the 12-month unweighted arithmetic average of the first-day-of-the-month market prices for oil and natural gas sales during fiscal 2026. The benchmark price of $59.79 per bbl of oil at March 31, 2026 versus $71.00 at March 31, 2025, was adjusted by lease for gravity, transportation fees and market differentials and did not give effect to derivative transactions. The benchmark price of $3.72 per mcf of natural gas at March 31, 2026 versus $2.44 at March 31, 2025, 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, the present value of future net revenues discounted at 10%, and related changes, see the Notes to the Company’s consolidated financial statements.

Proved oil and natural gas reserves are those quantities of oil and gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic and operating conditions. Proved developed reserves are those expected to be recovered from existing wells, equipment, and operating methods. Proved undeveloped reserves are those expected to be recovered from new wells on undrilled acreage or from existing wells requiring significant additional investment to establish production.

Mexco’s proved reserves as of March 31, 2026 and 2025 were prepared by Russell K. Hall and Associates, Inc., Environmental Engineering Consultants (“Hall and Associates”), an independent petroleum engineering firm located in Midland, Texas. A summary of their report is filed as Exhibit 99.1 to this Annual Report.

Management is responsible for providing accurate technical and operating data to Hall and Associates and for maintaining internal controls over the reserve estimation process to provide reasonable assurance that proved reserve estimates are calculated in accordance with SEC rules. Our Chief Financial Officer reviews the final reserves estimate and consults with Alan Neal, the representative at Hall and Associates responsible for evaluating the proved reserves covered by this report. Our Chairman and Chief Executive Officer also reviews the final reserves report.

Estimates of proved reserves are inherently imprecise and subject to change as additional data becomes available. These estimates are based on engineering and geological interpretation and require assumptions regarding production rates, future development costs, operating expenses, and commodity prices. Actual results will vary from these estimates, and such variances could be material and may adversely affect future cash flows, results of operations, and capital resources.

In accordance with SEC rules, reserve estimates and related present value calculations use the 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas. Prices are held constant over the economic life of the properties. Actual future prices and costs may differ materially from those used in these estimates. Unless replaced through acquisitions, successful exploration, or development activities, proved reserves will decline as production occurs.

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

| Oil (Bbls): | March 31, 2026 | 2025 |
| --- | ---: | ---: |
| Proved developed – Producing | 387,670 | 390,940 |
| Proved developed – Non-producing | 75,105 | 14,900 |
| Proved undeveloped | 195,840 | 269,000 |
| Total | 658,615 | 674,840 |
| Natural gas (Mcf): |  |  |
| Proved developed – Producing | 3,902,120 | 3,554,920 |
| Proved developed – Non-producing | 302,490 | 99,970 |
| Proved undeveloped | 466,060 | 704,810 |
| Total | 4,670,670 | 4,359,700 |
| Total net proved reserves (BOE) (1) | 1,437,060 | 1,401,460 |
| PV-10 Value (2) | $21,131,000 | $23,216,000 |
| Present value of future income tax discounted at 10% | (2,466,000) | (3,141,000) |
| Standardized measure of discounted future net cash flows (3) | $18,665,000 | $20,075,000 |
| Prices used in calculating reserves: (4) |  |  |
| Natural gas (per Mcf) | $2.24 | $2.14 |
| Oil (per Bbl) | $62.76 | $73.79 |

(1) These reserve estimates do not include the Company’s interest in two LLCs referred to in Item 1. Business – Company Profile.

(2) PV-10 represents the present value of estimated future net cash flows attributable to our proved oil and natural gas reserves, before income taxes, discounted at 10% per annum. PV-10 is a non-GAAP financial measure. It is relevant to investors because it provides a standardized basis for comparing the relative size and value of proved reserves across companies and excludes the impact of future income taxes. We use PV-10 internally to evaluate the economic attractiveness of our oil and natural gas properties. The standardized measure of discounted future net cash flows is derived from PV-10 after deducting estimated future income taxes.

(3) In accordance with SEC requirements, the standardized measure of discounted future net cash flows is calculated using 12-month average first-day-of-the-month prices for oil and natural gas. Future cash flows are estimated based on expected production from proved reserves, reduced by estimated future development and production costs (based on year-end costs) and estimated future income taxes (based on year-end statutory tax rates, including consideration of enacted future rate changes and available tax attributes). All calculations assume continuation of existing economic conditions and constant prices and costs over the life of the reserves.

(4) These prices reflect adjustments by lease for quality, transportation fees, and market differentials.

During fiscal 2026, we added proved reserves of 247 thousand BOE (“MBOE”) through extensions and discoveries, added 39 MBOE through acquisitions, and added 53 MBOE for upward revisions of previous estimates. Such upward revisions are primarily attributable to improved well performance, revisions to estimated future recoveries based on additional production history, and changes in the timing of future development activities. The reduction in proved undeveloped reserves was primarily attributable to properties in Lea County, New Mexico, due to changes in the timing of future development in wells in which we own a working interest. These interests are held by production and remain in place for future development.

During the fiscal year ending March 31, 2026, we had a working or royalty interest in the development of 25 wells, converting reserves of approximately 48,000 BOE from proved undeveloped to proved developed – producing with a capital cost of approximately $119,000.

Oil and natural gas prices significantly impact the calculation of PV-10 and the standardized measure of discounted future net cash flows. These measures do not represent an estimate of the fair value of the Company’s proved reserves. Any estimate of fair value would also consider, among other factors, expected changes in future prices and costs, recovery of reserves beyond proved reserves, and a discount rate more reflective of the time value of money and associated risks.

Future prices and costs may differ materially from those used in these estimates. The 10% discount rate required by Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 932, *Extractive Activities—Oil and Gas*, may not be the most appropriate rate for all purposes. In addition, the present value calculations are highly sensitive to assumptions regarding the timing of future production, which may prove 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 authorities or agencies during the year ended March 31, 2026, 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:

| Exploratory Wells | Year Ended March 31, 2026 Gross | Net | 2025 Gross | Net |
| --- | ---: | --- | ---: | --- |
| Beginning wells in progress | - | - | - | - |
| Wells spud | 1 | .02 | 1 | .10 |
| Successful wells | 0 | - | 0 | - |
| Ending wells in progress | - | - | - | - |
| Development Wells |  |  |  |  |
| Beginning wells in progress | 17 | .03 | 16 | .17 |
| Wells spud | 58 | .19 | 38 | .09 |
| Successful wells | (55) | (.08) | (37) | (.23) |
| Ending wells in progress | 20 | .14 | 17 | .03 |

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 177 gross wells (.07 net wells) on Company-owned minerals and royalties at no expense to the Company. We expect production from our mineral interests to 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 laterals that 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, 2026, we held an interest in approximately 8,100 gross (26.1 net) productive wells, including approximately 7,000 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, 2026:

|  | Acreage Gross | Net |
| --- | ---: | ---: |
| Texas | 387,100 | 1,497 |
| North Dakota | 68,600 | 27 |
| Oklahoma | 66,900 | 800 |
| Louisiana | 55,600 | 101 |
| Ohio | 35,800 | 4 |
| Wyoming | 30,700 | 15 |
| New Mexico | 30,700 | 182 |
| Colorado | 10,300 | 21 |
| Kansas | 8,500 | 41 |
| Montana | 7,200 | 1 |
| Arkansas | 1,600 | 5 |
| Alabama | 1,000 | 2 |
| South Dakota | 600 | - |
| Virginia | 100 | 1 |
| Total | 704,700 | 2,697 |

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:

| Oil (a): | Years Ended March 31, 2026 | 2025 |
| --- | ---: | ---: |
| Production (Bbls) | 82,133 | 83,564 |
| Revenue | $5,276,981 | $6,145,674 |
| Average Bbls per day (d) | 225 | 229 |
| Average sales price per Bbl | $64.25 | $73.54 |
| Gas (b): |  |  |
| Production (Mcf) | 681,794 | 570,012 |
| Revenue | $1,271,067 | $970,811 |
| Average Mcf per day (d) | 1,868 | 1,562 |
| Average sales price per Mcf | $1.86 | $1.70 |
| Total BOE (c) | 195,765 | 178,566 |
| Production costs: |  |  |
| Production expenses: | $936,975 | $1,043,202 |
| Production expenses per BOE | $4.09 | $5.84 |
| Production expenses per sales dollar | $0.14 | $0.15 |
| Production and ad valorem taxes: | $491,378 | $561,894 |
| Production and ad valorem taxes per BOE | $2.14 | $3.15 |
| Production and ad valorem taxes per sales dollar | $0.08 | $0.08 |
| Total oil and gas revenue | $6,548,048 | $7,116,485 |

(a) Includes condensate.

(b) Includes natural gas liquids.

(c) Natural gas production is converted to oil production at a ratio of six Mcf to one Bbl of oil.

(d) Calculated on a 365-day year.

## Legal proceedings

As filed, 437 characters.

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.

## Management's discussion and analysis

As filed, 33,589 characters.

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 activities through cash flows from operating activities, borrowings under our credit facility, sales of non-core properties, and issuances of common stock. Our primary source of long-term value is our oil and gas reserve base. Our producing oil and gas properties are pledged as collateral under our credit facility. We do not have any contractual commitments to deliver fixed quantities of our oil and gas under existing agreements.

Our long-term strategy is to increase profit margins by focusing on acquiring and developing oil and gas properties with low-cost operations and the potential for long-lived production. We focus our efforts on the acquisition of royalties and non-operated working interests in areas with significant development potential.

### 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, 2026 | 2025 | Change |
| --- | ---: | ---: | ---: |
| Net cash provided by operating activities | $3,779,152 | $4,269,621 | $(490,469) |
| Net cash used in investing activities | $(2,540,161) | $(4,154,575) | $1,614,414 |
| Net cash used in financing activities | $(216,970) | $(834,575) | $617,605 |

**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, 2026 was $3,779,152 in comparison to $4,269,621 for the year ended March 31, 2025. This decrease of $490,469 in our cash flow from operating activities consisted of an increase in our non-cash expenses of $245,850; a decrease in income tax payable of $179,147; an increase in our accounts receivable of $47,152; a decrease of $102,146 of our accounts payable and accrued expenses, and a decrease in our net income for the current year of $406,646. Variations in cash flow from operating activities may affect our level of exploration and development expenditures.

Our expenditures in operating activities consist primarily of drilling expenses, production expenses, and engineering services. Our expenses also include employee compensation, accounting, insurance, and other general and administrative expenses incurred to support the 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, 2026, net cash used for additions to oil and gas properties, net of drilling refunds and proceeds from property sales, was $2,109,157 compared to $3,154,575 in fiscal 2025. Cash used for an investment in a limited liability company was $427,429, compared to $1,000,000 in fiscal 2025.

**Cash Flow Used in Financing Activities.** Cash flow from financing activities is derived from changes in long-term debt and in equity account balances. Net cash flow used in our financing activities was $216,970 for the year ended March 31, 2026, compared to $834,575 for the year ended March 31, 2025. During the year ended March 31, 2026, we expended $204,600 to pay the annual dividend and $12,370 to amend our credit facility. During the year ended March 31, 2025, we expended $209,000 to pay the annual dividend and $703,216 to purchase 57,766 shares of our stock for the treasury account, and received proceeds of $77,641 from the exercise of employee stock options.

Accordingly, net cash increased $1,022,021, leaving cash and cash equivalents on hand of $2,775,976 as of March 31, 2026.

We had working capital of $3,995,456 as of March 31, 2026, compared to $2,469,664 as of March 31, 2025, an increase of $1,525,792 for the reasons set forth below.

### Oil and Natural Gas Property Development

**New Participations in Fiscal 2026.** The Company participated in the development of 57 horizontal wells and one vertical well at a cost of approximately $1,250,000 for the year ending March 31, 2026. Twenty of these wells have not been completed. Fifty-one of these wells are in the Delaware Basin located in the western portion of the Permian Basin in Lea and Eddy Counties, New Mexico. The remaining wells are in Glasscock, Midland, and Ward Counties, Texas.

In addition to the above working interests, there were 177 gross wells (.07 net wells) drilled by other operators on Mexco’s royalty interests and 261 gross wells (.12 net wells) obtained through acquisitions.

Mexco expended approximately $230,000 to participate in the drilling and completion of five horizontal wells in the Bone Spring formation of the Delaware Basin in Eddy County, New Mexico. In November 2025, two of these wells were completed with initial average production rates of 1,194 barrels of oil, 2,924 barrels of water, and 1,819,000 cubic feet of gas per day, or 1,497 BOE per day. In February 2026, the remaining three wells were completed with initial average production rates of 974 barrels of oil, 2,971 barrels of water, and 1,417,000 cubic feet of gas per day, or 1,210 BOE per day. Mexco’s working interest in these wells is .5%.

Mexco expended approximately $79,000 to drill and complete two horizontal wells in the Bone Spring formation of the Delaware Basin in Lea County, New Mexico. In August 2025, these wells were completed with initial average production rates of 741 barrels of oil, 3,276 barrels of water, and 1,110,000 cubic feet of gas per day, or 926 BOE per day. Mexco’s working interest in these wells is .3%.

Mexco expended approximately $155,000 to participate in the drilling and completion of three horizontal wells in the Wolfcamp Sand Formation of the Delaware Basin in Lea County, New Mexico. In December 2025, these wells were completed with initial average production rates of 827 barrels of oil, 3,483 barrels of water, and 2,354,000 cubic feet of gas per day, or 1,219 BOE per day. Mexco’s working interest in these wells is .52%.

Mexco expended approximately $65,000 to participate in an exploratory vertical well in the Ellenburger formation of Ward County, Texas. In November 2025, this well was determined to be noncommercial.

In December 2025, Mexco expended approximately $406,000 to participate in the drilling and completion of two horizontal development wells in the Wolfcamp XY formation of the Delaware Basin in Eddy County, New Mexico. Mexco’s working interest in these wells is 2.1%.

In December 2025, Mexco expended approximately $46,000 to participate in the drilling and completion of six horizontal wells in the Bone Spring formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .04%.

In March 2026, Mexco expended approximately $200,000 to participate in the drilling and completion of five horizontal wells in the Wolfcamp B formation in the Spraberry trend area of the Midland Basin in Midland and Glasscock Counties, Texas. Mexco’s working interest in these wells is 1.9%. Subsequently, in May 2026, the Company expended an additional approximately $35,000 for these wells.

Subsequently, in May 2026, Mexco expended approximately $460,000 to participate in the drilling and completion of six horizontal wells in the Wolfcamp A formation of the Delaware Basin in Reeves County, Texas. Mexco’s working interest in these wells is .8%.

**Completion of Wells Drilled in Fiscal 2025.** The Company expended approximately $150,000 to complete seventeen horizontal wells in which the Company participated during fiscal 2025. These wells, located in the Delaware Basin of Lea County, New Mexico, have been completed and turned to production.

**Investments.** In October 2022, the Company made an approximately 2% equity investment commitment in a limited liability company amounting to $2,000,000, which was fully funded as of July 2025. The limited liability company is capitalized at approximately $100 million to acquire mineral interests in the Utica and Marcellus formations in the state of Ohio. In October 2025, the Company expended $200,000 to exercise its option to participate in a voluntary optional cash call to increase its capitalized investment. In December 2025, the Company expended an additional $27,429 to exercise its option to acquire its share of the non-consenting interests from the October cash call. As of March 31, 2026, this LLC has returned $558,216, or 25% of the total investment.

**Acquisitions.** In May 2025, the Company acquired royalty (mineral) interests in 2 wells operated by Chevron Corporation in Pecos County, Texas for a purchase price of $40,000. This acquisition was effective April 1, 2025 and includes acreage for future development.

In August 2025, the Company acquired royalty interests in 12 producing wells operated by Diamondback Energy, Inc. in Martin County, Texas for a purchase price of $60,300 and royalty interests in 25 wells operated by Chevron Corporation in Weld County, Colorado for a purchase price of $26,300. These acquisitions were effective September 1, 2025.

In October 2025, the Company acquired royalty interests in 3 producing wells operated by Expand Energy Corporation in Caddo Parish, Louisiana for a purchase price of $31,300; royalty interests in 14 producing wells operated by Diamondback Energy, Inc. in Martin County, Texas for a purchase price of $44,300; royalty interests in 3 producing wells operated by Permian Resources Corporation in Eddy County, New Mexico for a purchase price of $6,800; and overriding royalty interests in 4 producing wells operated by Tap Rock Resources in Eddy County, New Mexico for a purchase price of $240,300. These acquisitions were effective November 1, 2025.

In December 2025, the Company acquired royalty interests in 14 producing wells operated by Occidental Petroleum Corporation in Weld County, Colorado for a purchase price of $35,300; royalty interests in approximately 4 producing wells operated by SM Energy Company in Howard County, Texas for a purchase price of $100,600; and royalty interests in 11 producing wells operated by Ovintiv Inc. in Martin County, Texas for a purchase price of $18,300. These acquisitions were effective December 1, 2025.

Also in December 2025, the Company acquired additional royalty interests in the 3 producing wells operated by Expand Energy Corporation in Caddo Parish, Louisiana for a purchase price of $22,300 and effective January 1, 2026.

In January 2026, the Company acquired royalty interests in 3 producing wells operated by ConocoPhillips in Karnes County, Texas for a purchase price of $27,800. This acquisition is effective January 1, 2026.

In February 2026, the Company acquired royalty interests in 41 producing wells operated by Occidental Petroleum Corporation and 15 producing wells operated by Bison IV Operating LLC in Weld County, Colorado, for an aggregate purchase price of $69,600; royalty interests in 29 producing wells operated by Brammer Petroleum, Sheridan Production and TGNR East Texas in Harrison and Panola Counties, Texas as well as additional interest in 19 producing wells in which we already held an interest for a purchase price of $43,100; royalty interests in 6 producing wells and additional interest in 5 producing wells operated by Aethon Energy Operating in Bienville Parish, Louisiana for a purchase price of $4,300; royalty interest in 1 producing well operated by San Juan Resources, Inc. for a purchase price of $3,800; royalty interests in 81 producing wells and additional interest in 10 producing wells in multiple counties in Louisiana and Texas for a purchase price of $41,800; and a leasehold in 40 undeveloped net acres in Eddy County, New Mexico for a purchase price of $1,500. All of these acquisitions were effective March 1, 2026.

**Other Projects.** 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.

**Pricing.** Crude oil and natural gas prices remained volatile over 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 $51.25 per bbl in December 2025 to a high of $98.86 per bbl in March 2025. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $2.65 per MMBtu in June and October 2025 to a high of $30.72 per MMBtu in January 2026, reflecting a temporary price spike during a period of severe weather and significant market volatility.

On March 31, 2026, the WTI posted price for crude oil was $97.36 per bbl and the Henry Hub spot price for natural gas was $2.88 per MMBtu. See Results of Operations below for realized prices. Pipeline capacity constraints and maintenance in the Permian Basin area have contributed to a wider difference between the Waha Hub and the Henry Hub, and at times realized prices were negative.

### Results of Operations

### Fiscal 2026 Compared to Fiscal 2025

We had net income of $1,305,722 for the year ended March 31, 2026, compared to $1,712,368 for the year ended March 31, 2025, a 24% decrease, primarily as a result of a decrease in operating revenues partially offset by a decrease in operating expenses as further explained below.

*Oil and natural gas sales.* Revenue from oil and natural gas sales was $6,548,048 for the year ended March 31, 2026, an 8% decrease from $7,116,485 for the year ended March 31, 2025. This resulted from an increase in natural gas production volumes and natural gas prices, partially offset by a decrease in oil production volumes and oil prices. The following table sets forth our oil and natural gas revenues, production quantities, and average prices received during the fiscal years ended March 31:

| Oil: | 2026 | 2025 | % Difference |
| --- | ---: | ---: | ---: |
| Revenue | $5,276,981 | $6,145,674 | (14.1)% |
| Volume (bbls) | 82,133 | 83,564 | (1.7)% |
| Average Price (per bbl) | $64.25 | $73.54 | (12.6)% |
| Gas: |  |  |  |
| Revenue | $1,271,067 | $970,811 | 30.9% |
| Volume (mcf) | 681,794 | 570,012 | 19.6% |
| Average Price (per mcf) | $1.86 | $1.70 | 9.7% |

*Income from investments in LLCs*. Income from investments in LLCs increased 51% to $329,102 in fiscal 2026 from $217,627 in fiscal 2025. This increase resulted primarily from higher earnings from one of the Company’s limited liability companies.

*Interest income.* Interest income on corporate funds increased 23% to $89,341 in fiscal 2026 from $72,629 in fiscal 2025. This increase resulted from an increase in our investment fund balances.

*Production and exploration.* Production costs were $1,428,353 in fiscal 2026, an 11% decrease from $1,605,096 in fiscal 2025. This is the result of a decrease in lease operating expenses on wells in which we own a working interest and a decrease in production taxes due to the decrease in oil and gas revenues.

*Depreciation, depletion and amortization.* Depreciation, depletion and amortization (“DD&A”) expense was $2,523,827 in fiscal 2026, a 3% increase from $2,452,694 in fiscal 2025. This was primarily due to an increase in gas production, partially offset by an increase in gas reserves and a decrease in the full cost amortization base.

*General and administrative expenses.* General and administrative expenses were $1,306,275 for the year ended March 31, 2026, a 1% decrease from $1,320,074 for the year ended March 31, 2025. This was primarily due to an increase in accounting and engineering services, partially offset by a decrease in contract services and employee stock option compensation.

*Income taxes.* Income tax for fiscal 2026 was $379,043 compared to $304,330 for fiscal 2025. The combined federal and state effective tax rate for fiscal 2026 and fiscal 2025 was 22.5% and 15.1%, respectively. See Note 5 – Income Taxes to the Notes to Consolidated Financial Statements for additional information.

### Contractual Obligations

We have no off-balance sheet debt or unrecorded obligations, and we 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, 2026:

| Contractual obligations: | Payments due in: Total | less than 1 year | 1 - 3 years | over 3 years |
| --- | ---: | ---: | ---: | ---: |
| Leases (1) | $80,427 | $60,320 | 20,107 | $- |

(1) The lease amount represents the monthly rent amount for our principal office space in Midland, Texas under a 36-month lease agreement expiring July 31, 2027. Of this total obligation for the remainder of the lease, our majority shareholder will pay $10,175 within 1 year and $3,392 in years 1-3 for his portion of the shared office space.

### Alternative Capital Resources

Although we have primarily used cash from operating activities, the sale 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 policies are those that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe inherently uncertain matters.

**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 exclude any costs related to production, general corporate overhead, or similar activities. The carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation (“ARO”) when incurred.

Sales of oil and natural gas properties, whether or not currently being amortized, are accounted for as adjustments to capitalized costs. 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. This includes any sales of properties such as Term Assignments and Assignments, Bills of Sale and Conveyances.

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, lease, or field basis rather than 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 those of companies that apply the successful efforts method, since we will generally reflect a higher level of capitalized costs and 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 periods of commodity price volatility 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 the 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 of our oil and gas properties does not affect 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 if higher crude oil and natural gas prices 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 demonstrate, 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 actual future 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 (“GAAP”), management is required to make informed judgments, estimates, and assumptions that affect the reported amounts of assets and liabilities as of the date of the consolidated financial statements and affect the reported amounts of revenues and expenses during the reporting period. In addition, significant estimates are used in determining proved oil and gas reserves. Although management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates. The estimate of the Company’s oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect these reported results.

**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.** Revenues from our royalty and non-operated working interest properties are recorded in accordance with ASC 606, Revenue from Contracts with Customers. Revenue is reported net of post-production costs when such costs are contractually deducted by the operator prior to distribution. Since the revenue checks are generally received two to three months after the production month, the Company accrues for revenue earned but not received by estimating production volumes and product prices. Any identified differences between the Company’s revenue estimates and actual revenue received historically have not been significant.

**Asset Retirement Obligations**. The Company records a liability for asset retirement obligations (“ARO”) associated with the plugging, abandonment, and remediation of oil and natural gas wells and related facilities in the period the obligation is incurred. The liability is recorded at estimated fair value, with a corresponding increase to the carrying amount of the related oil and natural gas property.

The capitalized asset retirement cost is depleted using the unit-of-production method over the life of the related proved reserves. The ARO liability is measured using the present value of estimated future cash flows. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

Estimating ARO requires management to make significant assumptions and judgments regarding the timing and amount of future abandonment and remediation costs, inflation rates, discount rates, and other factors. Revisions to these estimates are recorded as adjustments to both the ARO liability and the carrying amount of the related asset.

**Stock-based Compensation**. The Company uses the Binomial option pricing model to estimate the grant-date fair value of stock-based awards. Compensation expense is recognized within general and administrative expense in the Consolidated Statements of Operations using the graded-vesting method over the applicable vesting period.

**Accounts Receivable.** Accounts receivable includes trade receivables from joint interest owners and oil and gas purchasers. Credit is extended based on an evaluation of a customer’s financial condition and is generally uncollateralized. The collectibility of receivables is assessed and an allowance is made for any credit losses. The allowance for credit losses is determined based on a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole.

**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 utilizes the measurement alternative to account for investments when it does not possess the ability to exercise significant influence or control and the investment does not have a readily determinable fair value. Under this method, investments are initially recognized at cost and subsequently measured at cost, adjusted for any observable changes in the fair value of the investment. In addition, the Company reviews the carrying value of investments measured under the measurement alternative for impairment on a regular basis. If there is an indication of impairment, the Company assesses whether the carrying value of the investment exceeds its recoverable amount. Any impairment losses are recognized in the consolidated statements of operations. Income from these investments is recognized as Income from investments in LLCs in the consolidated statements of operations.

**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.

**Segments.** The Company’s chief operating decision maker (“CODM”), comprised of the Chairman of the Board and the President, evaluates operating results and allocates capital resources on a consolidated basis. Accordingly, the Company has one reportable segment: crude oil and natural gas development, exploration, and production.

**Leases.** The Company determines that an arrangement is a lease at inception. Operating leases are recorded as an operating lease right-of-use asset, an operating lease liability, current, and an 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 the commencement date in determining the present value of lease payments. The incremental borrowing rate used at adoption was 9%. Significant judgment is required when determining the incremental borrowing rate. Rent expense for lease payments is recognized on a straight-line basis over the lease term.

**New Accounting Pronouncements Not Yet Adopted.** In November 2024, the FASB issued ASU 2024-03, Topic 220 Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures: Disaggregation of the Income Statement Expenses. The amendments in this update require disclosure in the Company’s annual and interim consolidated financial statements of specified information about certain costs and expenses, including depletion, depreciation and amortization recognized as part of crude oil and natural gas producing activities, and employee compensation. This ASU is effective for fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. While the adoption of this ASU will modify the Company’s disclosures, it will not have an impact on the Company’s financial position, results of operations, or liquidity.

## Market risk

As filed, 4,164 characters.

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, 2026, our largest credit risk associated with any single purchaser was $474,335 or 37% 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 on the prevailing market prices of, and demand for, oil and natural gas. Prices for oil and natural gas production have 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 $51.25 per bbl in December 2025 to a high of $98.86 per bbl in March 2026. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $2.65 per MMBtu in June and October 2025 to a high of $30.72 per MMBtu in January 2026, reflecting a temporary price spike during a period of severe weather and significant market volatility.

On March 31, 2026, the WTI posted price for crude oil was $97.36 per bbl, and the Henry Hub spot price for natural gas was $2.88 per MMBtu. See Results of Operations above for realized prices. Pipeline capacity constraints and maintenance in the Permian Basin area have contributed to a wider difference between the Waha Hub and the Henry Hub, and at times realized prices were negative. Subsequently, on June 15, 2026, the WTI posted price for crude oil was $76.73, and the Henry Hub posted price for natural gas was $3.06.

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 affect both estimated future net revenues 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 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, not 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 2026, our pretax income would have changed by $821,133. If the average gas price had increased or decreased by one dollar per mcf for fiscal 2026, pretax income would have changed by $681,794.

## Controls and procedures

As filed, 2,544 characters.

**Management’s Annual Report on Internal Control over Financial Reporting.** The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our internal control over financial reporting is supported by appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel, and a written Code of Conduct adopted by our Board and applicable to all directors, officers, and employees of Mexco.

Our chief executive officer and chief financial officer assessed the effectiveness of our internal control over financial reporting using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in the 2013 “Internal Control—Integrated Framework”. Based upon that evaluation, our chief executive officer and chief financial officer concluded that our internal control over financial reporting was effective as of March 31, 2026.

**Evaluation of Disclosure Controls and Procedures.** We maintain disclosure controls and procedures to ensure that the information we must disclose in our filings with the SEC is recorded, processed, summarized and reported on a timely basis. At the end of the period covered by this report, our principal executive officer and principal financial officer reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e). Based on such evaluation, such officers concluded that, as of March 31, 2026, our disclosure controls and procedures were effective.

**Changes in Internal Control over Financial Reporting.** No changes in the Company’s internal control over financial reporting occurred during the year ended March 31, 2026 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Filed Jun 29, 2026.
Source: SEC EDGAR, the filing index for accession 0001493152-26-030386. Last ingested by Listed: Oct 24, 2026, 14:53 ET. No prices; not investment advice.