UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended March 31, 2025

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 1-31785

MEXCO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Colorado

84-0627918

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

415 W. Wall, Suite 475		(432) 682-1119
Midland, Texas 79701		(Registrant’s telephone number, including area code)
(Address of principal executive offices, Zip Code)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

Title of each class		Trading Symbol(s)		Name of each exchange on which registered
Common Stock, par value $0.50 per share		MXC		NYSE American

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐

Indicate by check-mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve (12) months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past ninety (90) days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or and emerging growth company. See definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act:

Large Accelerated Filer ☐ Accelerated Filer ☐ Non-Accelerated Filer ☒ Smaller Reporting Company ☒ Emerging Growth Company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.1D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

The aggregate market value of the voting stock held by non-affiliates of the Registrant as of September 30, 2024 (the last business day of the Registrant’s most recently completed second quarter) was $12,644,291 as computed by reference to the last reported sale.

There were 2,046,000 shares of the registrant’s common stock outstanding as of June 27, 2025.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s Proxy Statement relating to the 2025 Annual Meeting of Shareholders to be held on September 9, 2025, have been incorporated by reference in Part III of this Form 10-K. Such Proxy Statement will be filed with the Commission not later than 120 days after March 31, 2025, the end of the fiscal year covered by this report.

TABLE OF CONTENTS

Cautionary Note Regarding Forward-Looking Statements		3

PART I

Item 1.	Business	3
Item 1A.	Risk Factors	10
Item 1B.	Unresolved Staff Comments	15
Item 1C.	Cybersecurity	16
Item 2.	Properties	16
Item 3.	Legal Proceedings	20
Item 4.	Mine Safety Disclosures	20

PART II

Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	21
Item 6.	Reserved	23
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 8.	Financial Statements and Supplementary Data	31
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	31
Item 9A.	Controls and Procedures	31
Item 9B.	Other Information	32
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspection	32

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	32
Item 11.	Executive Compensation	32
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	32
Item 13.	Certain Relationships and Related Transactions, and Director Independence	32
Item 14.	Principal Accounting Fees and Services	32

PART IV

Item 15.	Exhibits and Financial Statement Schedules	32
Item 16.	Form 10-K Summary	32

Signatures		33

Glossary of Abbreviations and Terms		34

As used in this document, “the Company”, “Mexco”, “we”, “us” and “our” refer to Mexco Energy Corporation and its consolidated subsidiaries.

Abbreviations or definitions of certain terms commonly used in the oil and gas industry and in this Form 10-K can be found in the “Glossary of Abbreviations and Terms”.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”). These forward-looking statements are generally located in the material set forth under the headings “Risk Factors”, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, “Business”, “Properties” but may be found in other locations as well, and are typically identified by the words “could”, “should”, “expect”, “project”, “estimate”, “believe”, “anticipate”, “intend”, “budget”, “plan”, “forecast”, “predict” and other similar expressions.

Forward-looking statements generally relate to our profitability; planned capital expenditures; estimates of oil and gas production; future project dates; estimates of future oil and gas prices; estimates of oil and gas reserves; our future financial condition or results of operations; and our business strategy and other plans and objectives for future operations and are based upon our management’s reasonable estimates of future results or trends. Actual results in future periods may differ materially from those expressed or implied by such forward-looking statements because of a number of risks and uncertainties affecting our business, including those discussed in “Risk Factors”. The factors that may affect our expectations regarding our operations include, among others, the following: our success in development, exploitation and exploration activities; our ability to make planned capital expenditures; declines in our production or prices of oil and gas; our ability to raise equity capital or incur additional indebtedness; our restrictive debt covenants; our acquisition and divestiture activities; weather conditions and events; the proximity, capacity, cost and availability of pipelines and other transportation facilities; increases in the cost of drilling, completion and gas gathering or other costs of production and operations; and other factors discussed elsewhere in this document. We disclaim any intention or obligation to update or revise any forward-looking statements as a result of new information, future events or otherwise.

PART I

ITEM 1. BUSINESS

General

Mexco Energy Corporation, a Colorado corporation, is an independent oil and gas company engaged in the acquisition, exploration, development and production of crude oil and natural gas properties located in the United States. Incorporated in April 1972 under the name Miller Oil Company, the Company changed its name to Mexco Energy Corporation effective April 30, 1980. At that time, the shareholders of the Company also approved amendments to the Articles of Incorporation resulting in a one-for-fifty reverse stock split of the Company’s common stock.

Our total estimated proved reserves at March 31, 2025 were approximately 1.401 million barrels of oil equivalent (“MMBOE”) of which 48% was oil and 52% was natural gas, and our estimated present value of proved reserves was approximately $23 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.

Company Profile

Since our inception, we have been engaged in acquiring and developing oil and gas properties and the exploration for and production of natural gas, crude oil, condensate and natural gas liquids (“NGLs”) within the United States. We especially seek to acquire proved reserves that fit well with existing operations or in areas where Mexco has established production. Acquisitions preferably will contain most of their value in producing wells, behind pipe reserves and high quality proved undeveloped locations. Competition for the purchase of proved reserves is intense. Sellers often utilize a bid process to sell properties. This process usually intensifies the competition and makes it extremely difficult to acquire reserves without assuming significant price and production risks. We actively search for opportunities to acquire proved oil and gas properties. However, because the competition is intense, we cannot give any assurance that we will be successful in our efforts during fiscal 2026.

While we own oil and gas properties in other states, the majority of our activities are centered in West Texas and Southeastern New Mexico. The Company also owns producing properties and undeveloped acreage in fourteen states. We acquire interests in producing and non-producing oil and gas leases from landowners and leaseholders in areas considered favorable for oil and gas exploration, development and production. In addition, we may acquire oil and gas interests by joining in oil and gas drilling prospects generated by third parties. We may also employ a combination of the above methods of obtaining producing acreage and prospects. In recent years, we have placed primary emphasis on the evaluation and purchase of producing oil and gas properties, including working, royalty and mineral interests, and prospects that could have a potentially meaningful impact on our reserves. All of the Company’s oil and gas interests are operated by others.

From 1983 to 2025, Mexco Energy Corporation made numerous acquisitions of royalties, overriding royalties, minerals and working interests in producing oil and gas properties including the following most significant acquisitions:

1990-1994	Royalty interests, aggregate purchase price of approximately $501,000 covering multiple wells in the Gomez (Ellenberger) Field of Pecos County, Texas.

1993-2014	Tabbs Bay Oil Company and Thompson Brothers Lumber Company, respectively dissolved in 1957 and 1947. Purchase covering thousands of acres located respectively in 19 counties of Texas, 3 parishes of Louisiana and one county in Arkansas and 8 counties of Texas, respectively consisting of various mineral, royalty and overriding royalty interests.

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

2004	Royalty interests, purchase price $304,000 covering 37 producing wells in the Cotton Valley formation in Limestone County, Texas and the Lower Cotton Valley formation in Jackson Parish, Louisiana. This acreage also contains additional potential undrilled locations.

	Royalty interests, purchase price $500,000 covering 4 producing gas units in Freestone County, Texas containing 33 producing wells and additional potential undeveloped locations in the Cotton Valley formation.

2005	Royalty interests, purchase price $550,000 covering 75 producing wells and additional potential undeveloped locations in the Cotton Valley formation of Freestone and Limestone Counties, Texas.

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

	Royalty (mineral) acreage, purchase price $1,850,000 covering 122 mineral acres in the Newark East (Barnett Shale) Field of Tarrant County, Texas amounting to approximately 21.45% royalty interest.

2008	Royalty (mineral) acreage, purchase price $429,000 covering 522 mineral acres in the Newark East (Barnett Shale) Field of Tarrant County, Texas containing 6 producing natural gas wells and additional potential undeveloped well locations. In March 2009, purchased additional interests, $49,000.

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

	Overriding royalty interests, purchase price $1,650,000 covering 5,120 gross acres over 8 sections in the Haynesville trend area of DeSoto Parish, Louisiana containing 6 horizontal producing wells and additional potential undeveloped drill sites. The Company paid $1.46 million in cash and the remainder was paid as 26,833 shares of its common stock issued from treasury shares.

2011	Non-operating working interests, purchase price $670,000 covering 160 gross acres in the Fuhrman-Mascho Field of Andrews County, Texas containing 5 producing wells in the Grayburg and San Andres formations and additional potential drill sites. In March 2012, purchased additional working interests, $275,000.

2012	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 $200,000 covering 43 wells in 12 counties of 8 states, primarily in Texas.

	Royalty interests, purchase price $580,000 covering 580 wells in 87 counties of 8 states. Approximately 90% of the net revenue from these royalties is produced by 157 wells located in the Barnett Shale of the Fort Worth Basin of Texas.

	Royalty and mineral interests, purchase price $1,000,000 covering approximately 1,800 wells in 27 counties of Texas. Of these oil and gas reserves, approximately 60% is natural gas and 40% oil.

	Non-Operated working interests, purchase price $840,000 in 70 Natural gas producing wells located in 5 counties of Oklahoma.

	Non-Operated working interests, purchase price $200,000 covering 80 wells located in Hockley and Pecos Counties, Texas.

	Non-Operated working interests, purchase price $450,000 covering 43 wells in Webster Parish, Louisiana; Eddy County, New Mexico; and, Nolan and Smith Counties, Texas.

2019	Royalty interest investment, $300,000 for a less than 1% investment commitment in a limited liability company, capitalized at approximately $50 million to purchase royalty interests consisting of minerals located in the Marcellus and Utica areas of Ohio. This LLC has returned $321,112 (107%) of the total investment since inception in fiscal 2020.

2022-2023	Overriding royalty interests, purchase price of $567,000 covering 53 producing wells and several additional potential locations for development in Atascosa and Karnes Counties, Texas.

	Royalty interests, purchase price of $939,000 covering 22 producing wells and several additional potential locations for development in the Eagleford area of Dimmit County, Texas.

	Royalty interest investment, $2,000,000 for an approximate 2% investment commitment in a limited liability company, capitalized at approximately $100 million to purchase royalty interests consisting of minerals located in the Marcellus and Utica areas of Ohio. As of the date of this report, $1,800,000 of the commitment has been expended and 14% of the investment has been returned.

	Royalty interests, purchase price of $117,200 covering 28 producing wells in 6 counties in the Haynesville trend area of Louisiana and 5 counties in Texas.

2023-2024	Royalty interests, purchase price of $455,000 covering 8 producing wells and additional potential locations for development in Reeves County, Texas.

	Royalty interests, purchase price of $367,500 covering 84 producing wells and additional potential locations for development in 6 counties in Texas.

	Royalty interest, purchase price of $575,600 covering 9 producing wells with additional potential locations for development and 4 producing wellbores in Weld County, Colorado.

	Royalty interests, purchase price of $390,300 covering 255 producing wells in the Haynesville trend area of Caddo Parish, Louisiana.

2024-2025	Royalty interests, purchase price of $568,000 covering 30 producing wells and additional potential locations for development in Adams, Broomfield and Weld Counties, Colorado.

	Royalty interests, purchase price of $483,000 covering 240 producing wells in Laramie County, Wyoming and Adams and Weld Counties, Colorado.

	Royalty interest, purchase price of $473,000 covering 84 producing wells in DeSoto Parish, Louisiana and Karnes, Live Oak, Reagan, Reeves and Upton Counties, Texas.

	Royalty interests, purchase price of $260,000 covering 3 producing wells with additional potential locations for development in Eddy County, New Mexico.

	Royalty interests, purchase price of $188,000 covering over 400 producing wells in multiple counties throughout the states of Nebraska, North Dakota, South Dakota and Montana.

Industry Environment and Outlook

The commodity price environment was challenging in fiscal 2025. The war in Ukraine and the Israel-Hamas war, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession and measures to combat persistent inflation and instability in the financial sector have contributed to recent economic and pricing volatility and may continue to impact pricing throughout fiscal 2026. In light of these challenges facing our industry and in response to the continued challenging environment, our primary business strategies for fiscal 2026 will continue to include: (1) optimizing cash flows through operating efficiencies and cost reductions, (2) divesting of non-core assets, and (3) working to balance capital spending with cash flows to minimize borrowings and maintain ample liquidity.

See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for discussion of our fiscal 2025 operating results and potential impact on fiscal 2026 operating results due to commodity price changes.

Oil and Gas Operations

As of March 31, 2025, oil contributed approximately 84% of our oil and natural gas sales and approximately 48% of our total proved reserves volumes for fiscal 2025. Revenues from oil and gas royalty interests accounted for approximately 31% of our total operating revenues for fiscal 2025.

There are two primary areas in which the Company is focused, 1) the Delaware Basin located in the Western portion of the Permian Basin including Lea and Eddy Counties, New Mexico and Reeves and Loving Counties, Texas and 2) the Midland Basin located in the Eastern portion of the Permian Basin including Reagan, Upton, Midland, Martin, Howard and Glasscock Counties, Texas. The Permian Basin in total accounts for 80% of our discounted future net cash flows from proved reserves and 80% of our gross revenues.

The Permian Basin is one of the oldest and most prolific producing basins in North America which has been a significant source of oil production since the 1920s. The Permian Basin is known to have a number of zones of oil and natural gas bearing rock throughout.

The Delaware Basin properties, encompassing 39,850 gross acres, 211 net acres, 751 gross producing wells or 4 net wells account for approximately 67% of our discounted future net cash flows from proved reserves as of March 31, 2025. For fiscal 2025, these properties accounted for 65% of our gross revenues. Of these discounted future net cash flows from proved reserves, approximately 27% are attributable to proven undeveloped reserves which would be developed through new drilling.

The Midland Basin properties, encompassing 114,077 gross acres, 232 net acres, 1,652 gross producing wells or 4 net wells account for approximately 12% of our discounted future net cash flows from proved reserves as of March 31, 2025. For fiscal 2025, these properties accounted for 14% of our gross revenues. Of these discounted future net cash flows from proved reserves, approximately 3% are attributable to proven undeveloped reserves which would be developed through new drilling.

Mexco believes its most important properties for future development by horizontal drilling and hydraulic fracturing area are located in Lea and Eddy Counties, New Mexico of the Delaware Basin and the Midland Basin in Midland, Reagan and Upton Counties, Texas.

For more on these and other operations in this area see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources Commitments”.

We own partial interests in approximately 7,500 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)
2025		83,564		570,012
2024		69,999		502,879
2023		73,968		534,363
2022		61,689		393,841
2021		50,327		324,205

Competition and Markets

The oil and gas industry is a highly competitive business. Competition for oil and gas reserve acquisitions is significant. We may compete with major oil and gas companies, other independent oil and gas companies and individual producers and operators, some of which have financial and personnel resources substantially in excess of those available to us. As a result, we may be placed at a competitive disadvantage. Competitive factors include price, contract terms and types and quality of service, including pipeline distribution. The price for oil and gas is widely followed and is generally subject to worldwide market factors. Our ability to acquire and develop additional properties in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment in a timely manner.

In addition, the oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources could adversely affect our revenue.

Market factors affect the quantities of oil and natural gas production and the price we can obtain for the production from our oil and natural gas properties. Such factors include: the extent of domestic production; the level of imports of foreign oil and natural gas; the general level of market demand on a regional, national and worldwide basis; domestic and foreign economic conditions that determine levels of industrial production; political events in foreign oil-producing regions; and variations in governmental regulations including environmental, energy conservation and tax laws or the imposition of new regulatory requirements upon the oil and natural gas industry.

The market for our oil, gas and natural gas liquids production depends on factors beyond our control including: domestic and foreign political conditions; the overall level of supply of and demand for oil, gas and natural gas liquids; the price of imports of oil and gas; weather conditions; the price and availability of alternative fuels; the proximity and capacity of gas pipelines and other transportation facilities; and overall economic conditions.

Major Customers

We made sales that amounted to 10% or more of operating revenues as follows for the years ended March 31:

		2025				2024
Company A			58	%			59	%

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

Environmental Regulation

The oil and gas industry is extensively regulated at the federal, state, and local levels. Regulations affecting elements of the energy sector are under constant review for amendment or expansion and frequently more stringent requirements are imposed. Various federal and state agencies, including the Texas Railroad Commission, the Bureau of Land Management (the “BLM”), an agency of the U.S Department of the Interior (“DOI”), the Federal Energy Regulatory Commission (“FERC”), the U.S. Environmental Protection Agency (the “EPA”), the Department of Transportation (“DOT”) and the U.S. Occupational Safety and Health Administration (“OSHA”), have legal and regulatory authority and oversight over the operations on the properties in which the Company owns an interest.

Under certain environmental laws and regulations, the operators of the Company properties could be subject to strict, joint and several liability for the removal or remediation of property contamination, whether at a drill site or a waste disposal facility, even when the operators did not cause the contamination or their activities were in compliance with all applicable laws at the time the actions were taken. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund” law, for example, imposes liability, regardless of fault or the legality of the original conduct, on certain classes of persons for releases into the environment of a “hazardous substance.” Liable persons may include the current or previous owner and operator of a site where a hazardous substance has been disposed and persons who arranged for the disposal of a hazardous substance at a site. Under CERCLA and similar statutes, government authorities or private parties may take actions in response to threats to the public health or the environment or sue responsible persons for the associated costs. In the course of operations, the working interest owner and/or the operator of the Company properties may have generated and may generate materials that could trigger cleanup liabilities. In addition, the Company properties have produced oil and/or natural gas for many years, and previous operators may have disposed or released hydrocarbons, wastes or hazardous substances at the Company properties. The operator of the Company properties or the working interest owners may be responsible for all or part of the costs to clean up any such contamination. Although the Company is not the operator of such properties, its ownership of the properties could cause it to be responsible for all or part of such costs to the extent CERCLA or any similar statute imposes responsibility on such parties as “owners.”

Various state governments and regional organizations comprising state governments already have enacted legislation and promulgated rules restricting greenhouse gases (“GHGs”) emissions or promoting the use of renewable energy, and additional such measures are frequently under consideration. Although it is not possible at this time to estimate how potential future requirements addressing GHG emissions would impact operations on the Company properties and revenue, either directly or indirectly, any future federal, state or local laws or implementing regulations that may be adopted to address GHG emissions could require the operators of our properties to incur new or increased costs to obtain permits, operate and maintain equipment and facilities, install new emission controls, acquire allowances to authorize GHG emissions, pay taxes related to GHG emissions or administer a GHG emissions program. Regulation of GHGs could also result in a reduction in demand for and production of oil and natural gas. Additionally, to the extent that unfavorable weather conditions are exacerbated by global climate change or otherwise, the Company properties may be adversely affected to a greater degree than previously experienced.

We did not incur any material capital expenditures for remediation or pollution control activities for the year ended March 31, 2025. 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 2026.

Other Regulation

Other agencies with certain authority over the Company’s business include the Internal Revenue Service (the “IRS”), the SEC and NYSE. Ensuring compliance with the rules, regulations and orders promulgated by such entities requires extensive effort and incremental costs to comply, which affects the Company’s profitability. Because public policy changes are commonplace, and existing laws and regulations are frequently amended, the Company is unable to predict the future cost or impact of compliance. However, the Company does not expect that any of these laws and regulations will affect its operations materially differently than they would affect other companies with similar operations, size and financial strength.

Title to Properties

The leasehold properties we own are subject to royalty, overriding royalty and other outstanding interests customary in the industry. The properties may be subject to burdens such as liens incident to operating agreements and current taxes, development obligations under oil and gas leases and other encumbrances, easements and restrictions. We do not believe any of these burdens will materially interfere with the use of these properties.

Prior to drilling of an oil and natural gas well, it is normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our operators’ failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest. We believe the title to our properties is good and defensible in accordance with standards generally acceptable in the oil and gas industry subject to such exceptions that, in the opinion of counsel employed in the various areas in which we have activities, are not so material as to detract substantially from the use of such properties.

Substantially all of our properties are currently mortgaged under a deed of trust to secure funding through a credit facility.

Insurance

Our operations are subject to all the risks inherent in the exploration for and development and production of oil and gas including blowouts, fires and other casualties. We maintain insurance coverage customary for operations of a similar nature, but losses could arise from uninsured risks or in amounts in excess of existing insurance coverage.

Executive Officers

The following table sets forth certain information concerning the executive officers of the Company as of March 31, 2025.

Name	Age	Position
Nicholas C. Taylor	87	Chairman and Chief Executive Officer
Tamala L. McComic	56	President, Chief Financial Officer, Treasurer, and Assistant Secretary
Donna Gail Yanko	80	Vice President
Stacy D. Hardin	60	Secretary and Assistant Treasurer

Set forth below is a description of the principal occupations during at least the past five years of each executive officer of the Company.

Nicholas C. Taylor was elected Chairman of the Board and Chief Executive Officer of the Company in September 2011 and continues to serve in such capacity on a part time basis, as required. He served as Chief Executive Officer, President and Director of the Company from 1983 to 2011. From July 1993 to the present, Mr. Taylor has been involved in the independent practice of law and other business activities. In November 2005 he was appointed by the Speaker of the House to the Texas Ethics Commission and served until February 2010.

Tamala L. McComic, a Certified Public Accountant and Chartered Global Management Accountant, became Controller for the Company in July 2001 and was elected President and Chief Financial Officer in September 2011. She served the Company as Executive Vice President and Chief Financial Officer from 2009 to 2011 and Vice President and Chief Financial Officer from 2003 to 2009. Prior thereto, Ms. McComic served as Treasurer and Assistant Secretary of the Company.

Donna Gail Yanko was appointed to the position of Vice President of the Company in 1990. She also served as Corporate Secretary from 1992 to 2021 and from 1986 to 1992 was Assistant Secretary. From 1986 to 2015, on a part-time basis, she assisted the Chairman of the Board of the Company in his personal business activities. Ms. Yanko also served as a director of the Company from 1990 to 2008.

Stacy D. Hardin joined the Company in 2006 and was elected Corporate Secretary of the Company in September 2021. She has also served the Company as Assistant Treasurer of the Company since 2010 and from 2006 to 2021 was Assistant Secretary. Prior thereto, Ms. Hardin served as Assistant Controller.

Employees

As of March 31, 2025, we had two full-time and three part-time employees. We believe that relations with these employees are generally satisfactory. From time to time, we utilize the services of independent geological, land and engineering consultants on a limited basis and expect to continue to do so in the future.

Office Facilities

Our principal offices are located at 415 W. Wall, Suite 475, Midland, Texas 79701 and our telephone number is (432) 682-1119. We believe our facilities are adequate for our current operations and future needs.

Access to Company Reports

Mexco Energy Corporation files annual, quarterly and current reports, proxy statements and other information with the SEC. The SEC maintains an internet website (www.sec.gov) that contains annual, quarterly and current reports, proxy statements and other information that issuers, including Mexco, file electronically with the SEC.

We also maintain an internet website at www.mexcoenergy.com. In the Investor Relations section, our website contains our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other reports and amendments to those reports as soon as reasonably practicable after such material is electronically filed with the SEC. Information on our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. Additionally, our Code of Business Conduct and Ethics and the charters of our Audit Committee, Compensation Committee and Nominating Committee are posted on our website. Any of these corporate documents as well as any of the SEC filed reports are available in print free of charge to any stockholder who requests them. Requests should be directed to our Corporate Secretary by mail to P.O. Box 10502, Midland, Texas 79702 or by email to mexco@sbcglobal.net.

ITEM 1A. RISK FACTORS

The Company is subject to various risks and uncertainties in the ordinary course of business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations. We could also face additional risks and uncertainties not currently known to us or that we currently deem to be immaterial. If any of these risks actually occurs, it could materially harm our business, financial condition or results of operations and the trading price of our shares could decline. Investors should carefully consider each of the following risk factors and all of the other information set forth in this Annual Report on Form 10-K.

RISKS RELATED TO OUR BUSINESS AND INDUSTRY

Volatility of oil and gas prices significantly affects our results and profitability.

Prices for oil and natural gas fluctuate widely. We cannot predict future oil and natural gas prices with any certainty. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile. Factors that can cause price fluctuations include the level of global demand for petroleum products; foreign supply and pricing of oil and gas; the actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls; nature and extent of governmental regulation and taxation, including environmental regulations; level of domestic and international exploration, drilling and production activity; the cost of exploring for, producing and delivering oil and gas; speculative trading in crude oil and natural gas derivative contracts; availability, proximity and capacity of oil and gas pipelines and other transportation facilities; weather conditions; the price and availability of alternative fuels; technological advances affecting energy consumption; national and international pandemics; and, overall political and economic conditions in oil producing countries.

Increases and decreases in prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow from banks may be subject to redetermination based on changes in prices. In addition, we may have ceiling test writedowns when prices decline. Lower prices may also reduce the amount of crude oil and natural gas that can be produced economically. Thus, we may experience material increases or decreases in reserve quantities solely as a result of price changes and not as a result of drilling or well performance.

Changes in oil and gas prices impact both estimated future net revenue and the estimated quantity of proved reserves. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our credit facility and adversely affect the amount of cash flow available for capital expenditures and our ability to obtain additional capital for our exploration and development activities.

Oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. Lower prices or lack of storage may have an adverse affect on our financial condition due to reduction of our revenues, operating income and cash flows; curtailment or shut-in of our production due to lack of transportation or storage capacity; cause certain properties in our portfolio to become economically unviable; and, limit our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations.

Our results of operations may be negatively impacted by current global events, including the imposition of tariffs.

Our business, financial condition and future results are subject to political and economic risks and uncertainties, including volatility in the political, legal and regulatory environments as a result of the change in U.S. presidential administration and instability resulting from civil unrest, political demonstrations, mass strikes or armed conflict or other crises in crude oil or natural gas producing areas such as the ongoing war between Russia and Ukraine and the Israel-Iran conflict. Escalating trade tensions, particularly between the U.S. and Canada, Mexico, China and other countries, may lead to the imposition of tariffs and trade restrictions. Our operators could face unanticipated costs and competition for materials and components to continue their current drilling plans. In addition, the current U.S. presidential administration has signaled it will encourage increased domestic production of crude oil, which could lead to falling crude oil and natural gas prices.

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

In recent years the U.S. Congress has considered legislation to reduce emissions of GHGs, including methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas. Addressing GHG emissions with legislation on emissions fees could increase operating costs within the oil and gas industry.

Fluids resulting from crude oil and natural gas production, consisting primarily of salt-water, are disposed by injection in belowground disposal wells. In recent years, state and federal regulatory agencies have focused on a possible connection between fluid injection and increased seismic activity. The Texas Railroad Commission has suspended or limited new well permits for salt water disposal wells, particularly in the Permian Basin. Increased regulation on the treatment and disposal of fluids could increase operating costs and curtail economical drilling.

Lower oil and gas prices and other factors may cause us to record ceiling test writedowns.

Lower oil and gas prices increase the risk of ceiling limitation write-downs. We use the full cost method to account for oil and gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop crude oil and natural gas properties including the cost of abandoned properties, dry holes, geophysical costs and annual lease rentals. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded. Depletion of evaluated oil and natural gas properties is computed in the units of production method, whereby capitalized costs are amortized over total proved reserves. Under the full cost accounting rules, the net capitalized cost of crude oil and natural gas properties may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10% plus the lower of cost or fair market value of unproved properties. If net capitalized costs of oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess against earnings. This is called a “ceiling test writedown.” We use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net reserves. Under the accounting rules, we are required to perform a ceiling test each quarter. A ceiling test writedown does not impact cash flow from operating activities, but does reduce stockholders’ equity and earnings. The risk that we will be required to write down the carrying value of oil and natural gas properties increases when oil and natural gas prices are low. There were no ceiling test impairments on our oil and gas properties during fiscal 2025 and 2024.

We must replace reserves we produce.

Our future success depends upon our ability to find, develop or acquire additional, economically recoverable oil and gas reserves. Our proved reserves will generally decline as reserves are depleted, except to the extent that we can find, develop or acquire replacement reserves. One offset to the obvious benefits afforded by higher product prices especially for small to mid-cap companies in this industry, is that quality domestic oil and gas reserves are hard to find.

Approximately 28% and 33% of our total estimated net proved reserves at March 31, 2025 and 2024, respectively, were undeveloped, and those reserves may not ultimately be developed.

Recovery of undeveloped reserves requires significant capital expenditures and successful drilling. Our reserve data assumes that we can and will make these expenditures and conduct these operations successfully. These assumptions, however, may not prove correct. Delays in the development of our reserves, increases in costs to develop such reserves, or decreases in commodity prices will reduce the future net revenues or our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, if we or the outside operators of our properties choose not to spend the capital to develop these reserves, or if we are not able to successfully develop these reserves, we will be required to write-off these reserves. Any such write-offs of our reserves could reduce our ability to borrow money and could reduce the value of our common stock.

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

Estimates of oil and gas reserves, by necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, such as future production, oil and gas prices, operating costs, development costs and remedial costs, all of which may vary considerably from actual results. As a result, estimates of the economically recoverable quantities of oil and gas and of future net cash flows expected therefrom may vary substantially. As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on a twelve month un-weighted first-day-of-the-month average oil and gas prices for the twelve months prior to the date of the report. Actual future prices and costs may be materially higher or lower.

An increase in the differential between NYMEX and the reference or regional index price used to price our oil and gas would reduce our cash flow from operations.

Our oil and gas is priced in the local markets where it is produced based on local or regional supply and demand factors. The prices we receive for our oil and gas are typically lower than the relevant benchmark prices, such as The New York Mercantile Exchange (“NYMEX”). The difference between the benchmark price and the price we receive is called a differential. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, upsets in the midstream or downstream sectors of the industry, trade restrictions and governmental regulations such as policies of the Trump Administration. Additionally, insufficient pipeline capacity, lack of demand in any given operating area or other factors may cause the differential to increase in a particular area compared with other producing areas. During fiscal 2025, differentials averaged $2.79 per Bbl of oil and ($0.30) per Mcf of gas. Increases in the differential between the benchmark prices for oil and gas and the wellhead price we receive could significantly reduce our revenues and our cash flow from operations.

Drilling and operating activities are high risk activities that subject us to a variety of factors that we cannot control.

These factors include availability of workover and drilling rigs, well blowouts, cratering, explosions, fires, formations with abnormal pressures, pollution, releases of toxic gases and other environmental hazards and risks. Any of these operating hazards could result in substantial losses to us. In addition, we incur the risk that no commercially productive reservoirs will be encountered, and there is no assurance that we will recover all or any portion of our investment in wells drilled or re-entered.

We may not be able to fund the capital expenditures that will be required for us to increase reserves and production.

We must make capital expenditures to develop our existing reserves and to acquire new reserves. Historically, we have used our cash flow from operations and borrowings under our credit facility to fund our capital expenditures, however, lower oil and gas prices may prevent these options. Volatility in oil and gas prices, the timing of our drilling programs and drilling results will affect our cash flow from operations. Lower prices and/or lower production will also decrease revenues and cash flow, thus reducing the amount of financial resources available to meet our capital requirements, including reducing the amount available to pursue our drilling opportunities.

The borrowing base under our credit facility will be determined from time to time by the lender. Reductions in estimates of oil and gas reserves could result in a reduction in the borrowing base, which would reduce the amount of financial resources available under the credit facility to meet our capital requirements. Such a reduction could be the result of lower commodity prices and/or production, inability to drill or unfavorable drilling results, changes in oil and gas reserve engineering, the lender’s inability to agree to an adequate borrowing base or adverse changes in the lender’s practices regarding estimation of reserves. If cash flow from operations or our borrowing base decrease for any reason, our ability to undertake exploration and development activities could be adversely affected. As a result, our ability to replace production may be limited.

Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management and outside operators have specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling in these projects. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations.

Our business depends on oil and natural gas transportation facilities which are owned by others.

The marketability of our production depends in part on the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions could all affect our ability to produce and market our oil and gas.

We own non-operating interests in properties developed and operated by third parties and, as a result, we are unable to control the operation and profitability of such properties.

We participate in the drilling and completion of wells with third-party operators that exercise exclusive control over such operations. As a participant, we rely on third-party operators to successfully operate these properties pursuant to joint operating agreements and other similar contractual arrangements. As a participant in these operations, we may not be able to maximize the value associated with these properties in the manner we believe appropriate, or at all. For example, we cannot control the success of drilling and development activities on properties operated by third-parties, which depend on a number of factors under the control of a third-party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology. In addition, the third-party operator’s operational expertise and financial resources and its ability to gain the approval of other participants in drilling wells will impact the timing and potential success of drilling and development activities in a manner that we are unable to control. A third-party operator’s failure to adequately perform operations, breach of the applicable agreements or failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our financial condition and results of operations.

Acquiring reserves in the oil and gas industry is highly competitive.

Competition for oil and gas reserve acquisitions is significant. We may compete with major oil and gas companies, other independent oil and gas companies and individual producers and operators, some of which have financial and personnel resources substantially in excess of those available to us. As a result, we may be placed at a competitive disadvantage. Our ability to acquire and develop additional properties in the future will depend upon our ability to select and acquire suitable producing properties and prospects for future development activities.

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

Our operations are subject to all the risks inherent in the exploration for, and development and production of oil and gas including blowouts, fires and other casualties. We maintain insurance coverage customary for operations of a similar nature, but losses could arise from uninsured risks or in amounts in excess of existing insurance coverage.

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; tax effects of stock-based compensation; or changes in tax laws, regulations or interpretations thereof.

For example, in previous years, legislation has been proposed to eliminate or defer certain key U.S. federal income tax deductions historically available to crude oil and natural gas exploration and production companies. Such proposed changes have included: a repeal of the percentage depletion allowance for crude oil and natural gas properties; the elimination of deductions for intangible drilling and exploration and development costs; the elimination of the deduction for certain production activities; and an extension of the amortization period for certain geological and geophysical expenditures. The passage of any legislation as a result of these proposals or other similar changes in U.S. federal income tax laws that alter, eliminate or defer these or other tax deductions utilized within the industry could adversely affect our business, financial condition, results of operations and cash flows.

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

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities, including digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate energy assets might be specific targets of cyber security threats. Our and our operators’ technologies, systems, networks, and those of vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business activities. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

The loss of our chief executive officer or president could adversely impact our ability to execute our business strategy.

We depend, and will continue to depend in the foreseeable future, upon the continued services of our Chief Executive Officer, Nicholas C. Taylor and our President and Chief Financial Officer, Tamala L. McComic, who have extensive experience and expertise in evaluating and analyzing producing oil and gas properties and drilling prospects, maximizing production from oil and gas properties and developing and executing acquisitions and financing. As of March 31, 2025, we do not have key-man insurance on the lives of Mr. Taylor and Ms. McComic. The unexpected loss of the services of one or more of these individuals could, therefore, significantly and adversely affect our operations.

We may be affected by one substantial shareholder.

Nicholas C. Taylor beneficially owns approximately 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. The retirement, incapacity or death of Mr. Taylor, or any change in the power to vote shares beneficially owned by Mr. Taylor, could result in negative market or industry perception and could have an adverse effect on our business.

RISKS RELATED TO OUR COMMON STOCK

We may issue additional shares of common stock in the future, which could cause dilution to all shareholders.

We may seek to raise additional equity capital in the future. Any issuance of additional shares of our common stock will dilute the percentage ownership interest of all shareholders and may dilute the book value per share of our common stock.

Control by our executive officers and directors may limit your ability to influence the outcome of matters requiring stockholder approval and could discourage our potential acquisition by third parties.

As of March 31, 2025, our executive officers and directors beneficially owned approximately 49% of our common stock. These stockholders, if acting together, would be able to influence significantly all matters requiring approval by our stockholders, including the election of our board of directors and the approval of mergers or other business combination transactions.

The price of our common stock has been volatile and could continue to fluctuate substantially.

Mexco common stock is traded on the New York Stock Exchange’s NYSE American. The market price of our common stock has and could continue to experience volatility due to reasons unrelated to our operating performance. These reasons include: supply and demand for oil and natural gas; political conditions in oil and natural gas producing regions; demand for our common stock and limited trading volume; investor perception of our industry; fluctuations in commodity prices; variations in our results of operations; legislative or regulatory changes; general trends in the oil and natural gas industry; market conditions and analysts’ estimates; and, other events in the oil and gas industry.

Many of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. We cannot assure you that the market price of our common stock will not fluctuate or decline significantly in the future. In addition, the stock markets in general can experience considerable price and volume fluctuations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

Mexco maintains a cybersecurity program that aims to protect the confidentiality, integrity, and availability of data required by our business to be stored, analyzed, transported, and/or processed. We have implemented various internal and external controls and processes, including internal risk assessment and policy implementation, to incorporate a risk-based cybersecurity framework to monitor and mitigate security threats and other strategies to increase security for our information, facilities, and infrastructure.

Risk Management and Strategy. Mexco recognizes the risk that cybersecurity threats pose to our operations, and cybersecurity is an important component of our overall risk management strategy. Mexco’s cybersecurity team consists of our executive officers and third-party cybersecurity personnel. The third-party cybersecurity team, led by professionals with cybersecurity expertise across multiple industries, takes a cross-functional approach to addressing these risks and engages in discussions with our executive management team on an as-needed basis.

We have implemented a monitoring and detection system to help promptly identify cybersecurity incidents. We also require our employees to receive annual cybersecurity awareness training. We perform cybersecurity tabletop exercises to test the effectiveness of our incidence response plan (“IRP”) and implement post-incident “lessons learned” to enhance our response. We provide our system users with access consistent with the principle of least privilege, which requires that such users be given no more access than necessary to complete their job functions. We have programs in place to monitor our retained data with the goal of identifying personal identifiable information and taking appropriate actions to secure the data.

We have an IRP that delineates the procedures to be followed for handling a variety of cybersecurity incidents; categorizes potential cybersecurity incidents and the required timeframe for reporting each; establishes cybersecurity incident response levels; provides for investigations designed to help us to meet applicable legal obligations, including possible notification requirements; and outlines the roles and responsibilities for various personnel in the event of a cybersecurity incident.

Governance. The Board, in coordination with the Audit Committee and Chief Financial Officer, is responsible for the oversight of risks from cybersecurity threats. The responsibilities of the Audit Committee include overseeing policies and management systems for cybersecurity matters and reviewing Mexco’s strategy, objectives, and policies relative to cybersecurity. In addition, the Board and the Audit Committee receive regular presentations and reports on cybersecurity risks that address a range of topics, including developments, technological trends or tools, third party updates, and regulatory standards. Our IRP calls for prompt and timely direct notifications and updates to the Board (or its committees) as necessary in connection with cybersecurity incidents deemed to have a moderate or higher business impact, even if immaterial. On a periodic basis, the Board and the Audit Committee discuss our approach to cybersecurity with our executive officers and cybersecurity personnel.

Management plays a role in assessing and managing our material risks from cybersecurity threats through membership on our cybersecurity team, as well as by making final materiality determinations and disclosures and other compliance decisions, as reflected in our IRP.

Impact of Risks from Cybersecurity Threats. As of the date of this Report, we are not aware of any previous cybersecurity threats that have materially affected, or are reasonably likely to materially affect, the Company, including our business strategy, results of operations or financial condition. Notwithstanding the approach we take to cybersecurity, we may not be successful in preventing or mitigating a cybersecurity incident that could have a material adverse effect on us.

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

ITEM 2. PROPERTIES

Our properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped. As of March 31, 2025, we had interests in approximately 7,500 gross (26.4 net) producing oil and gas wells and owned leasehold mineral, royalty and other interests in approximately 662,000 gross (2,712 net) acres.

Oil and Natural Gas Reserves

In accordance with current SEC rules, the average prices used in computing reserves at March 31, 2025 were $73.79 per bbl of oil compared to $76.88 in 2024, a decrease of 4%, and $2.14 per mcf of natural gas compared to $2.75 in 2024, a decrease of 22%, such prices are based on the 12-month unweighted arithmetic average market prices for sales of oil and natural gas on the first calendar day of each month during fiscal 2025. The benchmark price of $71.00 per bbl of oil at March 31, 2025 versus $73.96 at March 31, 2024, was adjusted by lease for gravity, transportation fees and market differentials and did not give effect to derivative transactions. The benchmark price of $2.44 per mcf of natural gas at March 31, 2025 versus $2.45 at March 31, 2024, was adjusted by lease for BTU content, transportation fees and market differentials.

For information concerning our costs incurred for oil and gas operations, net revenues from oil and gas production, estimated future net revenues attributable to our oil and gas reserves, present value of future net revenues discounted at 10% and changes therein, see Notes to the Company’s consolidated financial statements.

Proved reserves are estimated reserves of crude oil (including condensate) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

The engineering report with respect to Mexco’s estimates of proved oil and gas reserves as of March 31, 2025 and 2024 is based on evaluations prepared by Russell K. Hall and Associates, Inc. Environmental Engineering Consultants, based in Midland, Texas (“Hall and Associates”), a summary of which is filed as Exhibit 99.1 to this annual report.

Management maintains internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported in accordance with rules and regulations provided by the SEC. As stated above, Mexco retained Hall and Associates to prepare estimates of our oil and gas reserves. Management works closely with this firm, and is responsible for providing accurate operating and technical data to it. Our Chief Financial Officer who has over 30 years experience in the oil and gas industry reviews the final reserves estimate and consults with a degreed geological consultant with extensive geological experience and if necessary, discusses the process used and findings with Alan Neal, the technical person at Hall and Associates responsible for evaluating the proved reserves covered by this report. Mr. Neal is a member of the Society of Petroleum Engineers and has over 40 years of experience in the oil and gas industry. Our Chairman and Chief Executive Officer who has over 50 years of experience in the oil and gas industry also reviews the final reserves estimate.

Numerous uncertainties exist in estimating quantities of proved reserves. Reserve estimates are imprecise and subjective and may change at any time as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates. Any significant variance could materially affect the estimated quantities and value of our oil and gas reserves, which in turn may adversely affect our cash flow, results of operations and the availability of capital resources.

Per the current SEC rules, the prices used to calculate our proved reserves and the present value of proved reserves set forth herein are made using the 12-month unweighted arithmetic average of the first-day-of-the-month price. All prices are held constant throughout the life of the properties. Actual future prices and costs may be materially higher or lower than those as of the date of the estimate. The timing of both the production and the expenses with respect to the development and production of oil and gas properties will affect the timing of future net cash flows from proved reserves and their present value. Except to the extent that we acquire additional properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced.

Our estimated proved oil and gas reserves and present value of estimated future net revenues from proved oil and gas reserves in the periods ended March 31 are summarized below.

PROVED RESERVES

	March 31,
	2025			2024
Oil (Bbls):
Proved developed – Producing		390,940			394,000
Proved developed – Non-producing		14,900			50,620
Proved undeveloped		269,000			346,330
Total		674,840			790,950
Natural gas (Mcf):
Proved developed – Producing		3,554,920			3,346,460
Proved developed – Non-producing		99,970			219,780
Proved undeveloped		704,810			970,880
Total		4,359,700			4,537,120

Total net proved reserves (BOE) ⁽¹⁾		1,401,460			1,547,127

PV-10 Value ⁽²⁾	$	23,216,000		$	29,078,000
Present value of future income tax discounted at 10%		(3,141,000	)		(4,450,000	)
Standardized measure of discounted future net cash flows ⁽³⁾	$	20,075,000		$	24,628,000

Prices used in Calculating Reserves: (4)
Natural gas (per Mcf)	$	2.14		$	2.75
Oil (per Bbl)	$	73.79		$	76.88

	(1)	These reserve estimates do not include the Company’s interest in two LLCs referred to in Item 1. Business – Company Profile on page 3 hereto.
	(2)	The PV-10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10% per annum, which is the most directly comparable GAAP financial measure. PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. Our reconciliation of this non-GAAP financial measure is shown in the table as the PV-10, less future income taxes, discounted at 10% per annum, resulting in the standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%.
	(3)	In accordance with SEC requirement, the standardized measure of discounted future net cash flows was computed by applying 12-month first day of the month average prices for oil and gas during the fiscal year to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions.
	(4)	These prices reflect adjustment by lease for quality, transportation fees and market differentials.

During fiscal 2025, we added proved reserves of 101 thousand BOE (“MBOE”) through extensions and discoveries, added 77 MBOE through acquisitions, subtracted 145 MBOE for downward revisions of previous estimates. Such downward revisions are primarily attributable to reserves written off due to the five-year limitation and the change in the timing of new development. The reserves written off were primarily in Lea County, New Mexico due to a change in the timing of development in wells in which we own a working interest. These interests are held by production and still in place to be developed in the future.

During the fiscal year ending March 31, 2025, we had a working or royalty interest in the development of 27 wells, converting reserves of approximately 84,000 BOE from proved undeveloped to proved developed – producing with a capital cost of approximately $645,000.

Oil and gas prices significantly impact the calculation of the PV-10 and the standardized measure of discounted future net cash flows. The present value of future net cash flows does not purport to be an estimate of the fair market value of the Company’s proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 932, “Extractive Activities – Oil and Gas”, may not necessarily be the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

We have not filed any other oil or gas reserve estimates or included any such estimates in reports to other federal or foreign governmental authorities or agencies during the year ended March 31, 2025, and no major discovery is believed to have caused a significant change in our estimates of proved reserves since that date.

Drilling Activities

The following table sets forth our drilling activity in wells in which we own a working interest for the years ended March 31:

	Year Ended March 31,
	2025						2024
	Gross			Net			Gross			Net
Exploratory Wells
Beginning wells in progress		-			-			-			-
Wells spud		1			.10			-			-
Successful wells		0			-			-			-
Ending wells in progress		-			-			-			-

Development Wells
Beginning wells in progress		16			.17			21			.05
Wells spud		38			.09			48			.22
Successful wells		(37	)		(.23	)		(53	)		(.09	)
Ending wells in progress		17			.03			16			.17

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 120 gross wells (.09 net wells) on company-owned minerals and royalties at no expense to the Company. We expect the production of our mineral interests will increase as operators continue to drill, complete, and develop our acreage. We expect to capitalize on this development, which requires no capital expenditure funding from us and believe the anticipated aggregate royalty receipts will enable us to grow our cash flows. A number of the horizontal wells in which the Company participates involve longer lateral which are more efficient and have greater estimated ultimate recovery.

Productive Wells and Acreage

Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections. Wells that are completed in more than one producing zone are counted as one well. As of March 31, 2025, we held an interest in approximately 7,500 gross (26.4 net) productive wells, including approximately 6,400 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, 2025:

	Acreage
	Gross		Net
Texas		373,100		1,514
Oklahoma		67,100		814
North Dakota		65,000		27
Louisiana		39,500		87
Wyoming		30,700		15
New Mexico		30,300		182
Ohio		26,900		2
Colorado		10,700		21
Kansas		8,500		41
Montana		7,200		1
Arkansas		1,600		5
Alabama		1,000		2
South Dakota		600		-
Virginia		100		1
Total		662,300		2,712

Net Production, Unit Prices and Costs

The following table summarizes our net oil and natural gas production, the average sales price per barrel (“bbl”) of oil and per thousand cubic feet (“mcf”) of natural gas produced and the average production (lifting) cost per unit of production for the years ended March 31:

	Years Ended March 31,
	2025		2024
Oil (a):
Production (Bbls)		83,564		69,999
Revenue	$	6,145,674	$	5,348,257
Average Bbls per day (d)		229		192
Average sales price per Bbl	$	73.54	$	76.40
Gas (b):
Production (Mcf)		570,012		502,879
Revenue	$	970,811	$	1,114,390
Average Mcf per day (d)		1,562		1,378
Average sales price per Mcf	$	1.70	$	2.22
Total BOE (c)		178,566		153,812
Production costs:
Production expenses:	$	1,043,202	$	1,029,279
Production expenses per BOE	$	5.84	$	6.69
Production expenses per sales dollar	$	0.15	$	0.16
Production and ad valorem taxes:	$	561,894	$	479,193
Production and ad valorem taxes per BOE	$	3.15	$	3.23
Production and ad valorem taxes per sales dollar	$	0.08	$	0.08
Total oil and gas revenue	$	7,116,485	$	6,462,647

	(a)	Includes condensate.
	(b)	Includes natural gas products.
	(c)	Natural gas production is converted to oil production using a ratio of six Mcf to one Bbl of oil.
	(d)	Calculated on a 365-day year.

ITEM 3. LEGAL PROCEEDINGS

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

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

In September 2003, our common stock began trading on the NYSE American, formerly the American Stock Exchange and more recently the NYSE MKT, under the symbol “MXC”. Prior to September 2003, the Company’s common stock was traded on the over-the-counter bulletin board market under the symbol “MEXC”. The registrar and transfer agent is Issuer Direct Corporation, 500 Perimeter Park Drive, Suite D, Morrisville, North Carolina, 27560 (Tel: 877-481-4014). The following table sets forth certain information as to the high and low sales price quoted for Mexco’s common stock on the NYSE American.

		High		Low
2025:	April - June 2024	$	16.52	$	9.84
	July - September 2024		14.10		10.11
	October - December 2024		13.78		10.55
	January - March 2025		14.11		7.55

2024:	April - June 2023	$	13.84	$	10.30
	July - September 2023		13.63		11.36
	October - December 2023		13.50		9.05
	January - March 2024		10.49		9.02

On March 31, 2025, the closing sales price of our common stock on the NYSE American was $8.17 per share.

Stockholders

As of March 31, 2025, we had 2,239,283 shares issued and 809 shareholders of record, which does not include shareholders for whom shares are held in a “nominee” or “street” name. Of these issued shares, 193,283 are held in the treasury. As of March 31, 2025, there were 2,046,000 shares outstanding.

Dividends

Prior to March 31, 2023, the Company had never paid a cash dividend to the Company’s shareholders. Payment of dividends is at the discretion of our Board of Directors (the “Board”) after considering many factors, including our financial condition, operating results, current and anticipated cash needs, and plans for expansion. In addition, our current bank loan prohibits us from paying cash dividends on our common stock without written permission.

On April 30, 2024, the Company announced that its Board declared a regular annual dividend of $0.10 per common share to its shareholders of record at the close of business on May 21, 2024. The dividend was paid on June 4, 2024. The Company obtained written permission from West Texas National Bank (“WTNB”) prior to declaring the regular annual dividend. On April 10, 2023, the Company announced that its Board declared a special dividend of $0.10 per common share to its shareholders of record at the close of business on May 1, 2023. The special dividend was paid on May 15, 2023. The Company obtained written permission from WTNB prior to declaring the special dividend.

Subsequently, on May 13, 2025, the Company announced that its Board declared a regular annual dividend of $0.10 per common share to its shareholders of record at the close of business on June 2, 2025. The dividend was paid on June 16, 2025. The Company obtained written permission from WTNB prior to declaring the regular annual dividend.

The Company can provide no assurance that dividends will be authorized or declared in the future or as to the amount or type of any future dividends. Our Board determination with respect to any such dividends, including the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by applicable law and other factors that the board deems relevant at the time of such determination.

SEC Form 10-K filed by Mexco Energy Corporation