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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

2

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.

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.

3

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.

4

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.

5

| 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.

6

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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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Securities Authorized for Issuance Under Compensation Plans

The following table includes certain information about our Employee Incentive Stock Plan as of March 31, 2025, which has been approved by our stockholders.

|  | Number of Shares Authorized for Issuance under Plan |  |  | Number of Shares to be Issued upon Exercise of Outstanding Options |  |  | Weighted Average Exercise Price of Outstanding Options |  |  | Number of Shares Remaining Available for Future Issuance under Plan |
2009 Plan |  |  | 200,000 |  |  |  | 35,000 |  |  | $ | 4.84 |  |  |  | - |
2019 Plan |  |  | 200,000 |  |  |  | 115,883 |  |  |  | 10.93 |  |  |  | 66,000 |
Total |  |  | 400,000 |  |  |  | 150,883 |  |  | $ | 9.52 |  |  |  | 66,000 |

Issuer Repurchases

In April 2024, the Board authorized the use of up to $1,000,000 to repurchase shares of the Company’s common stock for the treasury account. This program does not have an expiration date and may be modified, suspended or terminated at any time by the Board. Under the repurchase program, share of common stock may be purchased from time to time through open market purchases or other transactions. The amount and timing of repurchases will be subject to the availability of stock, prevailing market conditions, the trading price of stock, our financial performance and other conditions. Repurchases may also be made from time-to-time in connection with the settlement of our share-based compensation awards. Repurchases will be funded from cash flow.

The following table provides information related to repurchases of our common stock for the treasury account during the year ended March 31, 2025:

|  | Total Number of Shares Purchased |  |  | Average Price Paid per Share |  |  | Total Number of Shares Purchased as Part of Publicly Announced Program |  |  | Approximate Dollar Value of Shares that May Yet be Purchased Under the Program |
April 1-30, 2024 |  |  | 13,766 |  |  | $ | 13.70 |  |  |  | 13,766 |  |  | $ | 811,363 |
May 1-31, 2024 |  |  | - |  |  |  | - |  |  |  | - |  |  | $ | 811,363 |
June 1-30, 2024 |  |  | - |  |  |  | - |  |  |  | - |  |  | $ | 811,363 |
July 1-30, 2024 |  |  | 4,557 |  |  | $ | 11.78 |  |  |  | 4,557 |  |  | $ | 757,679 |
August 1-31, 2024 |  |  | 17,743 |  |  | $ | 11.95 |  |  |  | 17,743 |  |  | $ | 545,734 |
September 1-30, 2024 |  |  | 21,700 |  |  | $ | 11.47 |  |  |  | 21,700 |  |  | $ | 296,784 |
October 1-31, 2024 |  |  | - |  |  |  | - |  |  |  | - |  |  | $ | 296,784 |
November 1-30, 2024 |  |  | - |  |  |  | - |  |  |  | - |  |  | $ | 296,784 |
December 1-31, 2024 |  |  | - |  |  |  | - |  |  |  | - |  |  | $ | 296,784 |
January 1-31, 2025 |  |  | - |  |  |  | - |  |  |  | - |  |  | $ | 296,784 |
February 1-28, 2025 |  |  | - |  |  |  | - |  |  |  | - |  |  | $ | 296,784 |
March 1-31, 2025 |  |  | - |  |  |  | - |  |  |  | - |  |  | $ | 296,784 |
Total |  |  | 57,766 |  |  | $ | 12.17 |  |  |  | 57,766 |  |  |  |  |

During the year ended March 31, 2025, the Company repurchased 57,766 shares for the treasury account at an aggregate cost of $703,216, an average price of $12.17 per share. During the year ended March 31, 2024, the Company repurchased 50,101 shares for the treasury account at an aggregate cost of $585,035, an average price of $11.68 per share.

On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA 2022”). The IRA 2022, among other tax provisions, establishes a 1% excise tax on stock repurchases made by publicly traded U.S. corporations, effective for stock repurchases after December 31, 2022. The IRA 2022 does provide for certain exceptions for repurchases of stock including an exception as long as the aggregate value of the repurchases for the tax year does not exceed $1,000,000.

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ITEM 6. RESERVED

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-K.

Liquidity and Capital Resources and Commitments

Historically, we have funded our operations, acquisitions, exploration and development expenditures from cash generated by operating activities, bank borrowings, sales of non-core properties and issuance of common stock. Our primary financial resource is our base of oil and gas reserves. We have pledged our producing oil and gas properties to secure our credit facility. We do not have any delivery commitments to provide a fixed and determinable quantity of our oil and gas under any existing contract or agreement.

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

Cash Flows

Changes in the net funds provided by or (used in) each of our operating, investing and financing activities are set forth in the table below:

|  | For the Years Ended March 31, |  |  |  |
|  | 2025 |  |  | 2024 |  |  | Change |
Net cash provided by operating activities |  | $ | 4,269,621 |  |  | $ | 4,433,935 |  |  | $ | (164,314 | )
Net cash used in investing activities |  | $ | (4,154,575 | ) |  | $ | (3,416,499 | ) |  | $ | 738,076 |
Net cash used in financing activities |  | $ | (834,575 | ) |  | $ | (779,723 | ) |  | $ | 54,852 |

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, 2025 was $4,269,621 in comparison to $4,433,935 for the year ended March 31, 2024. This decrease of $164,314 in our cash flow operating activities consisted of increase in our non-cash expenses of $156,176; an increase in our accounts receivable of $533,564; an increase of $52,861 of our accounts payable and accrued expenses; and, an increase in our net income for the current year of $367,416. Variations in cash flow from operating activities may impact 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 consist of employee compensation, accounting, insurance and other general and administrative expenses that we have incurred in order to address normal and necessary business activities of a public company in the crude oil and natural gas production industry.

Cash Flow Used in Investing Activities. Cash flow from investing activities is derived from changes in oil and gas property balances. For the year ended March 31, 2025, we had net cash of $3,154,575 used for additions to oil and gas properties and a $1,000,000 investment in two limited liability companies compared to $3,016,499 and $400,000, respectively, for the year ended March 31, 2024.

Cash Flow Used in Financing Activities. Cash flow from financing activities is derived from our changes in long-term debt and in equity account balances. Net cash flow used in our financing activities was $834,575 for the year ended March 31, 2025 compared to net cash flow used in our financing activities of $779,723 for the year ended March 31, 2024. During the year ended March 31, 2025, we expended $209,000 to pay the annual dividend, expended $703,216 to purchase 57,766 shares of our stock for the treasury account, and received proceeds of $77,641 for the exercise of employee stock options. During the year ended March 31, 2024, we expended $213,600 to pay the annual dividend, expended $585,035 to purchase 50,101 shares of our stock for the treasury account, and received proceeds of $19,662 for the exercise of employee and director stock options.

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Accordingly, net cash decreased $719,529, leaving cash and cash equivalents on hand of $1,753,955 as of March 31, 2025.

We had working capital of $2,469,664 as of March 31, 2025 compared to working capital of $3,259,200 as of March 31, 2024, a decrease of $789,536 for the reasons set forth below.

Oil and Natural Gas Property Development.

New Participations in Fiscal 2025. The Company participated in the development of 35 horizontal wells at a cost of approximately $1,100,000 for the year ending March 31, 2025. Seventeen of these wells have not been completed. Twenty-nine of these wells are in the Delaware Basin located in the western portion of the Permian Basin in Lea and Eddy Counties, New Mexico; three wells are in the Midland Basin located in the eastern portion of the Permian Basin in Reagan County, Texas; and, the remaining three horizontal wells are in Grady County, Oklahoma.

In addition to the above working interests, there were 120 gross wells (.09 net wells) drilled by other operators on Mexco’s royalty interests and 840 gross wells (2.31 net wells) obtained through acquisitions.

Mexco expended approximately $207,000 to participate in the drilling of five horizontal wells in the Bone Spring formation of the Delaware Basin in Lea County, New Mexico. In November 2024, these wells were completed with initial average production rates of 1,106 barrels of oil, 2,583 barrels of water and 1,165,000 cubic feet of gas per day, or 1,300 BOE per day.

Mexco expended approximately $293,000 to drill and complete four horizontal wells in the Wolfcamp Sand formation of the Delaware Basin in Lea County, New Mexico. In November 2024, these wells were completed with initial average production rates of 1,089 barrels of oil, 4,716 barrels of water and 3,601,000 cubic feet of gas per day, or 1,689 BOE per day.

Mexco expended approximately $117,000 for the drilling and completion of two horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .5%. In March 2025, these wells were completed with initial average production rates of 1,734 barrels of oil, 3,171 barrels of water and 3,229,000 cubic feet of gas per day, or 2,272 BOE per day.

Mexco expended approximately $176,000 for the drilling and completion of two horizontal wells in the Penn Shale formation of the Delaware Basin in Lea County, New Mexico. Mexco’s average working interest in these wells is .5%. Subsequently, in June 2025, one of these wells were completed with initial average production rates of 676 barrels of oil, 1,899 barrels of water and 729,000 cubic feet of gas per day, or 798 BOE per day

Mexco expended approximately $46,000 for the drilling of two horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .28%.

Mexco expended approximately $70,000 to participate in the drilling of six horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .16%. Subsequently, in May 2025, Mexco expended approximately $85,000 to complete these wells.

Mexco expended approximately $70,000 to participate in the development of three horizontal wells in the Spraberry trend of the Midland Basin in Reagan County, Texas. Mexco’s working interest in these wells is approximately .26%.

Mexco expended approximately $32,000 to participate in an exploratory well in the Fusselman Formation of Irion County, Texas. This well was determined to be noncommercial and was plugged and abandoned.

In October 2022, the Company made an approximately 2% equity investment commitment in a limited liability company amounting to $2,000,000 of which $1,800,000 has been funded as of March 31, 2025. The limited liability company is capitalized at approximately $100 million to purchase mineral interests in the Utica and Marcellus areas in the state of Ohio. This LLC has returned $252,394 or 14% of the total investment.

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Completion of Wells Drilled in Fiscal 2024. The Company expended approximately $300,000 for the completion of 19 horizontal wells in which the Company participated during fiscal 2024.

The Company expended approximately $107,000 for the completion costs of two horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico that the Company participated in drilling during fiscal 2024. Mexco’s working interest in these wells is .53%. In July 2024, these wells were completed with initial average production rates of 1,402 barrels of oil, 2,009 barrels of water and 2,168,000 cubic feet of gas per day, or 1,763 BOE per day.

Five horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico in which the Company participated during fiscal 2024 were completed in April 2024 with initial average production rates of 732 barrels of oil, 1,481 barrels of water and 657,000 cubic feet of gas per day, or 842 of oil equivalent per day. Mexco’s working interest in these wells is approximately 1.16%.

A horizontal well in the Penn Shale formation of the Delaware Basin in Lea County, New Mexico was completed in May 2024 with the initial production rate of 964 barrels of oil, 2,441 barrels of water and 626,000 cubic feet of gas per day, or 1,068 of oil equivalent per day. Mexco’s working interest in this well is .165%.

The Company expended approximately $207,000 for the completion costs of four horizontial wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico that the Company participated in drilling during fiscal 2024. Mexco’s working interest in these wells is .45%. In October 2024, these wells were completed with initial average production rates of 893 barrels of oil, 2,990 barrels of water and 1,161,000 cubic feet of gas per day, or 1,087 BOE per day.

Acquisitions. In April 2024, the Company acquired royalty interests in 21 producing wells operated by Anadarko Petroleum Corporation and Cimarex Energy Company and located in Reeves County, Texas, for a purchase price of $158,000.

In August 2024, the Company acquired royalty interests in 6 producing wells operated by Marathon Oil and located in Karnes County, Texas, for a purchase price of $50,000. This acquisition was effective August 1, 2024.

In August 2024, the Company acquired royalty interests in 10 producing wells operated by Anadarko Petroleum Corporation and located in Weld County, Colorado, for a purchase price of $118,000 and royalty interests in approximately 250 producing wells operated by Samson Exploration, EOG Resources, and others in Laramie County, Wyoming and Adams and Weld Counties, Colorado, for a purchase price of $483,000. All of these acquisitions were effective September 1, 2024.

In September 2024, the Company acquired royalty interests in 21 producing wells operated by Marathon Oil and Murphy Exploration and located in Karnes County, Texas, for a purchase price of $90,000, effective August 1, 2024.

In October 2024, the Company acquired a .3% royalty interest in 15 producing wells operated by Civitas Resources, Inc. and located in Broomfield and Adams Counties, Colorado, for a purchase price of $450,000. This acquisition was effective November 1, 2024.

In October 2024, the Company acquired a .5% royalty interest in 3 producing wells operated by Mewbourne Oil Company and located in Eddy County, New Mexico, for a purchase price of $260,000. This acquisition was effective November 1, 2024 and includes acreage for further development.

In October 2024, the Company acquired royalty interests in 8 producing wells operated by Marathon Oil and located in Live Oak County, Texas, for a purchase price of $20,000; royalty interests in 6 producing wells operated by SWN Production Company, LLC and located in DeSoto Parish, Louisiana, for a purchase price of $25,000; royalty interests in 10 producing wells operated by Ovintiv, Inc. and located in Upton County, Texas, for a purchase price of $65,000; and, royalty interests in 12 producing wells operated by Pioneer Natural Resources and located in Reagan and Upton Counties, Texas, for a purchase price of $65,000. All of these acquisitions were effective November 1, 2024.

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Also, in October 2024 and effective November 1, 2024, the Company acquired various small royalty interests in over 400 producing wells operated by Petro-Hunt Corporation, Hess Bakken Investments II, LLC, Marathon Oil, WPX Energy, and others in multiple counties throughout the states of Nebraska, North Dakota, South Dakota, and Montana for a purchase price of $188,000.

Sale of Properties. In November 2024, the Company conveyed its working and royalty interests in 13.5 net acres in Ward County, Texas. The Company received $15,000 per acre in the total amount of $202,500. The Company retained an overriding royalty interest equal to the positive difference between 25% and any existing burdens of record as of the effective date. The divestiture of this non-core oil and gas asset did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded the proceeds as sales proceeds, a reduction of its full cost pool, with no gain or loss recognized on the sale.

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 generally remained volatile during the last year. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, in the last twelve months, the NYMEX West Texas Intermediate (“WTI”) posted price for crude oil has ranged from a low of $61.73 per bbl in September 2024 to a high of $82.89 per bbl in April 2024. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $1.21 per MMBtu in November 2024 to a high of $9.86 per MMBtu in January 2025.

On March 31, 2025 the WTI posted price for crude oil was $67.46 per bbl and the Henry Hub spot price for natural gas was $4.11 per MMBtu. See Results of Operations below for realized prices. Pipeline capacity constraints and maintenance in the Permian Basin area has contributed to a wider difference between the WaHa Hub and the Henry Hub and at times realized prices were negative.

Results of Operations

Fiscal 2025 Compared to Fiscal 2024

We had net income of $1,712,368 for the year ended March 31, 2025 compared to $1,344,952 for the year ended March 31, 2024, a 27% increase primarily as a result of an increase in operating revenues partially offset by an increase in operating expenses that is further explained below.

Oil and natural gas sales. Revenue from oil and natural gas sales was $7,116,485 for the year ended March 31, 2025, a 10% increase from $6,462,647 for the year ended March 31, 2024. This resulted from an increase in oil and natural gas production volumes partially offset by a decrease in oil and natural gas 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:

|  | 2025 |  |  | 2024 |  |  | % Difference |
Oil: |  |  |  |  |  |  |  |  |  |  |  |
Revenue |  | $ | 6,145,674 |  |  | $ | 5,348,257 |  |  |  | 14.9 | %
Volume (bbls) |  |  | 83,564 |  |  |  | 69,999 |  |  |  | 19.4 | %
Average Price (per bbl) |  | $ | 73.54 |  |  | $ | 76.40 |  |  |  | (3.7 | )%
Gas: |  |  |  |  |  |  |  |  |  |  |  |
Revenue |  | $ | 970,811 |  |  | $ | 1,114,390 |  |  |  | (12.9 | )%
Volume (mcf) |  |  | 570,012 |  |  |  | 502,879 |  |  |  | 13.3 | %
Average Price (per mcf) |  | $ | 1.70 |  |  | $ | 2.22 |  |  |  | (23.3 | )%

Other operating revenues. Other revenues increased 70% to $241,581 in fiscal 2025 from $142,237 in fiscal 2024. This resulted from an increase in income from one of our limited liability company investments.

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Interest income. Interest income on corporate funds decreased 46% to $72,629 in fiscal 2025 from $135,476 in fiscal 2024. This decrease resulted from using the corporate funds for property acquisitions and purchase of treasury stock.

Production and exploration. Production costs were $1,605,096 in fiscal 2025, a 5% increase from $1,526,472 in fiscal 2024. This is the result of an increase in production taxes due to an increase in oil and gas revenues and an increase in lease operating expenses on new wells in which we own an interest.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense was $2,452,694 in fiscal 2025, a 25% increase from $1,969,742 in fiscal 2024. This was primarily due to an increase in oil and natural gas production and a decrease in oil and natural gas reserves.

General and administrative expenses. General and administrative expenses were $1,320,074 for the year ended March 31, 2025, a 6% increase from $1,243,548 for the year ended March 31, 2024. This was primarily due to an increase in salaries and contract services, office expense, engineering services and legal expenses partially offset by a decrease in employee stock option compensation.

Income taxes. Income tax for fiscal 2025 was $304,330 compared to $620,544 for fiscal 2024. This was primarily due to a decrease in state income taxes and the reconciliation to the federal tax return. The effective tax rate for state and federal taxes combined for fiscal 2025 and fiscal 2024 was 15% and 32%, respectively. The decrease in the effective tax rate is primarily the result of state income taxes, primarily in New Mexico, the impact of permanent differences between book and taxable income, and the reconciliation to the federal tax return.

Contractual Obligations

We have no off-balance sheet debt or unrecorded obligations and have not guaranteed the debt of any other party. The following table summarizes future payments we are obligated to make based on agreements in place as of March 31, 2025:

|  | Payments due in: |
|  | Total |  |  | less than 1 year |  |  | 1 - 3 years |  |  | over 3 years |
Contractual obligations: |  |  |  |  |  |  |  |  |  |  |  |
Leases (1) |  | $ | 140,747 |  |  | $ | 60,320 |  |  |  | 80,427 |  |  | $ | - |

| (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 less than 1 year and $13,567 1-3 years for his portion of the shared office space.

Alternative Capital Resources

Although we have primarily used cash from operating activities, the sales of assets and funding from the credit facility as our primary capital resources, we have in the past, and could in the future, use alternative capital resources. These could include joint ventures, carried working interests and issuances of our common stock through a private placement or public offering.

Other Matters

Critical Accounting Policies and Estimates

In preparing financial statements, management makes informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to litigation, environmental liabilities, income taxes, fair value and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

The following represents those policies that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain.

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Full Cost Method of Accounting for Crude Oil and Natural Gas Activities. SEC Regulation S-X defines the financial accounting and reporting standards for companies engaged in crude oil and natural gas activities. Two methods are prescribed: the successful efforts method and the full cost method. We have chosen to follow the full cost method under which all costs associated with property acquisition, exploration and development are capitalized. We also capitalize internal costs that can be directly identified with acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation (“ARO”) when incurred.

Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of 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, Bill of Sales 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 versus the “full cost” pool basis. Additionally, gain or loss is generally recognized on all sales of crude oil and natural gas properties under the successful efforts method. As a result, our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher DD&A rate on our crude oil and natural gas properties.

At the time it was adopted, management believed that the full cost method would be preferable, as earnings tend to be less volatile than under the successful efforts method. However, the full cost method makes us more susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. These charges are not recoverable when prices return to higher levels. Our crude oil and natural gas reserves have a relatively long life. However, temporary drops in commodity prices can have a material impact on our business including impact from the full cost method of accounting.

Ceiling Test. Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test each quarter. The full cost ceiling test is an impairment test to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after-tax present value of the future net cash flows from proved crude oil and natural gas reserves plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation write-down.” This impairment to our oil and gas properties does not impact cash flow from operating activities, but does reduce our stockholders’ equity and reported earnings.

The risk that we will be required to write down the carrying value of crude oil and natural gas properties increases when crude oil and natural gas prices are depressed or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or if purchasers cancel long-term contracts for natural gas production. An expense recorded in one period may not be reversed in a subsequent period even though higher crude oil and natural gas prices may have increased the ceiling applicable to the subsequent period.

Estimates of our proved reserves are based on the quantities of oil and gas that engineering and geological analysis 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 future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

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It should not be assumed that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, the cost ceiling represents the present value (discounted at 10%) of net cash flows from sales of future production using the average price over the prior 12-month period.

The estimates of proved reserves materially impact DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost projects.

Use of Estimates. In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. In addition, significant estimates are used in determining year end proved oil and gas reserves. Although management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates. The estimate of our oil and natural gas reserves, which is used to compute DD&A and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect these reported results.

Excluded Costs. Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the DD&A pool). Impairments transferred to the DD&A pool increase the DD&A rate.

Revenue Recognition. 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 its revenue estimates and actual revenue received historically have not been significant.

Asset Retirement Obligations. The estimated costs of plugging, restoration and removal of facilities are accrued. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated by the units of production method. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. For all periods presented, we have included estimated future costs of abandonment and dismantlement in the full cost amortization base and amortize these costs as a component of our depletion expense.

Stock-based Compensation. We use the Binomial option pricing model to estimate the fair value of stock-based compensation expenses at grant date. This expense is recognized as compensation expense in our financial statements over the vesting period. We recognize the fair value of stock-based compensation awards as wages in the Consolidated Statements of Operations based on a graded-vesting schedule over the vesting period.

Accounts Receivable. Our accounts receivable includes trade receivables from joint interest owners and oil and gas purchasers. Credit is extended based on an evaluation of a customer’s financial condition and, generally, is uncollateralized. 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.

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Income Taxes. The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates applicable to the years in which those differences are expected to be settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income in the period that includes the enactment date. Any interest and penalties are recorded as interest expense and general and administrative expense, respectively.

Other Property and Equipment. Provisions for depreciation of office furniture and equipment are computed on the straight-line method based on estimated useful lives of three to ten years.

Investments. The Company accounts for investments of less than 3% of any limited liability companies at cost. The Company has no control of the limited liability companies. The cost of the investment is recorded as an asset on the consolidated balance sheets and when income from the investment is received, it is immediately recognized on the consolidated statements of operations. The Company evaluates investments for an impairment whenever events or changes in circumstances indicate that the carrying amount of an investment may not be recoverable. Indicators of impairment may include, but are not limited to, sustained declines in market value, investee financial condition and operating performance, industry or economic trends, and other relevant factors.

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. Based on the Company’s organizational structure, the Company has one operating segment, which is crude oil and natural gas development, exploration and production. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise.

Leases. The Company determines an arrangement is a lease at inception. Operating leases are recorded in operating lease right-of-use asset, operating lease liability, current, and operating lease liability, long-term on the consolidated balance sheets.

Operating lease right-of-use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent its obligation to make lease payments arising from the lease. Operating lease assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. As the Company’s lease does not provide an implicit rate, the Company uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The incremental borrowing rate used at adoption was 9%. Significant judgement is required when determining the incremental borrowing rate. Rent expense for lease payments is recognized on a straight-line basis over the lease term.

Recently Adopted Accounting Pronouncements. In December 2023, the FASB issued ASU 2023-09, Topic 740 Income Taxes: Improvements to Income Tax Disclosures, which is intended to enhance the transparency and decision usefulness of income tax disclosures. The amendments in this standard provide for enhanced income tax information primarily through changs to the rate reconciliation and income taxes paid. This ASU is effective for fiscal years beginning after December 15, 2024. 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.

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.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary source of market risk for us includes fluctuations in commodity prices and interest rates. All of our financial instruments are for purposes other than trading.

Credit Risk. Credit risk is the risk of loss as a result of nonperformance by other parties of their contractual obligations. Our primary credit risk is related to oil and gas production sold to various purchasers and the receivables are generally not collateralized. At March 31, 2025, our largest credit risk associated with any single purchaser was $478,863 or 43% of our total oil and gas receivables. We have not experienced any significant credit losses.

Energy Price Risk. Our most significant market risk is the pricing applicable to our crude oil and natural gas production. Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. Prices for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future.

Factors that can cause price fluctuations include the level of global demand for petroleum products, foreign and domestic supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels and overall political and economic conditions in oil producing and consuming countries.

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For example, in the last twelve months, the NYMEX West Texas Intermediate (“WTI”) posted price for crude oil has ranged from a low of $61.73 per bbl in September 2024 to a high of $82.89 per bbl in April 2024. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $1.21 per MMBtu in November 2024 to a high of $9.86 per MMBtu in January 2025.

On March 31, 2025 the WTI posted price for crude oil was $67.46 per bbl and the Henry Hub spot price for natural gas was $4.11 per MMBtu. See Results of Operations above for realized prices. Pipeline capacity constraints and maintenance in the Permian Basin area has contributed to a wider difference between the WaHa Hub and the Henry Hub and at times realized prices were negative. Subsequently, on June 16, 2025, the WTI posted price for crude oil was $67.75 and the Henry Hub posted price for natural gas was $2.90.

Declines in oil and natural gas prices will materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Changes in oil and gas prices impact both estimated future net revenue and the estimated quantity of proved reserves. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our credit facility and adversely affect the amount of cash flow available for capital expenditures and our ability to obtain additional capital for our acquisition, exploration and development activities. In addition, a noncash write-down of our oil and gas properties could be required under full cost accounting rules if prices declined significantly, even if it is only for a short period of time. See Critical Accounting Policies and Estimates — Ceiling Test under Item 7 of this report on Form 10-K. Lower prices may also reduce the amount of crude oil and natural gas that can be produced economically. Thus, we may experience material increases or decreases in reserve quantities solely as a result of price changes and not as a result of drilling or well performance.

Similarly, any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. If the average oil price had increased or decreased by ten dollars per barrel for fiscal 2025, our pretax income would have changed by $835,640. If the average gas price had increased or decreased by one dollar per mcf for fiscal 2025, pretax income would have changed by $570,012.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this item appears on pages F2 through F20 hereof and are incorporated herein by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES

None.

ITEM 9A. CONTROLS AND PROCEDURES

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

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

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Our chief executive officer and chief financial officer assessed the effectiveness our internal control over financial reporting using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in the 2013 “Internal Control - Integrated Framework”. Based upon that evaluation, our chief executive officer and chief financial officer concluded that our internal control over financial reporting was effective as of March 31, 2025.

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, 2025, 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, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTION

Not applicable

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

See “Mexco Energy Corporation Board of Directors”, “Named Executive Officers Who Are Not Directors”, “Section 16(a) Beneficial Ownership Reporting Compliance”, “Corporate Governance and Code of Business Conduct” and “Meetings and Committees of the Board of Directors” in the Proxy Statement of Mexco Energy Corporation for our Annual Meeting of Stockholders to be held September 9, 2025 (“Proxy Statement”) to be filed with the SEC within 120 days after the end of our fiscal year ended March 31, 2025, which is incorporated herein by reference.

The information required by this item with respect to executive officers of the Company is also set forth in Part I of this report.

ITEM 11. EXECUTIVE COMPENSATION

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

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this item will be contained in the Proxy Statement under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Employee Incentive Stock Option Plans”, and is hereby incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this item will be contained in the Proxy Statement under the captions “Certain Relationships and Related Transactions” and “Meetings and Committees of the Board of Directors”, and is hereby incorporated by reference herein.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this item will be contained in the Proxy Statement under the caption “Audit Fees and Services”, and is hereby incorporated by reference herein.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Consolidated Financial Statements. For a list of the consolidated financial statements filed as part of this Form 10-K, see the “Index to Consolidated Financial Statements” set forth on F-1 of this report.

Financial Statement Schedules. All schedules have been omitted because they are not applicable, not required under the instructions or the information requested is set forth in the consolidated financial statements or related notes thereto.

Exhibits. For a list of the exhibits required by this Item and accompanying this Form 10-K see the “Index to Exhibits” set forth on page 37 of this report.

ITEM 16. FORM 10-K SUMMARY

None

32

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

MEXCO ENERGY CORPORATION

By: | /s/ Nicholas C. Taylor |  | By: | /s/ Tamala L. McComic
| Chairman of the Board and Chief Executive Officer |  |  | President and Chief Financial Officer

Dated: June 27, 2025

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of June 27, 2025, by the following persons on behalf of the Registrant and in the capacity indicated.

/s/ Nicholas C. Taylor |
Nicholas C. Taylor |
Chief Executive Officer, Chairman of the Board of Directors |
/s/ Tamala L. McComic |
Tamala L. McComic |
Chief Financial Officer, President, Treasurer and Assistant Secretary |
/s/ Michael J. Banschbach |
Michael J. Banschbach |
Director |
/s/ Kenneth L. Clayton |
Kenneth L. Clayton |
Director |
/s/ Thomas R. Craddick |
Thomas R. Craddick |
Director |
/s/ Thomas H. Decker |
Thomas H. Decker |
Director |
/s/ Christopher M. Schroeder |
Christopher M. Schroeder |
Director |

33

Glossary of Abbreviations and Terms

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report.

Basin. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used herein in reference to crude oil, condensate or natural gas liquids hydrocarbons.

BOE. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

BTU. British thermal unit.

Completion. The installation of permanent equipment for the production of oil or natural gas.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Credit Facility. A line of credit provided by a bank or group of banks, secured by oil and gas properties.

DD&A. Refers to depreciation, depletion and amortization of the Company’s property and equipment.

Developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

Development well. A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploration. The search for natural accumulations of oil and natural gas by any geological, geophysical or other suitable means.

Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Extensions and discoveries. As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Formation. A layer of rock which has distinct characteristics that differs from nearby rock.

Gross acres or wells. Refers to the total acres or wells, as the case may be, in which an interest is owned any amount of working interest.

Lease. An instrument which grants to another (the lessee) the exclusive right to enter and explore for, drill for, produce, store and remove oil and natural gas from the mineral interest, in consideration for which the lessor is entitled to certain rents and royalties payable under the terms of the lease. Typically, the duration of the lessee’s authorization is for a stated term of years and “for so long thereafter” as minerals are producing.

Mcf. One thousand cubic feet of natural gas.

34

MBOE. One thousand barrels of oil equivalent.

MMBOE. One million barrels of oil equivalent.

MMBtu. One million British thermal units of energy commonly used to measure heat value or energy content of natural gas.

Natural gas liquids (“NGLs”). Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline.

Net acres or wells. Refers to gross acres or wells multiplied, in each case, by the percentage interest owned by the Company.

Net production. Oil and gas production that is owned by the Company, less royalties and production due others.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

Oil. Crude oil or condensate.

Operator. The individual or company responsible for the exploration, development and production of an oil or natural gas well or lease.

Overriding royalty interest (“ORRI”). A royalty interest that is created out of the operating or working interest. Its term is coextensive with that of the operating interest from which it was created.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed operating and production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed nonproducing reserves (“PDNP”). Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.

Proved developed producing reserves (“PDP”). Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.

Proved developed reserves. The combination of proved developed producing and proved developed nonproducing reserves.

Proved reserves. The estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves (“PUD”). Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

35

PV-10. When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses except for specific general and administrative expenses incurred to operate the properties, discounted to a present value using an annual discount rate of 10%.

Recompletion. A process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Royalty. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage, or of the proceeds of the sale thereof, but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Standardized measure of discounted future net cash flows. The discounted future net cash flows relating to proved reserves based on prices used in estimating the reserves, year-end costs, and statutory tax rates, and a 10% annual discount rate. The information for this calculation is included in the note regarding disclosures about oil and gas reserve data contained in the Notes to Consolidated Financial Statements included in this Form 10-K.

Undeveloped acreage. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Unit. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

Wellbore. The hole drilled by the bit that is equipped for crude oil or natural gas production on a completed well. Also called well or borehole.

Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden.

36

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm | F-2
Consolidated Balance Sheets | F-4
Consolidated Statements of Operations | F-5
Consolidated Statements of Changes in Stockholders’ Equity | F-6
Consolidated Statements of Cash Flows | F-7
Notes to Consolidated Financial Statements | F-8

F-1

Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

Mexco Energy Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Mexco Energy Corporation (a Colorado corporation) and Subsidiaries (the Company) as of March 31, 2025 and 2024, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the two years in the period ended March 31, 2025, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of March 31, 2025 and 2024, and the results of its operations and its cash flows for each of the two years in the period ended March 31, 2025, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the entity’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Estimation of proved reserves impacting the recognition and valuation of depletion expense and impairment of oil and gas properties.

F-2

Critical Accounting Matter Description

As described in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future revenues and expenses to calculate depletion expense. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion expense. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense and impairment evaluation, as a critical audit matter.

The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity necessary to estimate the volume and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or the impairment assessment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.

How the Critical Audit Matter Was Addressed in the Audit

We obtained an understanding of the design and implementation of management’s controls and our audit procedures related to the estimation of proved reserves included the following, among others.

| ● | We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists.

| ● | To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, such as commodity pricing, historical pricing differentials, operating costs, estimated capital costs and working and net revenue interests, we tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis. Specifically, our audit procedures involved testing management’s assumptions as follows:

| - | Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year;

| - | Evaluated the models used to estimate the operating costs at year-end compared to historical operating costs;

| - | Compared the models used to determine the future capital expenditures and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells;

| - | Evaluated the working and net revenue interests used in the reserve report by inspecting a sample of ownership interests, historical pricing differentials, and operating costs to underlying support from the Company’s accounting records.

| - | Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s or the operator’s intent to develop the proved undeveloped properties;

| - | Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report.

/s/ WEAVER AND TIDWELL, L.L.P.

We have served as the Company’s auditor since 2017.

PCAOB ID #410

Midland, Texas

June 27, 2025

F-3

Mexco Energy Corporation and Subsidiaries

CONSOLIDATED BALANCE SHEETS

|  | March 31, |  |  | March 31, |
|  | 2025 |  |  | 2024 |
ASSETS |  |  |  |  |  |  |  |
Current assets |  |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 1,753,955 |  |  | $ | 2,473,484 |
Accounts receivable: |  |  |  |  |  |  |  |
Oil and natural gas sales |  |  | 1,113,588 |  |  |  | 1,001,709 |
Trade |  |  | 67,951 |  |  |  | 9,186 |
Prepaid drilling |  |  | 24,381 |  |  |  | 148,748 |
Prepaid costs and expenses |  |  | 60,981 |  |  |  | 56,193 |
Total current assets |  |  | 3,020,856 |  |  |  | 3,689,320 |
Property and equipment, at cost |  |  |  |  |  |  |  |
Oil and gas properties, using the full cost method |  |  | 51,611,782 |  |  |  | 48,304,585 |
Other |  |  | 121,926 |  |  |  | 121,926 |
Accumulated depreciation, depletion and amortization |  |  | (36,637,530 | ) |  |  | (34,184,837 | )
Property and equipment, net |  |  | 15,096,178 |  |  |  | 14,241,674 |
Investment – cost basis |  |  | 2,100,000 |  |  |  | 1,100,000 |
Operating lease, right-of-use asset |  |  | 126,525 |  |  |  | 19,263 |
Other noncurrent assets |  |  | 4,298 |  |  |  | 8,597 |
Total assets |  | $ | 20,347,857 |  |  | $ | 19,058,854 |
LIABILITIES AND STOCKHOLDERS’ EQUITY |  |  |  |  |  |  |  |
Current liabilities |  |  |  |  |  |  |  |
Accounts payable and accrued expenses |  | $ | 307,387 |  |  | $ | 221,603 |
Income tax payable |  |  | 192,802 |  |  |  | 189,254 |
Operating lease liability, current |  |  | 51,003 |  |  |  | 19,263 |
Total current liabilities |  |  | 551,192 |  |  |  | 430,120 |
Long-term liabilities |  |  |  |  |  |  |  |
Operating lease liability, long-term |  |  | 75,522 |  |  |  | - |
Deferred income tax liability |  |  | 320,604 |  |  |  | 311,661 |
Asset retirement obligations |  |  | 688,842 |  |  |  | 688,808 |
Total long-term liabilities |  |  | 1,084,968 |  |  |  | 1,000,469 |
Total liabilities |  |  | 1,636,160 |  |  |  | 1,430,589 |
Commitments and contingencies |  |  | - |  |  |  | - |
Stockholders’ equity |  |  |  |  |  |  |  |
Preferred stock - $1.00 par value; 10,000,000 shares authorized; none outstanding |  |  | - |  |  |  | - |
Common stock - $0.50 par value; 40,000,000 shares authorized; 2,239,283 and 2,226,916 shares issued; and, 2,046,000 and 2,091,399 shares outstanding as of March 31, 2025 and 2024 |  |  | 1,119,641 |  |  |  | 1,113,458 |
Additional paid-in capital |  |  | 8,844,953 |  |  |  | 8,567,856 |
Retained earnings |  |  | 10,625,849 |  |  |  | 9,122,481 |
Treasury stock, at cost (193,283 and 135,517 shares, respectively) |  |  | (1,878,746 | ) |  |  | (1,175,530 | )
Total stockholders’ equity |  |  | 18,711,697 |  |  |  | 17,628,265 |
Total liabilities and stockholders’ equity |  | $ | 20,347,857 |  |  | $ | 19,058,854 |

The accompanying notes to the consolidated financial statements are an integral part of these statements.

F-4

Mexco Energy Corporation and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS

Years ended March 31,

|  | 2025 |  |  | 2024 |
Operating revenues: |  |  |  |  |  |  |  |
Oil sales |  | $ | 6,145,674 |  |  | $ | 5,348,257 |
Natural gas sales |  |  | 970,811 |  |  |  | 1,114,390 |
Other |  |  | 241,581 |  |  |  | 142,237 |
Total operating revenues |  |  | 7,358,066 |  |  |  | 6,604,884 |
Operating expenses: |  |  |  |  |  |  |  |
Production |  |  | 1,605,096 |  |  |  | 1,526,472 |
Accretion of asset retirement obligation |  |  | 29,983 |  |  |  | 29,869 |
Depreciation, depletion and amortization |  |  | 2,452,694 |  |  |  | 1,969,742 |
General and administrative |  |  | 1,320,074 |  |  |  | 1,243,547 |
Total operating expenses |  |  | 5,407,847 |  |  |  | 4,769,630 |
Operating income |  |  | 1,950,219 |  |  |  | 1,835,254 |
Other income (expenses): |  |  |  |  |  |  |  |
Interest income |  |  | 72,629 |  |  |  | 135,476 |
Interest expense |  |  | (6,150 | ) |  |  | (5,234 | )
Net other income (expense) |  |  | 66,479 |  |  |  | 130,242 |
Income before provision for income taxes |  |  | 2,016,698 |  |  |  | 1,965,496 |
Provision for income taxes |  |  | 304,330 |  |  |  | 620,544 |
Net income |  | $ | 1,712,368 |  |  | $ | 1,344,952 |
Income per common share: |  |  |  |  |  |  |  |
Basic: |  | $ | 0.83 |  |  | $ | 0.64 |
Diluted: |  | $ | 0.81 |  |  | $ | 0.62 |
Weighted average common shares outstanding: |  |  |  |  |  |  |  |
Basic: |  |  | 2,064,147 |  |  |  | 2,114,360 |
Diluted: |  |  | 2,107,775 |  |  |  | 2,161,010 |
Dividends declared per share |  | $ | 0.10 |  |  | $ | 0.10 |

The accompanying notes to the consolidated financial statements are an integral part of these statements.

F-5

Mexco Energy Corporation and Subsidiaries

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

Years ended March 31, 2025 and 2024

|  | Common Stock Par Value |  |  | Additional Paid-In Capital |  |  | Retained Earnings |  |  | Treasury Stock |  |  | Total Stockholders’ Equity |
Balance at April 1, 2023 |  | $ | 1,110,708 |  |  | $ | 8,321,145 |  |  | $ | 7,991,129 |  |  | $ | (590,495 | ) |  | $ | 16,832,487 |
Net income |  |  | - |  |  |  | - |  |  |  | 1,344,952 |  |  |  | - |  |  |  | 1,344,952 |
Issuance of stock through options exercised |  |  | 2,750 |  |  |  | 16,912 |  |  |  | - |  |  |  | - |  |  |  | 19,662 |
Dividends paid |  |  |  |  |  |  |  |  |  |  | (213,600 | ) |  |  |  |  |  |  | (213,600 | )
Purchase of stock |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (585,035 | ) |  |  | (585,035 | )
Stock based compensation |  |  | - |  |  |  | 229,799 |  |  |  | - |  |  |  | - |  |  |  | 229,799 |
Balance at March 31, 2024 |  | $ | 1,113,458 |  |  | $ | 8,567,856 |  |  | $ | 9,122,481 |  |  | $ | (1,175,530 | ) |  | $ | 17,628,265 |
Balance |  | $ | 1,113,458 |  |  | $ | 8,567,856 |  |  | $ | 9,122,481 |  |  | $ | (1,175,530 | ) |  | $ | 17,628,265 |
Net income |  |  | - |  |  |  | - |  |  |  | 1,712,368 |  |  |  | - |  |  |  | 1,712,368 |
Issuance of stock through options exercised |  |  | 6,183 |  |  |  | 71,458 |  |  |  | - |  |  |  | - |  |  |  | 77,641 |
Dividends paid |  |  | - |  |  |  | - |  |  |  | (209,000 | ) |  |  | - |  |  |  | (209,000 | )
Purchase of stock |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (703,216 | ) |  |  | (703,216 | )
Stock based compensation |  |  | - |  |  |  | 205,639 |  |  |  | - |  |  |  | - |  |  |  | 205,639 |
Balance at March 31, 2025 |  | $ | 1,119,641 |  |  | $ | 8,844,953 |  |  | $ | 10,625,849 |  |  | $ | (1,878,746 | ) |  | $ | 18,711,697 |
Balance |  | $ | 1,119,641 |  |  | $ | 8,844,953 |  |  | $ | 10,625,849 |  |  | $ | (1,878,746 | ) |  | $ | 18,711,697 |

SHARE ACTIVITY

|  | 2025 |  |  | 2024 |
Common stock shares, issued: |  |  |  |  |  |  |  |
At beginning of year |  |  | 2,226,916 |  |  |  | 2,221,416 |
Issued |  |  | 12,367 |  |  |  | 5,500 |
At end of year |  |  | 2,239,283 |  |  |  | 2,226,916 |
Common stock shares, held in treasury: |  |  |  |  |  |  |  |
At beginning of year |  |  | (135,517 | ) |  |  | (85,416 | )
Acquisitions |  |  | (57,766 | ) |  |  | (50,101 | )
At end of year |  |  | (193,283 | ) |  |  | (135,517 | )
Common stock shares, outstanding |  |  |  |  |  |  |  |
At end of year |  |  | 2,046,000 |  |  |  | 2,091,399 |

The accompanying notes to the consolidated financial statements are an integral part of these statements.

F-6

Mexco Energy Corporation and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years ended March 31,

|  | 2025 |  |  | 2024 |
Cash flows from operating activities: |  |  |  |  |  |  |  |
Net income |  | $ | 1,712,368 |  |  | $ | 1,344,952 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |  |  |  |
Deferred income tax expense |  |  | 8,943 |  |  |  | 311,661 |
Stock-based compensation |  |  | 205,639 |  |  |  | 229,799 |
Depreciation, depletion and amortization |  |  | 2,452,694 |  |  |  | 1,969,742 |
Accretion of asset retirement obligations |  |  | 29,983 |  |  |  | 29,869 |
Amortization of debt issuance costs |  |  | 4,299 |  |  |  | 4,309 |
Changes in operating assets and liabilities: |  |  |  |  |  |  |  |
(increase) Decrease in accounts receivable |  |  | (170,644 | ) |  |  | 362,920 |
(Increase) decrease in right-of-use asset |  |  | (107,262 | ) |  |  | 56,366 |
(increase) Decrease in prepaid expenses |  |  | (4,788 | ) |  |  | 309 |
Increase in accounts payable and accrued expenses |  |  | 69,059 |  |  |  | 16,198 |
Increase (decrease) in operating lease liability |  |  | 107,262 |  |  |  | (56,366 | )
Increase in income tax payable |  |  | 3,548 |  |  |  | 189,254 |
Settlement of asset retirement obligations |  |  | (41,480 | ) |  |  | (25,078 | )
Net cash provided by operating activities |  |  | 4,269,621 |  |  |  | 4,433,935 |
Cash flows from investing activities: |  |  |  |  |  |  |  |
Additions to oil and gas properties |  |  | (3,416,616 | ) |  |  | (3,349,326 | )
Drilling refund |  |  | 59,471 |  |  |  | 26,194 |
Investment in limited liability companies at cost |  |  | (1,000,000 | ) |  |  | (400,000 | )
Proceeds from sale of oil and gas properties and equipment |  |  | 202,570 |  |  |  | 306,633 |
Net cash used in investing activities |  |  | (4,154,575 | ) |  |  | (3,416,499 | )
Cash flows from financing activities: |  |  |  |  |  |  |  |
Proceeds from exercise of stock options |  |  | 77,641 |  |  |  | 19,662 |
Proceeds from long-term debt |  |  | 650,000 |  |  |  | 275,000 |
Debt issuance costs |  |  | - |  |  |  | (750 | )
Dividends paid |  |  | (209,000 | ) |  |  | (213,600 | )
Acquisition of treasury stock |  |  | (703,216 | ) |  |  | (585,035 | )
Reduction of long-term debt |  |  | (650,000 | ) |  |  | (275,000 | )
Net cash used in financing activities |  |  | (834,575 | ) |  |  | (779,723 | )
Net (decrease) increase in cash and cash equivalents |  |  | (719,529 | ) |  |  | 237,713 |
Cash and cash equivalents at beginning of year |  |  | 2,473,484 |  |  |  | 2,235,771 |
Cash and cash equivalents at end of year |  | $ | 1,753,955 |  |  | $ | 2,473,484 |
Supplemental disclosure of cash flow information: |  |  |  |  |  |  |  |
Cash paid for interest |  | $ | 1,852 |  |  | $ | 925 |
Cash paid for income taxes |  | $ | 228,487 |  |  | $ | - |
Accrued capital expenditures included in accounts payable |  | $ | 38,417 |  |  | $ | 21,693 |
Non-cash investing and financing activities: |  |  |  |  |  |  |  |
Asset retirement obligations |  | $ | 5,231 |  |  | $ | 7,617 |

The accompanying notes to the consolidated financial statements are an integral part of these statements.

F-7

MEXCO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended March 31, 2025 and 2024

1. Nature of Operations

Mexco Energy Corporation (a Colorado corporation) and its wholly owned subsidiaries, Forman Energy Corporation (a New York corporation), Southwest Texas Disposal Corporation (a Texas corporation) and TBO Oil & Gas, LLC (a Texas limited liability company) (collectively, the “Company”) are engaged in the acquisition, exploration, development and production of crude oil, natural gas, condensate and natural gas liquids (“NGLs”). Most of the Company’s oil and gas interests are centered in West Texas and Southeastern New Mexico; however, the Company owns producing properties and undeveloped acreage in fourteen states. All of the Company’s oil and gas interests are operated by others.

2. Summary of Significant Accounting Policies

Principles of Consolidation. The consolidated financial statements include the accounts of Mexco Energy Corporation and its wholly owned subsidiaries. All significant intercompany balances and transactions associated with the consolidated operations have been eliminated.

Estimates and Assumptions. 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.

Cash and Cash Equivalents. The Company considers all highly liquid debt instruments purchased with maturities of three months or less and money market funds to be cash equivalents. The Company maintains cash in bank deposit accounts that may, at times, exceed federally insured limits. At March 31, 2025, the Company had on deposit all of its cash and cash equivalents with three financial institutions. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk.

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, generally, is 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. The Company has not experienced any significant credit losses. For the years ended March 31, 2025 and 2024, no allowance has been made for any credit losses.

Oil and Gas Properties. The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs are capitalized and amortized on a composite unit of production method based on proved oil and natural gas reserves. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation (“ARO”) when incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments 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, Bill of Sales and Conveyances. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves.

F-8

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 depreciation, depletion and amortization (“DD&A”) pool). Impairments transferred to the DD&A pool increase the DD&A rate. No costs were excluded for the years ended March 31, 2025 and 2024.

Ceiling Test. Under the full cost method of accounting, a ceiling test is performed 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 the after-tax present value of the future net cash flows from proved crude oil and natural gas reserves and using an average price over the prior first day of the month 12-month period held flat for the life of production 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, the Company must charge the amount of the excess to earnings as an expense reflected in additional accumulated DD&A. This is called a “ceiling limitation write-down.” This impairment to our oil and gas properties does not impact cash flow from operating activities, but does reduce stockholders’ equity and reported earnings.

Depreciation, Depletion and Amortization. The depreciable base for oil and gas properties includes the sum of capitalized costs, net of accumulated DD&A, estimated future development costs and asset retirement costs not accrued in oil and gas properties, less costs excluded from amortization and salvage. The depreciable base of oil and gas properties is amortized using the unit-of-production method.

Asset Retirement Obligations. The Company has significant obligations to plug and abandon natural gas and crude oil wells and related equipment at the end of oil and gas production operations. The Company records the fair value of a liability for an ARO in the period in which it is incurred and a corresponding increase in the carrying amount of the related asset. Subsequently, the asset retirement costs included in the carrying amount of the related asset are allocated to expense using the units of production method. In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense in the Consolidated Statements of Operations.

Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. The Company uses the present value of estimated cash flows related to the ARO to determine the fair value. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset.

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 three3 to ten years.

Income Per Common Share. Basic net income per share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted net income per share assumes the exercise of all stock options having exercise prices less than the average market price of the common stock during the period using the treasury stock method and is computed by dividing net income by the weighted average number of common shares and dilutive potential common shares (stock options) outstanding during the period. In periods where losses are reported, the weighted-average number of common shares outstanding excludes potential common shares, because their inclusion would be anti-dilutive.

F-9

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 its revenue estimates and actual revenue received historically have not been significant.

Stock-based Compensation. The Company uses the Binomial option pricing model to estimate the fair value of stock-based compensation expenses at grant date. This expense is recognized as compensation expense in its consolidated financial statements over the vesting period. The Company recognizes the fair value of stock-based compensation awards as wages within general and administrative expense in the Consolidated Statements of Operations based on a graded-vesting schedule over the vesting period.

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.

Investments. The Company accounts for investments of less than 3% in limited liability companies at cost. The Company has no control of the limited liability companies. The cost of the investment is recorded as an asset on the consolidated balance sheets and when income from the investment is received, it is immediately recognized on the consolidated statements of operations. The Company evaluates investments for an impairment whenever events or changes in circumstances indicate that the carrying amount of an investment may not be recoverable. Indicators of impairment may include, but are not limited to, sustained declines in market value, investee financial condition and operating performance, industry or economic trends, and other relevant factors.

Segments. Based on the Company’s organizational structure, the Company has one operating segment, which is crude oil and natural gas development, exploration and production. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise.

Liquidity and Capital Resources. Historically, we have funded our operations, acquisitions, exploration and development expenditures from cash generated by operating activities, bank borrowings, sales of non-core properties and issuance of common stock. Our long-term strategy is on increasing profit margins while concentrating on obtaining reserves with low-cost operations by acquiring and developing oil and gas properties with potential for long-lived production. We focus our efforts on the acquisition of royalties and working interest, non-operated properties in areas with significant development potential.

Recently Adopted Accounting Pronouncements. In December 2023, the FASB issued ASU 2023-09, Topic 740 Income Taxes: Improvements to Income Tax Disclosures, which is intended to enhance the transparency and decision usefulness of income tax disclosures. The amendments in this standard provide for enhanced income tax information primarily through changs to the rate reconciliation and income taxes paid. This ASU is effective for fiscal years beginning after December 15, 2024. 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.

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.

3. Long-Term Debt

On December 28, 2018, the Company entered into a loan agreement (the “Agreement”) with West Texas National Bank (“WTNB”), which originally provided for a credit facility of $1,000,000 with a maturity date of December 28, 2021. The Agreement has no monthly commitment reduction and a borrowing base to be evaluated annually. On February 28, 2020, the Agreement was amended to increase the credit facility to $2,500,000, extend the maturity date to March 28, 2023 and increase the borrowing base to $1,500,000. On March 28, 2023, the Agreement was amended to extend the maturity date to March 28, 2026.

Under the Agreement, interest on the facility accrues at a rate equal to the prime rate as quoted in the Wall Street Journal plus one-half of one percent (.5%) floating daily. Interest on the outstanding amount under the Agreement is payable monthly. In addition, the Company will pay an unused commitment fee in an amount equal to one-half of one percent (.5%) times the daily average of the unadvanced amount of the commitment. The unused commitment fee is payable quarterly in arrears on the last day of each calendar quarter. As of March 31, 2025, there was $1,500,000 available for borrowing by the Company on the facility.

F-10

No principal payments are anticipated to be required through the maturity date of the credit facility, March 28, 2026. Upon closing the second amendment to the Agreement, the Company paid a loan origination fee of $9,000 plus legal and recording expenses totaling $12,950, which are amortized over the life of the credit facility.

Amounts borrowed under the Agreement are collateralized by the common stock of the Company’s wholly owned subsidiaries and substantially all of the Company’s oil and gas properties.

The Agreement contains customary covenants for credit facilities of this type including limitations on change in control, disposition of assets, mergers and reorganizations. The Company is also obligated to meet certain financial covenants under the Agreement and requires senior debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”) ratios (Senior Debt/EBITDA) less than or equal to 4.00 to 1.00 measured with respect to the four trailing quarters and minimum interest coverage ratios (EBITDA/Interest Expense) of 2.00 to 1.00 for each quarter.

In addition, the Agreement prohibits the Company from paying cash dividends on its common stock without prior written permission of WTNB. The Company obtained written permission from WTNB prior to declaring the special dividend on April 10, 2023 and the regular annual dividend on April 30, 2024 as discussed in Note 9. The Agreement does not permit the Company to enter into hedge agreements covering crude oil and natural gas prices without prior WTNB approval.

There was no balance outstanding on the credit facility as of March 31, 2025. The following table is a summary of activity on the WTNB credit facility for the years ended March 31, 2025 and 2024:

Summary of Line of Credit Activity

|  | Principal |
Balance at April 1, 2023: |  | $ | - |
Borrowings |  |  | 275,000 |
Repayments |  |  | (275,000 | )
Balance at March 31, 2024: |  | $ | - |
Borrowings |  |  | 650,000 |
Repayments |  |  | (650,000 | )
Balance at March 31, 2025: |  | $ | - |

4. Asset Retirement Obligations

The Company’s asset retirement obligations relate to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties. The ARO is included on the consolidated balance sheets with the current portion being included in the accounts payable and accrued expenses.

The following table provides a rollforward of the asset retirement obligations for fiscal years ended March 31:

Schedule of Rollforward of Asset Retirement Obligations

|  | 2025 |  |  | 2024 |
Carrying amount of asset retirement obligations, beginning of year |  | $ | 718,808 |  |  | $ | 730,276 |
Liabilities incurred |  |  | 5,231 |  |  |  | 7,617 |
Liabilities settled |  |  | (35,180 | ) |  |  | (48,954 | )
Accretion expense |  |  | 29,983 |  |  |  | 29,869 |
Revisions |  |  | - |  |  |  | - |
Carrying amount of asset retirement obligations, end of year |  |  | 718,842 |  |  |  | 718,808 |
Less: Current portion |  |  | 30,000 |  |  |  | 30,000 |
Non-Current asset retirement obligation |  | $ | 688,842 |  |  | $ | 688,808 |

5. Income Taxes

In August 2022, President Biden signed the Inflation Reduction Act of 2022 (“IRA 2022”). The IRA 2022, among other tax provisions, imposes a 15% corporate alternative minimum tax on adjusted financial statement income of certain large corporations (generally, corporations reporting more than $1 billion of average adjusted pre-tax net income on their consolidated financial statements), effective for tax years beginning after December 31, 2022. The IRA 2022 also establishes a 1% excise tax on stock repurchases made by publicly traded U.S. corporations, effective for stock repurchases after December 31, 2022. The IRA 2022 did not impact the Company’s current year tax provision or the Company’s consolidated financial statements.

F-11

The Company files a consolidated federal income tax return and various state income tax returns. The amount of income taxes the Company records requires the interpretation of complex rules and regulations of federal and state taxing jurisdictions. With few exceptions, the earliest year open to examination by U.S. federal and state income tax jurisdictions is 2020.

The income tax provision consists of the following for the years ended March 31, 2025 and 2024:

Schedule of Income Tax Provision

|  | 2025 |  |  | 2024 |
|  | Year Ended |
|  | March 31 |
|  | 2025 |  |  | 2024 |
Current income tax expense: |  |  |  |  |  |  |  |
Federal |  | $ | 232,035 |  |  | $ | 189,254 |
State |  |  | 63,352 |  |  |  | 119,629 |
Total current income tax expense |  | $ | 295,387 |  |  | $ | 308,883 |
Deferred income tax expense (benefit): |  |  |  |  |  |  |  |
Federal |  |  | 56,614 |  |  |  | 311,661 |
State |  |  | (47,671 | ) |  |  | - |
Total deferred income tax expense |  | $ | 8,943 |  |  | $ | 311,661 |
Total income tax expense: |  | $ | 304,330 |  |  | $ | 620,544 |

Income tax for the year ended March 31, 2025 was $304,330. Income tax for the year ended March 31, 2024 was $620,544.

GAAP requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Significant components of net deferred tax assets (liabilities) at March 31 are as follows:

Schedule of Components of Net Deferred Tax Assets (Liabilities)

|  | 2025 |  |  | 2024 |
Deferred tax assets: |  |  |  |  |  |  |  |
Percentage depletion carryforwards |  | $ | 1,283,374 |  |  | $ | 1,281,990 |
Deferred stock-based compensation |  |  | 15,745 |  |  |  | 15,745 |
Asset retirement obligation |  |  | 150,957 |  |  |  | 150,950 |
Net operating loss |  |  | - |  |  |  | 151,193 |
Other |  |  | 82,083 |  |  |  | 35,345 |
Total deferred tax assets |  | $ | 1,532,159 |  |  | $ | 1,635,223 |
Deferred tax liabilities: |  |  |  |  |  |  |  |
Excess financial accounting bases over tax bases of property and equipment |  |  | (1,852,763 | ) |  |  | (1,946,884 | )
Deferred tax liability, net |  | $ | (320,604 | ) |  | $ | (311,661 | )
Valuation allowance |  |  | - |  |  |  | - |
Net deferred tax liabilities |  | $ | (320,604 | ) |  | $ | (311,661 | )

As of March 31, 2025, the Company has a statutory depletion carryforward of approximately $6,100,000, which does not expire.

F-12

A reconciliation of the provision for income taxes to income taxes computed using the federal statutory rate for years ended March 31 follows:

Schedule of Reconciliation of Provision for Income Taxes

|  | 2025 |  |  | 2024 |
Tax expense at federal statutory rate (1) |  | $ | 423,507 |  |  | $ | 412,754 |
Statutory depletion carryforward |  |  | (153,438 | ) |  |  | 152,054 |
Change in valuation allowance |  |  | - |  |  |  | (3,578 | )
Permanent differences |  |  | 22,206 |  |  |  | 46,819 |
State income expense, net of federal benefit |  |  | 50,048 |  |  |  | 94,507 |
Other |  |  | (37,993 | ) |  |  | (82,012 | )
Total income tax |  | $ | 304,330 |  |  | $ | 620,544 |
Effective income tax rate |  |  | 15.1 | % |  |  | 31.6 | %

| (1) | The federal statutory rate was 21% for fiscal years ending March 31, 2025 and 2024.

For the years ended March 31, 2025 and 2024, the Company did not have any uncertain tax positions.

While the amount of unrecognized tax benefits may change in the next 12 months, the Company does not expect any change to have a significant impact on its results of operations. The recognition of the total amount of the unrecognized tax benefits would have an impact on the effective tax rate. If these unrecognized tax benefits are disallowed, the Company will be required to pay additional taxes.

6. Major Customers

Currently, the Company operates exclusively within the United States and its revenues and operating profit are derived from the oil and gas industry. Oil and gas production is sold to various purchasers and the receivables are unsecured. 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. Management is of the opinion that the loss of any one purchaser would not have an adverse effect on the Company’s ability to sell its oil and gas production.

In fiscal 2025, Purchaser A accounted for 58% of the total operating revenues and 43% of the total oil and natural gas accounts receivable; Purchaser B accounted for 5% of the total operating revenues and 6% of the total oil and natural gas accounts receivable; and, Purchaser C accounted for 4% of the total operating revenues and 11% of the total oil and natural gas accounts receivable. In fiscal 2024, Purchaser A accounted for 59% of the total operating revenues and 48% of the total oil and natural gas accounts receivable and Purchaser B accounted for 8% of the total operating revenues and 8% of the total oil and natural gas accounts receivable.

7. Oil and Natural Gas Costs

The costs related to the Company’s oil and natural gas activities were incurred as follows for the years ended March 31:

Schedule of Cost Related to Oil and Gas Activities

|  | 2025 |  |  | 2024 |
Property acquisition costs: |  |  |  |  |  |  |  |
Proved |  | $ | 1,984,243 |  |  | $ | 1,826,266 |
Unproved |  |  | - |  |  |  | - |
Exploration |  |  | 31,934 |  |  |  | 153,039 |
Development |  |  | 1,417,163 |  |  |  | 1,363,529 |
Capitalized asset retirement obligations |  |  | 5,231 |  |  |  | 7,617 |
Total costs incurred for oil and gas properties |  | $ | 3,438,571 |  |  | $ | 3,350,451 |

F-13

The Company had the following aggregate capitalized costs relating to its oil and gas property activities at March 31:

Schedule of Aggregate Capitalized Costs Relating Oil and Gas Property Activities

|  | 2025 |  |  | 2024 |
Proved oil and gas properties |  | $ | 51,611,782 |  |  | $ | 48,304,585 |
Unproved oil and gas properties: |  |  |  |  |  |  |  |
subject to amortization |  |  | - |  |  |  | - |
not subject to amortization |  |  | - |  |  |  | - |
Oil and gas properties, gross |  | $ | 51,611,782 |  |  | $ | 48,304,585 |
Less accumulated DD&A |  |  | 36,517,279 |  |  |  | 34,066,282 |
Total oil and gas properties |  | $ | 15,094,503 |  |  | $ | 14,238,303 |

DD&A amounted to $13.74 and $12.81 per BOE of production for the years ended March 31, 2025 and 2024, respectively.

8. Income Per Common Share

The following is a reconciliation of the number of shares used in the calculation of basic income per share and diluted income per share for the years ended March 31:

Schedule of Reconciliation of Basic and Diluted Net Income (loss) Per Share

|  | 2025 |  |  | 2024 |
Net income |  | $ | 1,712,368 |  |  | $ | 1,344,952 |
Shares outstanding: |  |  |  |  |  |  |  |
Weighted avg. common shares outstanding – basic |  |  | 2,064,147 |  |  |  | 2,114,360 |
Effect of the assumed exercise of dilutive stock options |  |  | 43,628 |  |  |  | 46,650 |
Weighted avg. common shares outstanding – dilutive |  |  | 2,107,775 |  |  |  | 2,161,010 |
Income per common share: |  |  |  |  |  |  |  |
Basic |  | $ | 0.83 |  |  | $ | 0.64 |
Diluted |  | $ | 0.81 |  |  | $ | 0.62 |

For the year ended March 31, 2025, 60,500 shares relating to stock options were excluded from the computation of diluted net income because their inclusion would be anti-dilutive. Anti-dilutive stock options have a weighted average exercise price of $15.34 at March 31, 2025. For the year ended March 31, 2024, 93,000 shares relating to stock options were excluded from the computation of diluted net income because their inclusion would be anti-dilutive. Anti-dilutive stock options have a weighted average exercise price of $13.12 at March 31, 2024.

9. Stockholders’ Equity

In April 2024, the Company’s Board (the “Board”) authorized the use of up to $1,000,000 to repurchase shares of the Company’s common stock, par value, $0.50, for the treasury account. This program does not have an expiration date and may be modified, suspended or terminated at any time by the Board. Under the repurchase program, share of common stock may be purchased from time to time through open market purchases or other transactions. The amount and timing of repurchases will be subject to the availability of stock, prevailing market conditions, the trading price of stock, our financial performance and other conditions. Repurchases may also be made from time-to-time in connection with the settlement of our share-based compensation awards. Repurchases will be funded from cash flow.

On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA 2022”). The IRA 2022, among other tax provisions, establishes a 1% excise tax on stock repurchases made by publicly traded U.S. corporations, effective for stock repurchases in excess of an annual limit of $1,000,000 after December 31, 2022.

During the year ended March 31, 2025, the Company repurchased 57,766 shares for the treasury account at an aggregate cost of $703,216, an average price of $12.17 per share per share. During the year ended March 31, 2024, the Company repurchased 50,101 shares for the treasury account at an aggregate cost of $585,035, an average price of $11.68 per share.

F-14

10. Stock-based Compensation

In September 2019, the Company adopted the 2019 Employee Incentive Stock Plan (the “2019 Plan”). The 2019 Plan provides for the award of stock options up to 200,000 shares and includes option awards as well as stock awards. Option awards are granted with the restriction of requiring payment for the shares. Stock awards are granted without restrictions and without payment by the recipient. Neither option awards nor stock awards may exceed 25,000 shares granted to any one individual in any fiscal year. Stock options may be an incentive stock option or a nonqualified stock option. Options to purchase common stock under the plan are granted at the fair market value of the common stock at the date of grant, become exercisable to the extent of 25% of the shares optioned on each of four anniversaries of the date of grant, expire ten years from the date of grant and are subject to forfeiture if employment terminates. The 2019 Plan expires ten years from the date of adoption. According to the Company’s employee stock incentive plan, new shares will be issued upon the exercise of stock options and the Company can repurchase shares exercised under the plan.

During the year ended March 31, 2025, there were no stock options granted. During the year ended March 31, 2024, the Compensation Committee of the Board of Directors approved and the Company granted 32,000 stock options.

The plan also provides for the granting of stock awards. No stock awards were granted during fiscal 2025 and 2024.

The Company recognized compensation expense of $205,639 and $229,799 related to vesting stock options in general and administrative expense in the Consolidated Statements of Operations for fiscal 2025 and 2024, respectively. The total cost related to non-vested awards not yet recognized at March 31, 2025 totals $280,173, which is expected to be recognized over a weighted average of 1.54 years.

The fair value of each stock option is estimated on the date of grant using the Binomial valuation model. Expected volatilities are based on historical volatility of the Company’s stock over the contractual term of 120 months and other factors. The Company uses historical data to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options granted are expected to be outstanding. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. No dividend yield was used in the calculation on current options outstanding because at the time of the last issuance of stock options, either no dividend had been declared or the Company had only declared a special one-time dividend. Actual value realized, if any, is dependent on the future performance of the Company’s common stock and overall stock market conditions. There is no assurance the value realized by an optionee will be at or near the value estimated by the Binomial model.

Included in the following table is a summary of the grant-date fair value of stock options granted and the related assumptions used in the Binomial models for stock options granted in fiscal 2025 and 2024. All such amounts represent the weighted average amounts for each period.

Schedule of Grant-date Fair Value of Stock Options Granted and Assumptions Used Binominal Models

|  | For the year ended March 31, |
|  | 2025 |  |  | 2024 |
Grant-date fair value |  |  | - |  |  | $ | 8.73 |
Volatility factor |  |  | - |  |  |  | 56.5 | %
Dividend yield |  |  | - |  |  |  | - |
Risk-free interest rate |  |  | - |  |  |  | 3.44 | %
Expected term (in years) |  |  | - |  |  |  | 6.25 |

No forfeiture rate is assumed for stock options granted to directors or employees due to the forfeiture rate history for these types of awards. During the year ended March 31, 2025, 2,500 unvested stock options were forfeited due to the resignation of an employee. During the year ended March 31, 2024, there were no stock options forfeited or expired.

F-15

The following table is a summary of activity of stock options for the years ended March 31, 2025 and 2024:

Schedule of Activity of Stock Options

|  | Number of Shares |  |  | Weighted Average Exercise Price Per Share |  |  | Weighted Aggregate Average Remaining Contract Life in Years |  |  | Intrinsic Value |
Outstanding at April 1, 2023 |  |  | 139,250 |  |  | $ | 8.36 |  |  |  | 7.04 |  |  | $ | 419,853 |
Granted |  |  | 32,000 |  |  |  | 12.68 |  |  |  |  |  |  |  |  |
Exercised |  |  | (5,500 | ) |  |  | 3.58 |  |  |  |  |  |  |  |  |
Forfeited or Expired |  |  | - |  |  |  | - |  |  |  |  |  |  |  |  |
Outstanding at March 31, 2024 |  |  | 165,750 |  |  | $ | 9.36 |  |  |  | 6.62 |  |  | $ | 103,275 |
Granted |  |  | - |  |  |  | - |  |  |  |  |  |  |  |  |
Exercised |  |  | (12,367 | ) |  |  | 6.28 |  |  |  |  |  |  |  |  |
Forfeited or Expired |  |  | (2,500 | ) |  |  | 14.83 |  |  |  |  |  |  |  |  |
Outstanding at March 31, 2025 |  |  | 150,883 |  |  | $ | 9.52 |  |  |  | 5.98 |  |  | $ | - |
Vested at March 31, 2025 |  |  | 105,508 |  |  | $ | 7.69 |  |  |  | 5.31 |  |  | $ | 50,431 |
Exercisable at March 31, 2025 |  |  | 105,508 |  |  | $ | 7.69 |  |  |  | 5.31 |  |  | $ | 50,431 |

During the year ended March 31, 2025, stock options covering 12,367 shares were exercised with a total intrinsic value of $92,316. The Company received proceeds of $77,641 from these exercises. During the year ended March 31, 2025, stock options covering 5,500 shares were exercised with a total intrinsic value of $37,566. The Company received proceeds of $19,662 from these exercises.

Other information pertaining to option activity was as follows during the year ended March 31:

Schedule of Other Information Pertaining to Option Activity

|  | 2025 |  |  | 2024 |
Weighted average grant-date fair value of stock options granted (per share) |  | $ | - |  |  | $ | 8.73 |
Total fair value of options vested |  | $ | 205,241 |  |  | $ | 234,025 |
Total intrinsic value of options exercised |  | $ | 92,316 |  |  | $ | 37,566 |

The following table summarizes information about options outstanding at March 31, 2025:

Schedule of Information About Options Outstanding

Range of Exercise Prices |  |  | Number of Options |  |  | Weighted Average Exercise Price Per Share |  |  | Weighted Average Remaining Contract Life in Years |  |  | Aggregate Intrinsic Value |
$ | 3.34 – 4.83 |  |  |  | 25,677 |  |  | $ | 3.34 |  |  |  |  |  |  |  |  |
| 4.84 – 5.97 |  |  |  | 35,000 |  |  |  | 4.84 |  |  |  |  |  |  |  |  |
| 5.98 – 8.51 |  |  |  | 29,706 |  |  |  | 8.51 |  |  |  |  |  |  |  |  |
| 8.52 – 18.05 |  |  |  | 60,500 |  |  |  | 15.34 |  |  |  |  |  |  |  |  |
$ | 3.34 – 18.05 |  |  |  | 150,883 |  |  | $ | 9.52 |  |  |  | 5.98 |  |  | $ | - |

Outstanding options at March 31, 2025 expire between September 2028 and April 2033 and have exercise prices ranging from $3.34 to $18.05.

11. Related Party Transactions

Related party transactions for the Company primarily relate to shared office expenditures in addition to administrative and operating expenses paid on behalf of the principal stockholder. The total billed to and reimbursed by the stockholder for the years ended March 31, 2025 and 2024 were $31,506 and $23,379, respectively. The principal stockholder pays for his share of the lease amount for the shared office space directly to the lessor. Amounts paid by the principal stockholder directly to the lessor for the year ending March 31, 2025 and 2024 were $11,974 and $15,572, respectively.

F-16

12. Commitments and Contingencies

From time to time the Company is a party to litigation or other legal proceedings that the Company considers to be part of the ordinary course of business. The Company is currently not involved in any legal proceedings that it considers probable or reasonably possible, individually or in the aggregate, to result in a material adverse effect on its financial condition, results of operations or liquidity.

13. Leases

The Company leases approximately 4,160 rentable square feet of office space from an unaffiliated third party for the corporate office located in Midland, Texas. This includes 702 square feet of office space shared with and paid by our principal shareholder. In June 2024, the Company agreed to extend its current lease at a flat (unescalated) rate for 36 months. The amended lease now expires on July 31, 2027.

The Company determines an arrangement is a lease at inception. Operating leases are recorded in operating lease right-of-use asset, operating lease liability, current, and operating lease liability, long-term on the consolidated balance sheet.

Operating lease right-of-use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent its obligation to make lease payments arising from the lease. Operating lease assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. As the Company’s lease does not provide an implicit rate, the Company uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The incremental borrowing rate used at adoption was 9%. Significant judgement is required when determining the incremental borrowing rate. Rent expense for lease payments is recognized on a straight-line basis over the lease term.

The balance sheet classification of lease assets and liabilities was as follows:

Schedule of Operating Lease Assets and Liabilities

|  | March 31, 2025 |
Assets |  |  |  |
Operating lease right-of-use asset, beginning balance |  | $ | 19,263 |
Current period amortization |  |  | (50,811 | )
Lease extension |  |  | 158,073 |
Total operating lease right-of-use asset |  | $ | 126,525 |
Liabilities |  |  |  |
Operating lease liability, current |  | $ | 51,003 |
Operating lease liability, long term |  |  | 75,522 |
Total lease liabilities |  | $ | 126,525 |

Future minimum lease payments as of March 31, 2025 under non-cancellable operating leases are as follows:

Schedule of Future Minimum Lease Payments

|  | Lease Obligation |
Fiscal Year Ended March 31, 2026 |  | $ | 60,320 |
Fiscal Year Ended March 31, 2027 |  |  | 60,320 |
Fiscal Year Ended March 31, 2028 |  |  | 20,107 |
Total lease payments |  | $ | 140,747 |
Less: imputed interest |  |  | (14,222 | )
Operating lease liability |  |  | 126,525 |
Less: operating lease liability, current |  |  | (51,003 | )
Operating lease liability, long term |  | $ | 75,522 |

Net cash paid for our operating lease for the year ended March 31, 2025 and 2024 was $47,653 and $42,668, respectively. Rent expense, less sublease income of $11,974 is included in general and administrative expenses.

14. Acquisitions

During the year ended March 31, 2025, the Company incurred approximately $2,000,000 in acquisition costs to acquire various royalty interests in approximately 840 producing wells located in Adams, Broomfield, and Weld Counties, Colorado; DeSoto Parish, Louisiana; Eddy County, New Mexico; Karnes, Live Oak, Reagan, Reeves, and Upton Counties, Texas; Laramie County, Wyoming; and multiple counties in Nebraska, North and South Dakota, and Montana.

F-17

During the year ended March 31, 2024, the Company incurred approximately $1,800,000 in acquisition costs to acquire various royalty interests in approximately 340 producing wells in Crane, Ector, Howard, Midland, Reeves, and Upton Counties, Texas.

15. Oil and Gas Reserve Data (Unaudited)

The estimates of the Company’s proved oil and gas reserves, which are located entirely within the United States, were prepared in accordance with the generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The estimates as of March 31, 2025 and 2024 were based on evaluations prepared by Russell K. Hall and Associates, Inc. The services provided by Russell K. Hall and Associates, Inc. are not audits of our reserves but instead consist of complete engineering evaluations of the respective properties. For more information about their evaluations performed, refer to the copy of their report filed as an exhibit to this Annual Report on Form 10-K. Management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

The following table presents the weighted average first-day-of-the-month prices used for oil and gas reserve preparation, based upon SEC guidelines.

Schedule of Weighted Average First-day-of-the-month Prices Used for Oil and Gas Reserve

|  | March 31, |  |  |  |
|  | 2025 |  |  | 2024 |  |  | % Change |
Prices utilized in the reserve estimates before adjustments: |  |  |  |  |  |  |  |  |  |  |  |
Oil per Bbl |  | $ | 71.00 |  |  | $ | 73.96 |  |  |  | (4 | %)
Natural gas per MMBtu |  | $ | 2.44 |  |  | $ | 2.45 |  |  |  | - |

The Company’s total estimated proved reserves at March 31, 2025 were approximately 1.401 MBOE of which 48% was oil and 52% was natural gas.

Changes in Proved Reserves:

Schedule of Changes in Proved Reserve

|  | Oil (Bbls) |  |  | Natural Gas (Mcf) |
Proved Developed and Undeveloped Reserves: |  |  |  |  |  |  |  |
As of April 1, 2023 |  |  | 727,000 |  |  |  | 4,949,000 |
Revision of previous estimates |  |  | (86,000 | ) |  |  | (463,000 | )
Purchase of minerals in place |  |  | 24,000 |  |  |  | 121,000 |
Extensions and discoveries |  |  | 199,000 |  |  |  | 437,000 |
Sales of minerals in place |  |  | (3,000 | ) |  |  | (4,000 | )
Production |  |  | (70,000 | ) |  |  | (503,000 | )
As of March 31, 2024 |  |  | 791,000 |  |  |  | 4,537,000 |
Revision of previous estimates |  |  | (132,000 | ) |  |  | (71,000 | )
Purchase of minerals in place |  |  | 40,000 |  |  |  | 221,000 |
Extensions and discoveries |  |  | 60,000 |  |  |  | 243,000 |
Sales of minerals in place |  |  | - |  |  |  | - |
Production |  |  | (84,000 | ) |  |  | (570,000 | )
As of March 31, 2025 |  |  | 675,000 |  |  |  | 4,360,000 |

Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves (“PUD”) are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion within five years of the date of their initial recognition. Moreover, the Company may be required to write down its proved undeveloped reserves if the operators do not drill on the reserves within the required five-year timeframe. 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.

F-18

Summary of Proved Developed and Undeveloped Reserves as of March 31, 2025 and 2024:

Summary of Proved Developed and Undeveloped Reserves

|  | Oil (Bbls) |  |  | Natural Gas (Mcf) |
Proved Developed Reserves: |  |  |  |  |  |  |  |
As of April 1, 2023 |  |  | 486,770 |  |  |  | 3,971,370 |
As of March 31, 2024 |  |  | 444,610 |  |  |  | 3,566,240 |
As of March 31, 2025 |  |  | 405,840 |  |  |  | 3,654,900 |
Proved Undeveloped Reserves: |  |  |  |  |  |  |  |
As of April 1, 2023 |  |  | 240,060 |  |  |  | 978,010 |
As of March 31, 2024 |  |  | 346,330 |  |  |  | 970,880 |
As of March 31, 2025 |  |  | 269,000 |  |  |  | 704,810 |

At March 31, 2025, the Company reported estimated PUDs of 386 MBOE, which accounted for 28% of its total estimated proved oil and gas reserves. This figure primarily consists of a projected 72 new wells (296 MBOE) operated by others, 37 wells are planned to be drilled in fiscal 2026, 12 wells in fiscal 2027 and 23 wells in fiscal 2028. The cost of these projects would be funded, to the extent possible, from existing cash balances, cash flow from operations and bank borrowings. The remainder may be funded through non-core asset sales and/or sales of our common stock.

The following table discloses the Company’s progress toward the conversion of PUDs during fiscal 2025.

Progress of Converting Proved Undeveloped Reserves:

Schedule of Progress of Converting Proved Undeveloped Reserves

|  | Oil & Natural Gas (BOE) |  |  | Future Development Costs |
PUDs, beginning of year |  |  | 508,141 |  |  | $ | 5,481,477 |
Revision of previous estimates |  |  | (95,438 | ) |  |  | (1,621,802 | )
Sales of reserves |  |  | - |  |  |  | - |
Conversions to PD reserves |  |  | (84,006 | ) |  |  | (645,145 | )
Additional PUDs added |  |  | 57,765 |  |  |  | 797,445 |
PUDs, end of year |  |  | 386,462 |  |  | $ | 4,011,975 |

Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2025 and 2024 along with estimates of the operating costs, production taxes and future development costs necessary to produce such reserves. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.

Operating costs and production taxes are estimated based on current costs with respect to producing oil and natural gas properties. Future development costs including abandonment costs are based on the best estimate of such costs assuming current economic and operating conditions. The future cash flows estimated to be spent to develop the Company’s share of proved undeveloped properties through March 31, 2028 are $4,011,975.

Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable carryforwards.

The future net revenue information assumes no escalation of costs or prices, except for oil and natural gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.

F-19

The current reporting rules require that year end reserve calculations and future cash inflows be based on the 12-month average market prices for sales of oil and gas on the first calendar day of each month during the fiscal year discounted at 10% per year and assuming continuation of existing economic conditions. The average prices used for fiscal 2025 were $73.79 per bbl of oil and $2.14 per mcf of natural gas. The average prices used for fiscal 2024 were $76.88 per bbl of oil and $2.75 per mcf of natural gas.

The standardized measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first day of the month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and natural gas reserves, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rate to the difference.

The basis for this table is the reserve studies prepared by an independent petroleum engineering consultant, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of proved oil and gas properties.

The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of March 31, 2025 and 2024 in accordance with ASC 932, “Extractive Activities – Oil and Gas” which requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:

Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

|  | March 31 |
|  | 2025 |  |  | 2024 |
Future cash inflows |  | $ | 59,135,000 |  |  | $ | 73,290,000 |
Future production costs and taxes |  |  | (18,172,000 | ) |  |  | (21,634,000 | )
Future development costs |  |  | (4,137,000 | ) |  |  | (5,481,000 | )
Future income taxes |  |  | (4,982,000 | ) |  |  | (7,067,000 | )
Future net cash flows |  |  | 31,844,000 |  |  |  | 39,108,000 |
Annual 10% discount for estimated timing of cash flows |  |  | (11,769,000 | ) |  |  | (14,480,000 | )
Standardized measure of discounted future net cash flows |  | $ | 20,075,000 |  |  | $ | 24,628,000 |

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:

Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows to Proved Oil and Gas Reserves

|  | March 31 |
|  | 2025 |  |  | 2024 |
Sales of oil and gas produced, net of production costs |  | $ | (5,511,000 | ) |  | $ | (4,936,000 | )
Net changes in price and production costs |  |  | (2,735,000 | ) |  |  | (14,394,000 | )
Changes in previously estimated development costs |  |  | (1,111,000 | ) |  |  | (77,000 | )
Revisions of quantity estimates |  |  | (5,155,000 | ) |  |  | (3,620,000 | )
Net change due to purchases and sales of minerals in place |  |  | 1,996,000 |  |  |  | 1,146,000 |
Extensions and discoveries, less related costs |  |  | 1,713,000 |  |  |  | 7,208,000 |
Net change in income taxes |  |  | 1,309,000 |  |  |  | 2,208,000 |
Accretion of discount |  |  | 2,321,000 |  |  |  | 2,908,000 |
Changes in timing of estimated cash flows and other |  |  | 2,620,000 |  |  |  | 1,370,000 |
Changes in standardized measure |  |  | (4,553,000 | ) |  |  | (8,187,000 | )
Standardized measure, beginning of year |  |  | 24,628,000 |  |  |  | 32,815,000 |
Standardized measure, end of year |  | $ | 20,075,000 |  |  | $ | 24,628,000 |

16. Subsequent Events

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 regular annual dividend in the amount of $204,600 was paid on June 16, 2025.

In June 2025, the Company expended approximately $116,000 to participate in the drilling of 5 horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Eddy County, New Mexico.

The Company completed a review and analysis of all events that occurred after the consolidated balance sheet date to determine if any such events must be reported and has determined that there are no other subsequent events to be disclosed.

F-20

INDEX TO EXHIBITS

Exhibit Number |
3.1 | Restated Articles of Incorporation of Mexco Energy Corporation filed as Exhibit 3.1 to the Company’s Annual Report on Form 10-K dated June 24, 1998, and incorporated herein by reference.
3.2 | Amended Bylaws of Mexco Energy Corporation as amended on September 13, 2011 filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K dated September 14, 2011, and incorporated herein by reference.
10.1 | 2009 Employee Incentive Stock Plan of Mexco Energy Corporation filed as Exhibit A to the Company’s Proxy Statement on Form 14C dated July 15, 2009, and incorporated herein by reference.
10.2 | 2019 Employee Incentive Stock Plan of Mexco Energy Corporation filed as Exhibit A to the Company’s Proxy Statement on Form 14C dated July 16, 2019, and incorporated herein by reference.
10.3 | Loan Agreement dated December 28, 2018 between West Texas National Bank and Mexco Energy Corporation filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K dated December 31, 2018, and incorporated herein by reference.
10.4 | First Amendment to Loan Agreement dated February 28, 2020 to the Loan Agreement between West Texas National Bank and Mexco Energy Corporation filed as Exhibit 10.4 to the Company’s Annual Report on form 10-K filed on June 26, 2020, and incorporated herein by reference.
10.5 | Second Amendment to Loan Agreement dated March 28, 2023 to the Loan Agreement between West Texas National Bank and Mexco Energy Corporation filed as Exhibit 10.5 to the Company’s Annual Report on Form 10-K dated June 26, 2023, and incorporated herein by reference.
14.1 | Code of Business Conduct and Ethics of Mexco Energy Corporation filed with the Company’s Quarterly Report on Form 10-Q filed on November 15, 2004, and incorporated herein by reference.
21.1 | Subsidiaries of Mexco Energy Corporation
23.1 | Consent of Weaver and Tidwell, L.L.P., Independent Registered Public Accounting Firm
23.2 | Consent of Russell K. Hall & Associates, Inc., Independent Petroleum Engineers
31.1 | Certification of the Chief Executive Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 | Certification of the Chief Financial Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 | Certification of the Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1 | Report of Russell K. Hall & Associates, Inc., Independent Petroleum Engineering Firm
101.INS | Inline XBRL Instance Document
101.SCH | Inline XBRL Taxonomy Extension Schema Document
101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB | Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document
104 | Cover Page Innteractive Data File (embedded within the Inline XBRL and contained in Exhibit 101)

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