false FY 0000066418 No 0000066418 2025-04-01 2026-03-31 0000066418 2025-09-30 0000066418 2026-06-29 0000066418 2026-03-31 0000066418 2025-03-31 0000066418 2024-04-01 2025-03-31 0000066418 MXC:OilSalesMember 2025-04-01 2026-03-31 0000066418 MXC:OilSalesMember 2024-04-01 2025-03-31 0000066418 MXC:NaturalGasSalesMember 2025-04-01 2026-03-31 0000066418 MXC:NaturalGasSalesMember 2024-04-01 2025-03-31 0000066418 MXC:OtherMember 2025-04-01 2026-03-31 0000066418 MXC:OtherMember 2024-04-01 2025-03-31 0000066418 us-gaap:CommonStockMember 2024-03-31 0000066418 us-gaap:AdditionalPaidInCapitalMember 2024-03-31 0000066418 us-gaap:RetainedEarningsMember 2024-03-31 0000066418 us-gaap:TreasuryStockCommonMember 2024-03-31 0000066418 2024-03-31 0000066418 us-gaap:CommonStockMember 2025-03-31 0000066418 us-gaap:AdditionalPaidInCapitalMember 2025-03-31 0000066418 us-gaap:RetainedEarningsMember 2025-03-31 0000066418 us-gaap:TreasuryStockCommonMember 2025-03-31 0000066418 us-gaap:CommonStockMember 2024-04-01 2025-03-31 0000066418 us-gaap:AdditionalPaidInCapitalMember 2024-04-01 2025-03-31 0000066418 us-gaap:RetainedEarningsMember 2024-04-01 2025-03-31 0000066418 us-gaap:TreasuryStockCommonMember 2024-04-01 2025-03-31 0000066418 us-gaap:CommonStockMember 2025-04-01 2026-03-31 0000066418 us-gaap:AdditionalPaidInCapitalMember 2025-04-01 2026-03-31 0000066418 us-gaap:RetainedEarningsMember 2025-04-01 2026-03-31 0000066418 us-gaap:TreasuryStockCommonMember 2025-04-01 2026-03-31 0000066418 us-gaap:CommonStockMember 2026-03-31 0000066418 us-gaap:AdditionalPaidInCapitalMember 2026-03-31 0000066418 us-gaap:RetainedEarningsMember 2026-03-31 0000066418 us-gaap:TreasuryStockCommonMember 2026-03-31 0000066418 2024-04-01 0000066418 MXC:OfficeFurnitureandEquipmentMember srt:MinimumMember 2026-03-31 0000066418 MXC:OfficeFurnitureandEquipmentMember srt:MaximumMember 2026-03-31 0000066418 MXC:LoanAgreementMember MXC:WestTexasNationalBankMember 2018-12-28 0000066418 MXC:LoanAgreementMember MXC:WestTexasNationalBankMember 2018-12-28 2018-12-28 0000066418 MXC:LoanAgreementMember MXC:WestTexasNationalBankMember 2020-02-28 0000066418 MXC:LoanAgreementMember MXC:WestTexasNationalBankMember 2020-02-28 2020-02-28 0000066418 MXC:LoanAgreementMember 2023-03-28 2023-03-28 0000066418 MXC:LoanAgreementMember MXC:WestTexasNationalBankMember 2025-09-17 0000066418 MXC:LoanAgreementMember MXC:WestTexasNationalBankMember 2026-03-28 2026-03-28 0000066418 MXC:LoanAgreementMember MXC:WestTexasNationalBankMember 2026-03-31 0000066418 MXC:LoanAgreementMember MXC:WestTexasNationalBankMember 2023-03-28 2023-03-28 0000066418 MXC:LoanAgreementMember MXC:WestTexasNationalBankMember 2025-04-01 2026-03-31 0000066418 MXC:LoanAgreementMember MXC:WestTexasNationalBankMember 2025-03-31 0000066418 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember MXC:BTAOilProducersLLCMember 2025-04-01 2026-03-31 0000066418 us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember MXC:BTAOilProducersLLCMember 2025-04-01 2026-03-31 0000066418 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember MXC:ApexNaturalGasLLCMember 2025-04-01 2026-03-31 0000066418 us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember MXC:ApexNaturalGasLLCMember 2025-04-01 2026-03-31 0000066418 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember MXC:ExxonMobilCorpMember 2025-04-01 2026-03-31 0000066418 us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember MXC:ExxonMobilCorpMember 2025-04-01 2026-03-31 0000066418 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember MXC:PurchaserAMember 2024-04-01 2025-03-31 0000066418 us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember MXC:PurchaserAMember 2024-04-01 2025-03-31 0000066418 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember MXC:PurchaserBMember 2024-04-01 2025-03-31 0000066418 us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember MXC:PurchaserBMember 2024-04-01 2025-03-31 0000066418 us-gaap:CustomerConcentrationRiskMember us-gaap:SalesRevenueNetMember MXC:PurchaserCMember 2024-04-01 2025-03-31 0000066418 us-gaap:CustomerConcentrationRiskMember us-gaap:AccountsReceivableMember MXC:PurchaserCMember 2024-04-01 2025-03-31 0000066418 srt:MaximumMember MXC:BoardOfDirectorsMember 2024-04-30 0000066418 MXC:BoardOfDirectorsMember us-gaap:CommonStockMember 2024-04-30 0000066418 us-gaap:SubsequentEventMember 2026-06-01 2026-06-30 0000066418 MXC:BoardOfDirectorsMember us-gaap:CommonStockMember us-gaap:SubsequentEventMember 2026-06-30 0000066418 2024-04-01 2024-12-31 0000066418 MXC:TwoThousandAndNineTeenEmployeeIncentiveStockPlanMember 2019-09-30 0000066418 MXC:TwoThousandAndNineTeenEmployeeIncentiveStockPlanMember 2019-09-01 2019-09-30 0000066418 us-gaap:InvestmentAdvisoryManagementAndAdministrativeServiceMember 2025-04-01 2026-03-31 0000066418 us-gaap:InvestmentAdvisoryManagementAndAdministrativeServiceMember 2024-04-01 2025-03-31 0000066418 us-gaap:EmployeeStockOptionMember 2024-03-31 0000066418 us-gaap:EmployeeStockOptionMember 2023-04-01 2024-03-31 0000066418 us-gaap:EmployeeStockOptionMember 2023-03-31 0000066418 us-gaap:EmployeeStockOptionMember 2024-04-01 2025-03-31 0000066418 us-gaap:EmployeeStockOptionMember 2025-03-31 0000066418 us-gaap:EmployeeStockOptionMember 2025-04-01 2026-03-31 0000066418 us-gaap:EmployeeStockOptionMember 2026-03-31 0000066418 MXC:RangeOneMember 2025-04-01 2026-03-31 0000066418 MXC:RangeOneMember 2026-03-31 0000066418 MXC:RangeTwoMember 2025-04-01 2026-03-31 0000066418 MXC:RangeTwoMember 2026-03-31 0000066418 MXC:RangeThreeMember 2025-04-01 2026-03-31 0000066418 MXC:RangeThreeMember 2026-03-31 0000066418 MXC:RangeFourMember 2025-04-01 2026-03-31 0000066418 MXC:RangeFourMember 2026-03-31 0000066418 us-gaap:RelatedPartyMember 2025-04-01 2026-03-31 0000066418 us-gaap:RelatedPartyMember 2024-04-01 2025-03-31 0000066418 us-gaap:PrincipalOwnerMember 2025-04-01 2026-03-31 0000066418 us-gaap:PrincipalOwnerMember 2024-04-01 2025-03-31 0000066418 MXC:ShareholderMember 2026-03-31 0000066418 2024-06-01 2024-06-30 0000066418 srt:OilReservesMember 2025-04-01 2026-03-31 0000066418 srt:OilReservesMember 2024-04-01 2025-03-31 0000066418 srt:NaturalGasReservesMember 2025-04-01 2026-03-31 0000066418 srt:NaturalGasReservesMember 2024-04-01 2025-03-31 0000066418 MXC:HundredAndFourtyTwoNewWellsMember 2024-04-01 2025-03-31 0000066418 MXC:TwoThousandsAndTwentySevenMember 2025-04-01 2026-03-31 0000066418 MXC:TwoThousandsAndTwentyNineMember 2025-04-01 2026-03-31 0000066418 MXC:TwoThousandsAndThirtyMember 2025-04-01 2026-03-31 0000066418 srt:ScenarioForecastMember 2030-03-31 0000066418 srt:OilReservesMember 2024-03-31 0000066418 srt:NaturalGasReservesMember 2024-03-31 0000066418 srt:OilReservesMember 2025-03-31 0000066418 srt:NaturalGasReservesMember 2025-03-31 0000066418 srt:OilReservesMember 2026-03-31 0000066418 srt:NaturalGasReservesMember 2026-03-31 0000066418 us-gaap:SubsequentEventMember 2026-04-01 2026-04-30 0000066418 MXC:WolfcampMember stpr:NM us-gaap:SubsequentEventMember 2026-05-01 2026-05-30 0000066418 us-gaap:SubsequentEventMember 2026-06-04 0000066418 us-gaap:SubsequentEventMember 2026-06-04 2026-06-04 iso4217:USD xbrli:shares iso4217:USD xbrli:shares xbrli:pure utr:sqft utr:acre MXC:Wells MXC:Integer utr:Boe utr:Mcf utr:bbl iso4217:USD utr:MMBTU iso4217:USD utr:bbl

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, 2026

☐	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
Midland, Texas 79701		(432) 682-1119
(Address of principal executive offices, Zip Code)		(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) 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 an 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, 2025 (the last business day of the Registrant’s most recently completed second quarter) was $9,540,503 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 29, 2026.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s Proxy Statement relating to the 2026 Annual Meeting of Shareholders to be held on September 8, 2026, 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, 2026, 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	15
Item 2.	Properties	16
Item 3.	Legal Proceedings	19
Item 4.	Mine Safety Disclosures	19

PART II

Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	20
Item 6.	Reserved	21
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	29
Item 8.	Financial Statements and Supplementary Data	30
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	30
Item 9A.	Controls and Procedures	30
Item 9B.	Other Information	31
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspection	31

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	31
Item 11.	Executive Compensation	31
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	31
Item 13.	Certain Relationships and Related Transactions, and Director Independence	31
Item 14.	Principal Accounting Fees and Services	31

PART IV

Item 15.	Exhibits and Financial Statement Schedules	31
Item 16.	Form 10-K Summary	31

Signatures		32

Glossary of Abbreviations and Terms		33

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 as Miller Oil Company, the Company changed its name to Mexco Energy Corporation effective April 30, 1980. At that time, the Company’s shareholders also approved amendments to the Articles of Incorporation, resulting in a one-for-fifty reverse stock split of the Company’s common stock.

Our total estimated proved reserves at March 31, 2026 were approximately 1.437 million barrels of oil equivalent (“MMBOE”) of which 46% was oil and 54% was natural gas, and our estimated present value of proved reserves was approximately $21 million based on estimated future net revenues excluding taxes discounted at 10% per annum, pricing and other assumptions set forth in “Item 2 – Properties” below.

Nicholas C. Taylor beneficially owns approximately 46% of the outstanding shares of our common stock. Mr. Taylor is also our Chairman of the Board and Chief Executive Officer. As a result, Mr. Taylor has significant influence in matters voted on by our shareholders, including the election of our Board members. Mr. Taylor participates in all facets of our business and has a significant impact on both our business strategy and daily operations.

Company Profile

Since our inception, we have been engaged in acquiring and developing oil and gas properties and the exploration for and production of crude oil, natural gas, condensate and natural gas liquids (“NGLs”) within the United States. We especially seek to acquire proved reserves that fit well with existing operations or in areas where Mexco has established production. Acquisitions will preferably contain most of their value in producing wells, behind-pipe reserves, and high-quality proved undeveloped locations. Competition for the purchase of proved reserves is intense. Sellers often utilize a bidding process to sell properties. This process intensifies the competition and makes it difficult to acquire reserves without assuming significant price and production risks. We actively seek opportunities to acquire proved oil and gas properties. However, given the intense competition, we cannot give any assurance that we will be successful in our efforts during fiscal 2027.

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

From 1983 to 2026, Mexco Energy Corporation made numerous acquisitions of royalties, overriding royalties, minerals, and working interests in producing oil and gas properties, including the following most significant acquisitions:

1990-1994

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

1993-2014

Tabbs Bay Oil Company and Thompson Brothers Lumber Company, which were dissolved in 1957 and 1947, respectively. Purchase covering thousands of acres located in 27 counties in Texas, 3 parishes in Louisiana, and one county in Arkansas, consisting of various mineral, royalty, and overriding royalty interests.

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

2004-2005

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

2007-2008

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

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

2010-2012

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

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

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

TBO Oil and Gas, LLC, purchase price of $1,150,000, consisting of working interests in approximately 280 wells located in 16 counties of 3 states.

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

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

2019

Royalty interest investment of $300,000 for a less than 1% investment commitment in a limited liability company (“LLC”), capitalized at approximately $50 million to purchase royalty interests consisting of minerals located in the Marcellus and Utica areas of Ohio. This LLC has returned 115% of the total investment since inception in fiscal 2020.

2022-2023

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

Royalty interest investment of $2,000,000 for an approximate 2% investment commitment in a limited liability company, capitalized at approximately $100 million to purchase royalty interests consisting of minerals located in the Marcellus and Utica areas of Ohio. During 2025, an additional $227,429 was expended to participate in a voluntary optional cash call and acquire its proportionate share of the resulting non-consenting interests, increasing its capitalized investment. As of the date of this report, this investment is fully funded, and 25% of the investment has been returned.

2023-2024

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

2024-2025

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

2025-2026

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

Industry Environment and Outlook

Commodity prices remained volatile during fiscal 2026 due to shifting global supply-and-demand fundamentals, OPEC+ production decisions, geopolitical tensions, inflationary pressures, interest rate uncertainty, and concerns regarding the pace of global economic growth. In addition, fluctuations in oil and natural gas prices, evolving trade policies, and continued uncertainty in the broader economic environment may continue to impact our industry and operating results. In light of these challenges and the ongoing volatility in commodity markets, our primary business strategies for fiscal 2027 will continue to include: (1) optimizing cash flows through operating efficiencies and cost reductions, (2) divesting non-core assets, and (3) working to balance capital spending with cash flows to minimize borrowings and maintain ample liquidity.

See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for discussion of our fiscal 2026 operating results and potential impact on fiscal 2027 operating results due to commodity price changes.

Oil and Gas Operations

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

The Company is primarily focused on two areas: 1) the Delaware Basin located in the Western portion of the Permian Basin, including Lea and Eddy Counties, New Mexico and Reeves and Loving Counties, Texas, and 2) the Midland Basin located in the Eastern portion of the Permian Basin, including Reagan, Upton, Midland, Martin, Howard, and Glasscock Counties, Texas. The Permian Basin in total accounts for 75% of our discounted future net cash flows from proved reserves and 76% of our operating revenues.

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

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

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

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

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

We own partial interests in approximately 8,100 producing wells all of which are located within the United States in the states of Texas, New Mexico, Oklahoma, Louisiana, Alabama, Arkansas, Wyoming, Kansas, Colorado, Montana, Virginia, North Dakota, South Dakota and Ohio. Additional information concerning these properties and our oil and gas reserves is provided below.

The following table indicates our oil and gas production in each of the last five years:

Year	Oil(Bbls)		Gas (Mcf)
2026		82,133		681,794
2025		83,564		570,012
2024		69,999		502,879
2023		73,968		534,363
2022		61,689		393,841

Competition

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

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

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

Markets and Major Customers

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

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

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

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

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

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

Environmental Regulation

The oil and gas industry is subject to extensive regulation at the federal, state, and local levels. Environmental and energy-related regulations are subject to ongoing review and may be revised or made more stringent over time. Various federal and state agencies, including the Texas Railroad Commission, the Bureau of Land Management (the “BLM”), an agency of the U.S. Department of the Interior (the “DOI”), the Federal Energy Regulatory Commission (“FERC”), the U.S. Environmental Protection Agency (the “EPA”), the Department of Transportation (“DOT”), and the U.S. Occupational Safety and Health Administration (“OSHA”), as well as state environmental and natural resources agencies, have regulatory authority over aspects of the operations conducted on properties in which the Company owns an interest.

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

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

We did not incur any material capital expenditures for remediation or pollution control activities for the year ended March 31, 2026. Additionally, as of the date of this report, we are not aware of any environmental issues or claims that will require material capital expenditures during fiscal 2027.

Other Regulation

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

Title to Properties

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

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

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

Insurance

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

Executive Officers

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

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

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

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

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

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

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

Employees

As of March 31, 2026, we had two full-time and two part-time employees. We believe that relations with these employees are generally satisfactory. From time to time, we utilize the services of independent geological, land, and engineering consultants on a limited basis and expect to continue to do so.

Office Facilities

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

Access to Company Reports

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

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

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 that are not currently known to us or that we deem immaterial. If any of these risks actually occur, it could materially harm our business, financial condition, or results of operations, and the trading price of our shares could decline. Investors should carefully consider each of the following risk factors and all of the other information set forth in this Annual Report on Form 10-K.

RISKS RELATED TO OUR BUSINESS AND INDUSTRY

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

Prices for oil and natural gas fluctuate widely and are influenced by numerous factors beyond our control, including global supply and demand, actions of OPEC and other producing nations, government regulation and taxation (including environmental regulation), levels of exploration and production activity, transportation and storage capacity constraints, availability of alternative fuels, technological developments affecting energy consumption, speculative trading in commodity derivatives, weather conditions, geopolitical developments, pandemics, and overall global economic conditions.

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

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

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

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

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

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

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

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

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

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

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

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

Under full cost accounting rules, the net capitalized cost of oil and natural gas properties is subject to a “ceiling limitation” based on the present value of estimated future net cash flows from proved reserves, discounted at 10%, plus the lower of cost or fair market value of unproved properties. The ceiling calculation uses the unweighted arithmetic average first-day-of-the-month prices for oil and natural gas over the preceding 12-month period and is performed quarterly. If capitalized costs exceed the ceiling, the excess must be charged to earnings as a noncash “ceiling test write-down.” While such write-downs do not affect cash flows from operations, they reduce net income and stockholders’ equity.

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

We must replace reserves we produce.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

We participate in the drilling and completion of wells operated by third parties that exercise exclusive control over such operations pursuant to joint operating agreements and other contractual arrangements. Accordingly, we rely on third-party operators to conduct operations and may not be able to maximize the value of these properties in the manner we believe appropriate, or at all.

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

A third-party operator’s failure to perform adequately, breach of applicable agreements, or actions adverse to our interests could reduce production and revenues, adversely affect liquidity, increase capital requirements beyond current plans, and have a material adverse effect on our business, financial condition, and results of operations.

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

Competition for oil and gas reserve acquisitions is significant. We may compete with major oil and gas companies, other independent oil and gas companies, and individual producers and operators, some of which have substantially greater financial and personnel resources than we do. As a result, we may be at a competitive disadvantage in acquiring reserves and development opportunities. Our ability to acquire and develop additional properties will depend on our ability to identify, evaluate, and acquire suitable producing properties and development prospects.

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

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

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

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

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

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

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

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

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

The loss of our Chief Executive Officer or President could adversely impact our ability to execute our business strategy.

We depend, and will continue to depend in the foreseeable future, upon the continued services of our Chief Executive Officer, Nicholas C. Taylor, and our President and Chief Financial Officer, Tamala L. McComic, who have extensive experience and expertise in evaluating and analyzing producing oil and gas properties and drilling prospects, maximizing production from oil and gas properties, and developing and executing acquisitions and financing. As of March 31, 2026, we do not have key-man insurance for the lives of Mr. Taylor and Ms. McComic. The unexpected loss of the services of one or more of these individuals could significantly and adversely affect our operations.

We may be affected by one substantial shareholder.

Nicholas C. Taylor beneficially owns approximately 46% of our common stock and serves as our Chairman of the Board and Chief Executive Officer, giving him significant influence in matters voted on by our shareholders, including the election of our Board members. Mr. Taylor participates in all facets of our business and has a significant impact on both our business strategy and daily operations. The retirement, incapacity, or death of Mr. Taylor, or any change in the power to vote shares beneficially owned by Mr. Taylor, could result in negative market perception and adversely affect our business.

RISKS RELATED TO OUR COMMON STOCK

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

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

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

As of March 31, 2026, our executive officers and directors beneficially owned approximately 49% of our common stock. These stockholders, if acting together, would be able to significantly influence all matters requiring approval by our stockholders, including the election of our board of directors and the approval of mergers or other business combination transactions.

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

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

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

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 1C.

CYBERSECURITY

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

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

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

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

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

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

ITEM 2.

PROPERTIES

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

Oil and Natural Gas Reserves

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

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

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

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

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

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

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

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

PROVED RESERVES

	March 31,
	2026			2025
Oil (Bbls):
Proved developed – Producing		387,670			390,940
Proved developed – Non-producing		75,105			14,900
Proved undeveloped		195,840			269,000
Total		658,615			674,840
Natural gas (Mcf):
Proved developed – Producing		3,902,120			3,554,920
Proved developed – Non-producing		302,490			99,970
Proved undeveloped		466,060			704,810
Total		4,670,670			4,359,700

Total net proved reserves (BOE) ⁽¹⁾		1,437,060			1,401,460

PV-10 Value ⁽²⁾	$	21,131,000		$	23,216,000
Present value of future income tax discounted at 10%		(2,466,000	)		(3,141,000	)
Standardized measure of discounted future net cash flows ⁽³⁾	$	18,665,000		$	20,075,000

Prices used in calculating reserves: ⁽⁴⁾
Natural gas (per Mcf)	$	2.24		$	2.14
Oil (per Bbl)	$	62.76		$	73.79

⁽¹⁾

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

⁽²⁾

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

⁽³⁾

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

⁽⁴⁾

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

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

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

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

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

We have not filed any other oil or gas reserve estimates or included any such estimates in reports to other federal or foreign governmental authorities or agencies during the year ended March 31, 2026, and no major discovery is believed to have caused a significant change in our estimates of proved reserves since that date.

Drilling Activities

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

	Year Ended March 31,
	2026						2025
	Gross			Net			Gross			Net
Exploratory Wells
Beginning wells in progress		-			-			-			-
Wells spud		1			.02			1			.10
Successful wells		0			-			0			-
Ending wells in progress		-			-			-			-

Development Wells
Beginning wells in progress		17			.03			16			.17
Wells spud		58			.19			38			.09
Successful wells		(55	)		(.08	)		(37	)		(.23	)
Ending wells in progress		20			.14			17			.03

The information contained in the foregoing table should not be considered indicative of future drilling performance, nor should it be assumed that there is any necessary correlation between the number of productive wells drilled and the amount of oil and gas that may ultimately be recovered by us.

In addition to the working interests mentioned above, other operators drilled 177 gross wells (.07 net wells) on Company-owned minerals and royalties at no expense to the Company. We expect production from our mineral interests to increase as operators continue to drill, complete, and develop our acreage. We expect to capitalize on this development, which requires no capital expenditure funding from us, and believe the anticipated aggregate royalty receipts will enable us to grow our cash flows. A number of the horizontal wells in which the Company participates involve longer laterals that are more efficient and have greater estimated ultimate recovery.

Productive Wells and Acreage

Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections. Wells that are completed in more than one producing zone are counted as one well. As of March 31, 2026, we held an interest in approximately 8,100 gross (26.1 net) productive wells, including approximately 7,000 wells in which we held an overriding or royalty interest and 1,100 wells in which we held a working interest.

A gross acre is an acre in which an interest is owned. A net acre is deemed to exist when the sum of fractional ownership interests in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres. The following table sets forth the approximate developed acreage in which we held a leasehold mineral or other interest as of March 31, 2026:

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

Net Production, Unit Prices and Costs

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

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

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

ITEM 3.

LEGAL PROCEEDINGS

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

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5.

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

Market Information

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

		High		Low
2026:	April - June 2025	$	16.00	$	5.89
	July - September 2025		9.45		7.80
	October - December 2025		10.80		8.36
	January - March 2026		16.48		8.65

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

On March 31, 2026, the closing sales price of our common stock on the NYSE American was $10.22 per share.

Stockholders

As of March 31, 2026, we had 2,239,283 shares issued and 808 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, 2026, 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 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 West Texas National Bank (“WTNB”) prior to declaring the regular annual dividend. On April 30, 2024, 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 21, 2024. The special dividend was paid on June 4, 2024. The Company obtained written permission from WTNB prior to declaring the special dividend.

Subsequently, on June 4, 2026, 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 15, 2026. The dividend is to be paid on June 30, 2026. 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’s 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.

Securities Authorized for Issuance Under Compensation Plans

The following table includes certain information about our Employee Incentive Stock Plan as of March 31, 2026, 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		68,500
Total		400,000		150,883	$	9.52		68,500

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, par value $0.50, for the treasury account. This program has no expiration date and may be modified, suspended, or terminated at any time by the Board. Under the repurchase program, 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 shares, prevailing market conditions, the trading price of our common 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. As of March 31, 2026, the Company’s repurchase program approved in April 2024 had $296,784 in remaining funds.

During the year ended March 31, 2026, there were no shares of common stock repurchased for the treasury account. 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.

Subsequently, in June 2026, the Board authorized the use of an additional $250,000 to repurchase shares of the Company’s common stock, par value $0.50, for the treasury account.

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

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

Cash Flows

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

	For the Years Ended March 31,
	2026			2025			Change
Net cash provided by operating activities	$	3,779,152		$	4,269,621		$	(490,469	)
Net cash used in investing activities	$	(2,540,161	)	$	(4,154,575	)	$	1,614,414
Net cash used in financing activities	$	(216,970	)	$	(834,575	)	$	617,605

Cash Flow Provided by Operating Activities. Cash flow from operating activities is primarily derived from the production of our crude oil and natural gas reserves and changes in the balances of non-cash accounts, receivables, payables or other non-energy property asset account balances. Cash flow provided by our operating activities for the year ended March 31, 2026 was $3,779,152 in comparison to $4,269,621 for the year ended March 31, 2025. This decrease of $490,469 in our cash flow from operating activities consisted of an increase in our non-cash expenses of $245,850; a decrease in income tax payable of $179,147; an increase in our accounts receivable of $47,152; a decrease of $102,146 of our accounts payable and accrued expenses, and a decrease in our net income for the current year of $406,646. Variations in cash flow from operating activities may affect our level of exploration and development expenditures.

Our expenditures in operating activities consist primarily of drilling expenses, production expenses, and engineering services. Our expenses also include employee compensation, accounting, insurance, and other general and administrative expenses incurred to support the normal and necessary business activities of a public company in the crude oil and natural gas production industry.

Cash Flow Used in Investing Activities. Cash flow from investing activities is derived from changes in oil and gas property balances. For the year ended March 31, 2026, net cash used for additions to oil and gas properties, net of drilling refunds and proceeds from property sales, was $2,109,157 compared to $3,154,575 in fiscal 2025. Cash used for an investment in a limited liability company was $427,429, compared to $1,000,000 in fiscal 2025.

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

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

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

Oil and Natural Gas Property Development

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Other Projects. We are participating in other projects and are reviewing projects in which we may participate. The cost of such projects would be funded, to the extent possible, from existing cash balances and cash flow from operations. The remainder may be funded through borrowings on the credit facility and, if appropriate, sales of non-core properties.

Pricing. Crude oil and natural gas prices remained volatile over the last year. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, in the last twelve months, the NYMEX West Texas Intermediate (“WTI”) posted price for crude oil has ranged from a low of $51.25 per bbl in December 2025 to a high of $98.86 per bbl in March 2025. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $2.65 per MMBtu in June and October 2025 to a high of $30.72 per MMBtu in January 2026, reflecting a temporary price spike during a period of severe weather and significant market volatility.

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

Results of Operations

Fiscal 2026 Compared to Fiscal 2025

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

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

	2026		2025		% Difference
Oil:
Revenue	$	5,276,981	$	6,145,674		(14.1	)%
Volume (bbls)		82,133		83,564		(1.7	)%
Average Price (per bbl)	$	64.25	$	73.54		(12.6	)%

Gas:
Revenue	$	1,271,067	$	970,811		30.9	%
Volume (mcf)		681,794		570,012		19.6	%
Average Price (per mcf)	$	1.86	$	1.70		9.7	%

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

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

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

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

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

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

Contractual Obligations

We have no off-balance sheet debt or unrecorded obligations, and we have not guaranteed the debt of any other party. The following table summarizes future payments we are obligated to make based on agreements in place as of March 31, 2026:

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

⁽¹⁾

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

Alternative Capital Resources

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

Other Matters

Critical Accounting Policies and Estimates

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

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

Full Cost Method of Accounting for Crude Oil and Natural Gas Activities. SEC Regulation S-X defines the financial accounting and reporting standards for companies engaged in crude oil and natural gas activities. Two methods are prescribed: the successful efforts method and the full cost method. We have chosen to follow the full cost method under which all costs associated with property acquisition, exploration, and development are capitalized. We also capitalize internal costs that can be directly identified with acquisition, exploration, and development activities and exclude any costs related to production, general corporate overhead, or similar activities. The carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation (“ARO”) when incurred.

Sales of oil and natural gas properties, whether or not currently being amortized, are accounted for as adjustments to capitalized costs. Gain or loss on the sale or other disposition of oil and gas properties is not recognized unless the sale would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas. This includes any sales of properties such as Term Assignments and Assignments, Bills of Sale and Conveyances.

Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization, and impairment of crude oil and natural gas properties are generally calculated on a well-by-well, lease, or field basis rather than the “full cost” pool basis. Additionally, gain or loss is generally recognized on all sales of crude oil and natural gas properties under the successful efforts method. As a result, our financial statements will differ from those of companies that apply the successful efforts method, since we will generally reflect a higher level of capitalized costs and a higher DD&A rate on our crude oil and natural gas properties.

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

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

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

Estimates of our proved reserves are based on the quantities of oil and gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our reserve estimates and the projected cash flows are derived from these reserve estimates, in accordance with SEC guidelines, by an independent engineering firm based in part on data provided by us. The accuracy of a reserve estimate is a function of the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgment of the persons preparing the estimate. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from actual future results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing, and production after the date of an estimate may justify material revisions to the estimate.

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

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

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

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

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

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

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

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

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

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

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

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

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

Reclassifications. Certain amounts in prior periods’ consolidated financial statements have been reclassified to conform with the current period’s presentation. These reclassifications had no effect on previously reported results of operations, retained earnings, or net cash flows.

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

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

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

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

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, 2026, our largest credit risk associated with any single purchaser was $474,335 or 37% of our total oil and gas receivables. We have not experienced any significant credit losses.

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

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

For example, in the last twelve months, the NYMEX West Texas Intermediate (“WTI”) posted price for crude oil has ranged from a low of $51.25 per bbl in December 2025 to a high of $98.86 per bbl in March 2026. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $2.65 per MMBtu in June and October 2025 to a high of $30.72 per MMBtu in January 2026, reflecting a temporary price spike during a period of severe weather and significant market volatility.

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

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

Similarly, any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations, and capital resources. Oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. If the average oil price had increased or decreased by ten dollars per barrel for fiscal 2026, our pretax income would have changed by $821,133. If the average gas price had increased or decreased by one dollar per mcf for fiscal 2026, pretax income would have changed by $681,794.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this item appears on pages F2 through F21 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 and applicable to all directors, officers, and employees of Mexco.

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

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

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

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 8, 2026 (“Proxy Statement”) to be filed with the SEC within 120 days after the end of our fiscal year ended March 31, 2026, 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 F22 of this report.

ITEM 16.

FORM 10-K SUMMARY

None

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 29, 2026

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of June 29, 2026, 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

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.

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 that has distinct characteristics differing from nearby rock.

Gross acres or wells. Refers to the total acres or wells, as the case may be, in which the Company owns a working, royalty, mineral, or other 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.

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 can be estimated 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.

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 a 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.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm (PCAOB ID Number 410)	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

To the Board of Directors and Shareholders of 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, 2026 and 2025, 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, 2026, 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, 2026 and 2025, and the results of its operations and its cash flows for each of the two years in the period ended March 31, 2026, 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 matter communicated below is a matter 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 a critical audit matter 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

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

F-2

Critical Audit 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.

Denver, Colorado

June 29, 2026

F-3

Mexco Energy Corporation and Subsidiaries

CONSOLIDATED BALANCE SHEETS

	March 31,			March 31,
	2026			2025
ASSETS
Current assets
Cash and cash equivalents	$	2,775,976		$	1,753,955
Accounts receivable:
Oil and natural gas sales		1,287,841			1,113,588
Trade		111,494			67,951
Prepaid drilling		204,218			24,381
Prepaid costs and expenses		68,846			60,981
Total current assets		4,448,375			3,020,856
Property and equipment, at cost
Oil and gas properties, using the full cost method		53,664,668			51,611,782
Other		125,501			121,926
Accumulated depreciation, depletion and amortization		(39,161,357	)		(36,637,530	)
Property and equipment, net		14,628,812			15,096,178
Investment – cost basis		2,527,429			2,100,000
Operating lease right-of-use asset		75,522			126,525
Other noncurrent assets		12,325			4,298
Total assets	$	21,692,463		$	20,347,857

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable and accrued expenses	$	379,929		$	307,387
Income tax payable		17,203			192,802
Operating lease liability, current		55,787			51,003
Total current liabilities		452,919			551,192
Long-term liabilities
Operating lease liability, long-term		19,735			75,522
Deferred income tax liability		533,673			320,604
Asset retirement obligations		699,317			688,842
Total long-term liabilities		1,252,725			1,084,968
Total liabilities		1,705,644			1,636,160

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 shares issued and 2,046,000 shares outstanding as of March 31, 2026 and 2025		1,119,641			1,119,641
Additional paid-in capital		9,018,953			8,844,953
Retained earnings		11,726,971			10,625,849
Treasury stock, at cost (193,283 shares)		(1,878,746	)		(1,878,746	)
Total stockholders’ equity		19,986,819			18,711,697
Total liabilities and stockholders’ equity	$	21,692,463		$	20,347,857

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,

	2026			2025
Operating revenues:
Oil sales	$	5,276,981		$	6,145,674
Natural gas sales		1,271,067			970,811
Other		13,276			23,954
Total operating revenues		6,561,324			7,140,439

Operating expenses:
Production		1,428,353			1,605,096
Accretion of asset retirement obligation		32,168			29,983
Depreciation, depletion and amortization		2,523,827			2,452,694
General and administrative		1,306,275			1,320,074
Total operating expenses		5,290,623			5,407,847

Operating income		1,270,701			1,732,592

Other income (expenses):
Income from investments in LLCs		329,102			217,627
Interest income		89,341			72,629
Interest expense		(4,379	)		(6,150	)
Net other income		414,064			284,106

Income before provision for income taxes		1,684,765			2,016,698

Provision for income taxes		379,043			304,330

Net income	$	1,305,722		$	1,712,368

Income per common share:
Basic:	$	0.64		$	0.83
Diluted:	$	0.63		$	0.81

Weighted average common shares outstanding:
Basic:		2,046,000			2,064,147
Diluted:		2,080,503			2,107,775

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, 2026 and 2025

	Common Stock Par Value		Additional Paid-In Capital		Retained Earnings			Treasury Stock			Total Stockholders’ Equity
Balance at April 1, 2024	$	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
Net income		-		-		1,305,722			-			1,305,722
Dividends paid		-		-		(204,600	)		-			(204,600	)
Stock based compensation		-		174,000		-			-			174,000
Balance at March 31, 2026	$	1,119,641	$	9,018,953	$	11,726,971		$	(1,878,746	)	$	19,986,819

SHARE ACTIVITY
	2026			2025
Common stock shares, issued:
At beginning of year		2,239,283			2,226,916
Issued		-			12,367
At end of year		2,239,283			2,239,283

Common stock shares, held in treasury:
At beginning of year		(193,283	)		(135,517	)
Acquisitions		-			(57,766	)
At end of year		(193,283	)		(193,283	)

Common stock shares, outstanding
At end of year		2,046,000			2,046,000

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,

	2026			2025
Cash flows from operating activities:
Net income	$	1,305,722		$	1,712,368
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax expense		213,069			8,943
Stock-based compensation		174,000			205,639
Depreciation, depletion and amortization		2,523,827			2,452,694
Accretion of asset retirement obligations		32,168			29,983
Amortization of debt issuance costs		4,343			4,299
Changes in operating assets and liabilities:
Increase in accounts receivable		(217,796	)		(170,644	)
Decrease (increase) in right-of-use asset		51,003			(107,262	)
Increase in prepaid expenses		(7,866	)		(4,788	)
(Decrease) increase in accounts payable and accrued expenses		(33,087	)		69,059
(Decrease) increase in operating lease liability		(51,003	)		107,262
(Decrease) increase in income tax payable		(175,599	)		3,548
Settlement of asset retirement obligations		(39,629	)		(41,480	)
Net cash provided by operating activities		3,779,152			4,269,621

Cash flows from investing activities:
Additions to oil and gas properties		(2,189,426	)		(3,416,616	)
Additions to other property and equipment		(3,575	)		-
Drilling refund		54,368			59,471
Investment in limited liability companies at cost		(427,429	)		(1,000,000	)
Proceeds from sale of oil and gas properties and equipment		25,901			202,570
Net cash used in investing activities		(2,540,161	)		(4,154,575	)

Cash flows from financing activities:
Proceeds from exercise of stock options		-			77,641
Proceeds from long-term debt		-			650,000
Debt issuance costs		(12,370	)		-
Dividends paid		(204,600	)		(209,000	)
Acquisition of treasury stock		-			(703,216	)
Reduction of long-term debt		-			(650,000	)
Net cash used in financing activities		(216,970	)		(834,575	)

Net increase (decrease) in cash and cash equivalents		1,022,021			(719,529	)

Cash and cash equivalents at beginning of year		1,753,955			2,473,484

Cash and cash equivalents at end of year	$	2,775,976		$	1,753,955

Supplemental disclosure of cash flow information:
Cash paid for interest	$	36		$	1,852
Cash paid for income taxes	$	362,802		$	228,487
Accrued capital expenditures included in accounts payable	$	144,047		$	38,417

Non-cash investing and financing activities:
Asset retirement obligations	$	9,592		$	5,231

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, 2026 and 2025

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, 2026, 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 include trade receivables from joint interest owners and oil and gas purchasers. The opening balance of accounts receivable from contracts with customers as of April 1, 2024, was $1,001,709. Credit is extended based on an evaluation of a customer’s financial condition and is generally uncollateralized. The collectibility of receivables is assessed, and an allowance is made for any credit losses. The allowance for credit losses is determined based on a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company has not experienced any significant credit losses. For the years ended March 31, 2026 and 2025, no allowance has been made for any credit losses.

Oil and Gas Properties. The Company accounts for its oil and natural gas properties using the full cost method of accounting. Under this method, all costs incurred in the acquisition, exploration, and development of oil and natural gas properties are capitalized and amortized using the unit-of-production method based on proved reserves. Costs directly related to exploration and development activities are capitalized, while production costs, general corporate overhead, and similar activities are expensed as incurred.

The carrying value of oil and natural gas properties includes asset retirement costs associated with the fair value of asset retirement obligations (“ARO”) when incurred.

Sales or other dispositions of oil and natural gas properties, whether or not currently being amortized, are generally accounted for as adjustments to capitalized costs, with no gain or loss recognized unless the disposition significantly alters the relationship between capitalized costs and proved reserves. This treatment includes transactions involving Term Assignments and Assignments, Bills of Sale and Conveyances.

Depletion of evaluated oil and natural gas properties is calculated using the unit-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, 2026 and 2025.

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 unweighted arithmetic average of the first-day-of-the-month prices for the preceding 12-month period, held constant 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 of our oil and gas properties does not affect cash flow from operating activities but does reduce stockholders’ equity and reported earnings. No impairment was recorded for the years ended March 31, 2026 or 2025.

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 accrues the estimated costs of plugging, restoration, and removal of facilities by recognizing the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which the obligation is incurred, typically at the inception of a well’s life, with a corresponding increase in the carrying amount of the related long-lived asset. The initial fair value is determined using the present value of estimated future cash flows, which incorporates management assumptions regarding ultimate plugging and abandonment costs, inflation factors, credit-adjusted risk-free discount rates, and the timing of settlement. Capitalized asset retirement costs are subsequently allocated to expense over the useful life of the related assets utilizing the units-of-production method, while the discounted ARO liability is accreted over time to its expected settlement value, with such changes reflected as accretion expense within the Consolidated Statements of Operations. Management continuously evaluates its estimates against changes in the legal, regulatory, environmental, and political environments; any subsequent revisions to the timing or amount of undiscounted estimated cash flows result in a corresponding adjustment to both the ARO liability and the carrying value of the related asset. Settlement of the liability is accounted for as an adjustment to the Company’s full cost pool with no gain or loss recognized, and for all periods presented, estimated future costs of abandonment and dismantlement are included in the full cost amortization base pursuant to SEC Regulation S-X Rule 4-10 and amortized as a component of depletion, depreciation, and amortization expense.

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.

F-9

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.

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 revenue checks are generally received two to three months after the production month, the Company accrues revenue earned but not yet received by estimating production volumes and product prices. Any identified differences between its revenue estimates and actual revenue received historically have not been significant.

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

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 to increase 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 non-operated working interests in areas with significant development potential.

F-10

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 $1,000,000 credit facility 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. On September 17, 2025, WTNB reaffirmed the borrowing base at $1,500,000. On March 28, 2026, the Agreement was amended to extend the maturity date to March 28, 2029.

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, 2026, the Company had $1,500,000 available to borrow under the facility.

No principal payments are anticipated to be required through the maturity date of the credit facility, March 28, 2029. Upon closing the third amendment to the Agreement, the Company paid a loan origination fee of $9,000 plus legal expenses totaling $12,200, 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 changes in control, disposition of assets, mergers, and reorganizations. The Company is also obligated to meet certain financial covenants under the Agreement including requirements that senior debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”) ratios (Senior Debt/EBITDA) is 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. Commencing with the fiscal quarter ending June 30, 2026, the amended Agreement requires the Company to maintain Senior Debt to EBITDA ratios less than or equal to 3.00 to 1.00 measured with respect to the four trailing quarters.

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 regular annual dividend in 2025 and special dividend in 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, 2026 and 2025. The following table is a summary of activity on the WTNB credit facility for the years ended March 31, 2026 and 2025:

Summary of Line of Credit Activity

	Principal
Balance at April 1, 2024:	$	-
Borrowings		650,000
Repayments		(650,000	)
Balance at March 31, 2025:	$	-
Borrowings		-
Repayments		-
Balance at March 31, 2026:	$	-

F-11

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 included in accounts payable and accrued expenses.

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

	2026			2025
Carrying amount of asset retirement obligations, beginning of year	$	718,842		$	718,808
Liabilities incurred		9,592			5,231
Liabilities settled		(31,285	)		(35,180	)
Accretion expense		32,168			29,983
Revisions		-			-
Carrying amount of asset retirement obligations, end of year		729,317			718,842
Less: Current portion		30,000			30,000
Non-Current asset retirement obligation	$	699,317		$	688,842

5. Income Taxes

On July 4, 2025, the “One Big Beautiful Bill” (“OBBB”) was enacted. The OBBB is a comprehensive piece of legislation that includes significant changes to federal tax policy, environmental funding, and energy development regulations. Key provisions relevant to the crude oil and natural gas industry include (i) tax policy changes that extend and expand components of the 2017 Tax Cuts and Jobs Act and (ii) the introduction of fee and royalty-related provisions aimed at reducing financial and administrative burdens on domestic energy producers. The Company has evaluated the impact of the OBBB; however, certain provisions continue to be assessed for their impact on our consolidated financial statements in future periods.

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 2021.

The income tax provision consists of the following for the years ended March 31, 2026 and 2025:

Schedule of Income Tax Provision

	2026			2025
	Year Ended
	March 31
	2026			2025
Current income tax expense:
Federal	$	107,292		$	232,035
State		58,682			63,352
Total current income tax expense	$	165,974		$	295,387
Deferred income tax expense (benefit):
Federal		224,910			56,614
State		(11,841	)		(47,671	)
Total deferred income tax expense	$	213,069		$	8,943
Total income tax expense:	$	379,043		$	304,330

Income tax for the year ended March 31, 2026 was $379,043. Income tax for the year ended March 31, 2025 was $304,330.

F-12

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:

	2026			2025
Deferred tax assets:
Percentage depletion carryforwards	$	1,108,633		$	1,283,374
Stock-based compensation		15,745			15,745
Asset retirement obligation		153,157			150,957
Other		94,650			82,083
Total deferred tax assets	$	1,372,185		$	1,532,159

Deferred tax liabilities:
Excess financial accounting bases over tax bases of property and equipment		(1,905,858	)		(1,852,763	)
Deferred tax liability, net	$	(533,673	)	$	(320,604	)
Valuation allowance		-			-
Net deferred tax liabilities	$	(533,673	)	$	(320,604	)

As of March 31, 2026, the Company has a statutory depletion carryforward of approximately $5,300,000, which does not expire.

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

	2026			% of Income Before Income Taxes			2025			% of Income Before Income Taxes
Tax expense at federal statutory rate ⁽¹⁾	$	353,801			21.0	%	$	423,507			21.0	%
Excess percentage depletion		(63,000	)		(3.7	)%		(153,438	)		(7.6	)%
Permanent differences		30,966			1.8	%		22,206			1.1	%
State income expense, net of federal benefit		37,004			2.2	%		50,048			2.5	%
Other		20,272			1.2	%		(37,993	)		(1.9	)%
Total income tax	$	379,043			22.5	%	$	304,330			15.1	%

⁽¹⁾

The federal statutory rate was 21% for fiscal years ending March 31, 2026 and 2025.

For the years ended March 31, 2026 and 2025, the Company did not have any uncertain tax positions.

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 2026, BTA Oil Producers, LLC accounted for 33% of the total operating revenues and 37% of the total oil and natural gas accounts receivable; Apex Natural Gas LLC accounted for 2% of the total operating revenues and 11% of the total oil and natural gas accounts receivable; and Exxon Mobil Corporation accounted for 15% of the total operating revenues and 7% of the total oil and natural gas accounts receivable. In fiscal 2025, BTA Oil Producers, LLC accounted for 59% of the total operating revenues and 43% of the total oil and natural gas accounts receivable; Permian Resources Corporation accounted for 6% of the total operating revenues and 6% of the total oil and natural gas accounts receivable; and, Pioneer Natural Resources accounted for 4% of the total operating revenues and 11% of the total oil and natural gas accounts receivable.

F-13

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:

	2026		2025
Property acquisition costs:
Proved	$	809,401	$	1,984,243
Unproved		-		-
Exploration		80,892		31,934
Development		1,170,674		1,417,163
Capitalized asset retirement obligations		9,592		5,231
Total costs incurred for oil and gas properties	$	2,070,559	$	3,438,571

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

	2026		2025
Proved oil and gas properties	$	53,664,668	$	51,611,782
Unproved oil and gas properties:
subject to amortization		-		-
not subject to amortization		-		-
Oil and gas properties, gross	$	53,664,668	$	51,611,782
Less accumulated DD&A		39,040,201		36,517,279
Total oil and gas properties	$	14,624,467	$	15,094,503

DD&A amounted to $11.02 and $13.74 per BOE of production for the years ended March 31, 2026 and 2025, 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:

	2026		2025
Net income	$	1,305,722	$	1,712,368

Shares outstanding:
Weighted avg. common shares outstanding – basic		2,046,000		2,064,147
Effect of the assumed exercise of dilutive stock options		34,503		43,628
Weighted avg. common shares outstanding – dilutive		2,080,503		2,107,775

Income per common share:
Basic	$	0.64	$	0.83
Diluted	$	0.63	$	0.81

For the years ended March 31, 2026 and 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, 2026.

F-14

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 has no expiration date and may be modified, suspended, or terminated at any time by the Board. Under the repurchase program, 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. As of March 31, 2026, the Company’s repurchase program approved in April 2024 had $296,784 in remaining funds.

Subsequently, in June 2026, the Board authorized the use of an additional $250,000 to repurchase shares of the Company’s common stock, par value $0.50, for the treasury account. To date, the Company’s repurchase program has $546,784 remaining.

During the year ended March 31, 2026, no shares of common stock were repurchased for the treasury account. 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.

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.

The Company recognized compensation expense of $174,000 and $205,639 related to vesting stock options in general and administrative expense in the Consolidated Statements of Operations for fiscal 2026 and 2025, respectively. The total cost related to non-vested awards not yet recognized at March 31, 2026 totals $106,173, which is expected to be recognized over a weighted average of 0.82 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 that the value realized by an optionee will be at or near the value estimated by the Binomial model.

During the years ended March 31, 2026 and 2025, there were no stock options granted.

The plan also provides for the granting of stock awards. No stock awards were granted during fiscal 2026 and 2025.

F-15

No forfeiture rate is assumed for stock options granted to directors or employees due to the Company’s historically low forfeiture experience for these types of awards. During the year ended March 31, 2026, there were no stock options forfeited or expired. During the year ended March 31, 2025, 1,875 unvested stock options and 625 vested stock options were forfeited due to the resignation of an employee.

The following table is a summary of activity of stock options for the years ended March 31, 2026 and 2025:

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, 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	$	-
Granted		-			-
Exercised		-			-
Forfeited or Expired		-			-
Outstanding at March 31, 2026		150,883		$	9.52		4.98	$	105,825

Vested at March 31, 2026		128,133		$	8.64		4.65	$	202,065
Exercisable at March 31, 2026		128,133		$	8.64		4.65	$	202,065

During the year ended March 31, 2026, no stock options were exercised. 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.

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

	2026		2025
Weighted average grant-date fair value of stock options granted (per share)	$	-	$	-
Total fair value of options vested	$	-	$	205,241
Total intrinsic value of options exercised	$	-	$	92,316

The following table summarizes information about options outstanding at March 31, 2026:

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		4.98	$	-

Outstanding options at March 31, 2026 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 consists of shared office expenditures, as well as administrative and operating expenses paid on behalf of the principal stockholder. The total amount billed to and reimbursed by the principal stockholder for the years ended March 31, 2026 and 2025 were $49,661 and $31,506, 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 years ending March 31, 2026 and 2025 were $10,175 and $11,974, 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 not currently involved in any legal proceedings that it considers probable to result in, or reasonably likely 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 expires on July 31, 2027.

The Company determines that an arrangement is a lease at inception. Operating leases are recorded as 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 judgment is required when determining the incremental borrowing rate. Rent expense for lease payments is recognized on a straight-line basis over the lease term.

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

	March 31, 2026
Assets
Operating lease right-of-use asset, beginning balance	$	126,525
Current period amortization		(51,003	)
Lease extension		-
Total operating lease right-of-use asset	$	75,522

Liabilities
Operating lease liability, current	$	55,787
Operating lease liability, long term		19,735
Total lease liabilities	$	75,522

Future minimum lease payments as of March 31, 2026 under non-cancellable operating leases are as follows:

	Lease Obligation
Fiscal Year Ended March 31, 2027		60,320
Fiscal Year Ended March 31, 2028		20,107
Total lease payments	$	80,427
Less: imputed interest		(4,905	)
Operating lease liability		75,522
Less: operating lease liability, current		(55,787	)
Operating lease liability, long term	$	19,735

Net cash paid for our operating lease for the years ended March 31, 2026 and 2025 was $50,145 and $47,653, respectively. Operating lease expense, including amortization of the operating lease right of use asset, and rent expense, less sublease income of $10,175, are included in general and administrative expenses on the consolidated statements of operations.

F-17

14. Acquisitions

During the year ended March 31, 2026, the Company incurred approximately $818,000 in acquisition costs to acquire various royalty interests in approximately 270 producing wells in Colorado, Louisiana, New Mexico, and Texas. These costs also included the purchase of additional royalty interests in 24 properties in which we already hold an interest in Louisiana and Texas, as well as 40 undeveloped net acres in New Mexico.

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 in Colorado, Louisiana, Montana, Nebraska, New Mexico, North and South Dakota, Texas, and Wyoming.

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, 2026 and 2025 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 market prices used for oil and gas reserve preparation, based on SEC guidelines.

	March 31,
	2026		2025		% Change
Prices utilized in the reserve estimates before adjustments:
Oil per Bbl	$	59.79	$	71.00		(16	)%
Natural gas per MMBtu	$	3.72	$	2.44		52	%

F-18

The Company’s total estimated proved reserves at March 31, 2026 were approximately 1.437 MMBOE, of which 46% was oil and 54% 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, 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
Revision of previous estimates		(106,000	)		315,000
Purchase of minerals in place		18,000			124,000
Extensions and discoveries		155,000			557,000
Sales of minerals in place		(1,000	)		(3,000	)
Production		(82,000	)		(682,000	)
As of March 31, 2026		659,000			4,671,000

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. The reduction in proved undeveloped reserves was primarily attributable to properties in Lea County, New Mexico, due to changes in the timing of future development in wells in which we own a working interest. These interests are held by production and remain in place for future development.

Summary of Proved Developed and Undeveloped Reserves as of March 31, 2026 and 2025:

	Oil (Bbls)		Natural Gas (Mcf)
Proved Developed Reserves:
As of April 1, 2024		444,610		3,566,240
As of March 31, 2025		405,840		3,654,900
As of March 31, 2026		462,780		4,204,610
Proved Undeveloped Reserves:
As of April 1, 2024		346,330		970,880
As of March 31, 2025		269,000		704,810
As of March 31, 2026		195,840		466,060

At March 31, 2026, the Company reported estimated PUDs of 274 MBOE, which accounted for 19% of its total estimated proved oil and gas reserves. This figure primarily consists of a projected 62 new wells (221 MBOE) operated by others. Of these wells, 41 wells are planned to be drilled in fiscal 2027, 17 wells in fiscal 2029, and 4 wells in fiscal 2030. The cost of these projects is expected to 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.

F-19

The following table discloses the Company’s progress toward the conversion of PUDs during fiscal 2026.

Progress of Converting Proved Undeveloped Reserves:

	Oil & Natural Gas (BOE)			Future Development Costs
PUDs, beginning of year		386,462		$	4,011,975
Revision of previous estimates		(106,667	)		(1,713,376	)
Sales of reserves		-			-
Conversions to PD reserves		(66,539	)		(119,475	)
Additional PUDs added		60,261			1,179,554
PUDs, end of year		273,517		$	3,358,678

Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2026 and 2025, 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. Estimated future development costs associated with the Company’s proved undeveloped properties through March 31, 2030 are $3,358,678.

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 contracts that include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.

The SEC reporting rules require that year-end reserve estimates and related future net cash flows be calculated using the unweighted arithmetic average of the first-day-of-the-month market prices for oil and natural gas during the 12-month period and discounted at 10% per year and assuming continuation of existing economic and operating conditions. The average prices used for fiscal 2026 were $62.76 per bbl of oil and $2.24 per mcf of natural gas. The average prices used for fiscal 2025 were $73.79 per bbl of oil and $2.14 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 flows 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, 2026 and 2025 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.

F-20

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

	2026			2025
	March 31
	2026			2025
Future cash inflows	$	51,791,000		$	59,135,000
Future production costs and taxes		(15,010,000	)		(18,172,000	)
Future development costs		(3,858,000	)		(4,137,000	)
Future income taxes		(3,843,000	)		(4,982,000	)
Future net cash flows		29,080,000			31,844,000
Annual 10% discount for estimated timing of cash flows		(10,415,000	)		(11,769,000	)
Standardized measure of discounted future net cash flows	$	18,665,000		$	20,075,000

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

	2026			2025
	March 31
	2026			2025
Sales of oil and gas produced, net of production costs	$	(5,120,000	)	$	(5,511,000	)
Net changes in price and production costs		(1,807,000	)		(2,735,000	)
Changes in previously estimated development costs		7,000			(1,111,000	)
Revisions of quantity estimates		(3,438,000	)		(5,155,000	)
Net change due to purchases and sales of minerals in place		838,000			1,996,000
Extensions and discoveries, less related costs		4,727,000			1,713,000
Net change in income taxes		675,000			1,309,000
Accretion of discount		2,322,000			2,321,000
Changes in timing of estimated cash flows and other		386,000			2,620,000
Changes in standardized measure		(1,410,000	)		(4,553,000	)
Standardized measure, beginning of year		20,075,000			24,628,000
Standardized measure, end of year	$	18,665,000		$	20,075,000

16. Employee 401(k) Plan

In January 2026, the Company adopted a defined contribution 401(k) retirement savings plan for eligible employees. As of March 31, 2026, the plan had not commenced operations, and no employee salary deferrals or employer matching contributions had been made. Accordingly, no expense related to the plan was recognized during the year ended March 31, 2026.

17. Subsequent Events

In April 2026, effective May 1, 2026, the Company acquired royalty interests in 144 producing wells in Weld County, Colorado and Atascosa, Howard, LaSalle, Martin, and Yoakum Counties, Texas, and additional royalty interests in 3 properties in which we already hold an interest in Howard County, Texas, for an aggregate purchase price of $1,028,600.

In May 2026, Mexco expended approximately $460,000 to participate in the drilling and completion of six horizontal wells in the Wolfcamp A formation of the Delaware Basin in Reeves County, Texas.

On June 4, 2026, 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 15, 2026. The dividend in the amount of $204,600 is to be paid on June 30, 2026.

In June 2026, effective July 1, 2026, the Company acquired royalty interests in 256 producing wells in Adams and Larimer Counties, Colorado; Caddo and DeSoto Parishes, Louisiana; Karnes, McMullen, Panola, and Winkler Counties, Texas; and Ashtabula County, Ohio for an aggregate purchase of $1,066,600.

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-21

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.

10.6		Third Amendment to Loan Agreement dated March 28, 2026 to the Loan Agreement between West Texas National Bank and Mexco Energy Corporation filed as Exhibit 10.6 to the Company’s Annual Report on Form 10-K dated June 26, 2026, 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 Interactive Data File (embedded within the Inline XBRL and contained in Exhibit 101)

F-22

MEXCO ENERGY CORP 10-K