MEXCO ENERGY CORP

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.

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.

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 toten years.

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

**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.

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.

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

**Investments.**The Company 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.

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 hasone reportable segment: crude oil and natural gas development, exploration, and production.

**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.

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

3. Long-Term Debt

On December 28, 2018, the Company entered into a loan agreement (the “Agreement”) with West Texas National Bank (“WTNB”), which originally provided for a $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 wasno 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:

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:

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:

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

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:

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:

For the years ended March 31, 2026 and 2025, the Company didnot 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.

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:

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

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:

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.

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 expiresten 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.

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 wereno 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:

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:

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

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.

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:

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

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.

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.

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:

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:

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.

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

Progress of Converting Proved Undeveloped Reserves:

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.

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

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

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 itsshareholders 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.

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