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Item 7. Management’s Discussion and Analysis

2026-06-29 compared with 2025-06-27 · 259 added, 278 removed, 171 unchanged (76% of the section changed)

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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.

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.

and Capital Resources and Commitments

Historically,

we have funded our operations, acquisitions, exploration and development expenditures from cash generated by operating activities, bank

borrowings, sales of non-core properties and issuance of common stock.

Our primary financial resource is our base of oil and gas reserves.

We have pledged our producing oil and gas properties to secure our credit facility.

We do not have any delivery commitments to provide

a fixed and determinable quantity of our oil and gas under any existing contract or agreement.

long-term strategy is on increasing profit margins while concentrating on obtaining reserves with low-cost operations by acquiring and

developing oil and gas properties with potential for long-lived production.

We focus our efforts on the acquisition of royalties and

working interests and non-operated properties in areas with significant development potential.

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.

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.

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,

Net cash provided by operating activities

the Years Ended March 31,

Net cash provided by operating

Net cash used in investing activities

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Cash flow from operating activities is primarily derived from the production of our crude

oil and natural gas reserves and changes in the balances of non-cash accounts, receivables, payables or other non-energy property asset

account balances.

Cash flow provided by our operating activities for the year ended March 31, 2025 was $4,269,621 in comparison to $4,433,935

for the year ended March 31, 2024.

This decrease of $164,314 in our cash flow operating activities consisted of increase in our non-cash

expenses of $156,176;

an increase in our accounts receivable of $533,564;

an increase of $52,861 of our accounts payable and accrued

and, an increase in our net income for the current year of $367,416.

Variations in cash flow from operating activities may

impact our level of exploration and development expenditures.

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.

expenditures in operating activities consist primarily of drilling expenses, production expenses, and engineering services.

also consist of employee compensation, accounting, insurance and other general and administrative expenses that we have incurred in order

to address normal and necessary business activities of a public company in the crude oil and natural gas production industry.

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.

Flow Used in Investing Activities.

Cash flow from investing activities is derived from changes in oil and gas property balances.

For the year ended March 31, 2025, we had net cash of $3,154,575 used for additions to oil and gas properties and a $1,000,000 investment

in two limited liability companies compared to $3,016,499 and $400,000, respectively, for the year ended March 31, 2024.

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.

Flow Used in Financing Activities.

Cash flow from financing activities is derived from our changes in long-term debt and in equity

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 $834,575 for the year ended March 31, 2025 compared to net cash

flow used in our financing activities of $779,723 for the year ended March 31, 2024.

During the year ended March 31, 2025, we expended

$209,000 to pay the annual dividend, expended $703,216 to purchase 57,766 shares of our stock for the treasury account, and received

proceeds of $77,641 for the exercise of employee stock options.

During the year ended March 31, 2024, we expended $213,600 to pay the

annual dividend, expended $585,035 to purchase 50,101 shares of our stock for the treasury account, and received proceeds of $19,662

for the exercise of employee and director stock options.

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

had working capital of $2,469,664 as of March 31, 2025 compared to working capital of $3,259,200 as of March 31, 2024, a decrease of

$789,536 for the reasons set forth below.

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.

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

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.

and Natural Gas Property Development

Participations in Fiscal 2026.

The Company participated in the development of 35 horizontal wells at a cost of approximately

$1,100,000 for the year ending March 31, 2025.

Seventeen of these wells have not been completed.

Twenty-nine of these wells are in the

Delaware Basin located in the western portion of the Permian Basin in Lea and Eddy Counties, New Mexico;

three wells are in the Midland

Basin located in the eastern portion of the Permian Basin in Reagan County, Texas;

and, the remaining three horizontal wells are in Grady

County, Oklahoma.

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.

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.

expended approximately $207,000 to participate in the drilling of five horizontal wells in the Bone Spring formation of the Delaware

Basin in Lea County, New Mexico.

In November 2024, these wells were completed with initial average production rates of 1,106 barrels

of oil, 2,583 barrels of water and 1,165,000 cubic feet of gas per day, or 1,300 BOE per day.

expended approximately $293,000 to drill and complete four horizontal wells in the Wolfcamp Sand formation of the Delaware Basin in Lea

County, New Mexico.

In November 2024, these wells were completed with initial average production rates of 1,089 barrels of oil, 4,716

barrels of water and 3,601,000 cubic feet of gas per day, or 1,689 BOE per day.

expended approximately $117,000 for the drilling and completion of two horizontal wells in the Bone Spring Sand formation of the Delaware

Basin in Lea County, New Mexico.

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%.

In March 2025, these wells were completed with

initial average production rates of 1,734 barrels of oil, 3,171 barrels of water and 3,229,000 cubic feet of gas per day, or 2,272 BOE

expended approximately $176,000 for the drilling and completion of two horizontal wells in the Penn Shale formation of the Delaware Basin

in Lea County, New Mexico.

Mexco’s average working interest in these wells is .5%.

Subsequently, in June 2025, one of these wells

were completed with initial average production rates of 676 barrels of oil, 1,899 barrels of water and 729,000 cubic feet of gas per

day, or 798 BOE per day

expended approximately $46,000 for the drilling of two horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea

County, New Mexico.

expended approximately $79,000 to drill and complete two horizontal wells in the Bone Spring formation of the Delaware Basin in Lea County,

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%.

expended approximately $70,000 to participate in the drilling of six horizontal wells in the Bone Spring Sand formation of the Delaware

Basin in Lea County, New Mexico.

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%.

expended approximately $65,000 to participate in an exploratory vertical well in the Ellenburger formation of Ward County, Texas.

November 2025, this well was determined to be noncommercial.

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%.

Subsequently, in May 2025, Mexco expended approximately

$85,000 to complete these wells.

expended approximately $70,000 to participate in the development of three horizontal wells in the Spraberry trend of the Midland Basin

in Reagan County, Texas.

Mexco’s working interest in these wells is approximately .26%.

expended approximately $32,000 to participate in an exploratory well in the Fusselman Formation of Irion County, Texas.

This well was

determined to be noncommercial and was plugged and abandoned.

October 2022, the Company made an approximately 2% equity investment commitment in a limited liability company amounting to $2,000,000

of which $1,800,000 has been funded as of March 31, 2025.

The limited liability company is capitalized at approximately $100 million

to purchase mineral interests in the Utica and Marcellus areas in the state of Ohio.

This LLC has returned $252,394 or 14% of the total

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%.

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%.

of Wells Drilled in Fiscal 2025.

The Company expended approximately $300,000 for the completion of 19 horizontal wells in which the

The Company expended approximately $150,000 to complete seventeen horizontal wells in which the

Company participated during fiscal 2025.

Company expended approximately $107,000 for the completion costs of two horizontal wells in the Bone Spring Sand formation of the Delaware

Basin in Lea County, New Mexico that the Company participated in drilling during fiscal 2024.

Mexco’s working interest in these

wells is .53%.

In July 2024, these wells were completed with initial average production rates of 1,402 barrels of oil, 2,009 barrels

of water and 2,168,000 cubic feet of gas per day, or 1,763 BOE per day.

horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico in which the Company participated

during fiscal 2024 were completed in April 2024 with initial average production rates of 732 barrels of oil, 1,481 barrels of water and

657,000 cubic feet of gas per day, or 842 of oil equivalent per day.

Mexco’s working interest in these wells is approximately 1.16%.

horizontal well in the Penn Shale formation of the Delaware Basin in Lea County, New Mexico was completed in May 2024 with the initial

production rate of 964 barrels of oil, 2,441 barrels of water and 626,000 cubic feet of gas per day, or 1,068 of oil equivalent per day.

Mexco’s working interest in this well is .165%.

Company expended approximately $207,000 for the completion costs of four horizontial wells in the Bone Spring Sand formation of the Delaware

Basin in Lea County, New Mexico that the Company participated in drilling during fiscal 2024.

Mexco’s working interest in these

wells is .45%.

In October 2024, these wells were completed with initial average production rates of 893 barrels of oil, 2,990 barrels

of water and 1,161,000 cubic feet of gas per day, or 1,087 BOE per day.

These wells, located in the Delaware Basin of Lea County, New Mexico, have been completed and

turned to production.

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 April 2024, the Company acquired royalty interests in 21 producing wells operated by Anadarko Petroleum Corporation and Cimarex

Energy Company and located in Reeves County, Texas, for a purchase price of $158,000.

August 2024, the Company acquired royalty interests in 6 producing wells operated by Marathon Oil and located in Karnes County, Texas,

for a purchase price of $50,000.

This acquisition was effective August 1, 2024.

August 2024, the Company acquired royalty interests in 10 producing wells operated by Anadarko Petroleum Corporation and located in Weld

County, Colorado, for a purchase price of $118,000 and royalty interests in approximately 250 producing wells operated by Samson Exploration,

EOG Resources, and others in Laramie County, Wyoming and Adams and Weld Counties, Colorado, for a purchase price of $483,000.

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.

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.

September 2024, the Company acquired royalty interests in 21 producing wells operated by Marathon Oil and Murphy Exploration and located

in Karnes County, Texas, for a purchase price of $90,000, effective August 1, 2024.

October 2024, the Company acquired a .3% royalty interest in 15 producing wells operated by Civitas Resources, Inc.

and located in Broomfield

and Adams Counties, Colorado, for a purchase price of $450,000.

This acquisition was effective November 1, 2024.

October 2024, the Company acquired a .5% royalty interest in 3 producing wells operated by Mewbourne Oil Company and located in Eddy

County, New Mexico, for a purchase price of $260,000.

This acquisition was effective November 1, 2024 and includes acreage for further

October 2024, the Company acquired royalty interests in 8 producing wells operated by Marathon Oil and located in Live Oak County, Texas,

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 6 producing wells operated by SWN Production Company, LLC and located in DeSoto

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.

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.

Martin County, Texas for a purchase price of $18,300.

These acquisitions were effective December 1, 2025.

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.

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.

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;

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 interests in 10 producing wells operated by Ovintiv, Inc.

and located in

Upton County, Texas, for a purchase price of $65,000;

and, royalty interests in 12 producing wells operated by Pioneer Natural Resources

and located in Reagan and Upton Counties, Texas, for a purchase price of $65,000.

All of these acquisitions were effective November 1,

in October 2024 and effective November 1, 2024, the Company acquired various small royalty interests in over 400 producing wells operated

by Petro-Hunt Corporation, Hess Bakken Investments II, LLC, Marathon Oil, WPX Energy, and others in multiple counties throughout the

states of Nebraska, North Dakota, South Dakota, and Montana for a purchase price of $188,000.

of Properties.

In November 2024, the Company conveyed its working and royalty interests in 13.5 net acres in Ward County, Texas.

The Company received $15,000 per acre in the total amount of $202,500.

The Company retained an overriding royalty interest equal to the

positive difference between 25% and any existing burdens of record as of the effective date.

The divestiture of this non-core oil and

gas asset did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves

and, accordingly, the Company recorded the proceeds as sales proceeds, a reduction of its full cost pool, with no gain or loss recognized

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.

acquisitions were effective March 1, 2026.

We are participating in other projects and are reviewing projects in which we may participate.

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borrowings on the credit facility and, if appropriate, sales of non-core properties.

Crude oil and natural gas prices generally remained volatile during the last year.

The volatility of the energy markets makes it extremely

difficult to predict future oil and natural gas price movements with any certainty.

For example, in the last twelve months, the NYMEX

West Texas Intermediate (“WTI”) posted price for crude oil has ranged from a low of $61.73 per bbl in September 2024 to a

high of $82.89 per bbl in April 2024.

The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low

of $1.21 per MMBtu in November 2024 to a high of $9.86 per MMBtu in January 2025.

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.

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 has contributed

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.

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2026 Compared to Fiscal 2025

had net income of $1,712,368 for the year ended March 31, 2025 compared to $1,344,952 for the year ended March 31, 2024, a 27% increase

primarily as a result of an increase in operating revenues partially offset by an increase in operating expenses that is further explained

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.

and natural gas sales.

Revenue from oil and natural gas sales was $7,116,485 for the year ended March 31, 2025, a 10% increase from

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 oil and natural gas production volumes partially offset

by a decrease in oil and natural gas prices.

The following table sets forth our oil and natural gas revenues, production quantities and

average prices received during the fiscal years ended March 31:

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:

Volume (bbls)

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Average Price (per mcf)

operating revenues.

Other revenues increased 70% to $241,581 in fiscal 2025 from $142,237 in fiscal 2024.

This resulted from an increase

in income from one of our limited liability company investments.

Interest income on corporate funds decreased 46% to $72,629 in fiscal 2025 from $135,476 in fiscal 2024.

This decrease resulted

from using the corporate funds for property acquisitions and purchase of treasury stock.

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 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.

and exploration.

Production costs were $1,605,096 in fiscal 2025, a 5% increase from $1,526,472 in fiscal 2024.

Production costs were $1,428,353 in fiscal 2026, an 11% decrease from $1,605,096 in fiscal 2025.

This is the result

of an increase in production taxes due to an increase in oil and gas revenues and an increase in lease operating

expenses on new wells in which we own an interest.

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,

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a 3% increase from $2,452,694 in fiscal 2025.

This was primarily due to an increase in oil and natural gas production and a decrease

in oil and natural gas reserves.

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.

and administrative expenses.

General and administrative expenses were $1,320,074 for the year ended March 31, 2025, a 6% increase

from $1,243,548 for the year ended March 31, 2024.

This was primarily due to an increase in salaries and contract services, office expense,

engineering services and legal expenses partially offset by a decrease in employee stock option compensation.

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 tax for fiscal 2026 was $379,043 compared to $304,330 for fiscal 2025.

This was primarily due to a decrease in state

income taxes and the reconciliation to the federal tax return.

The effective tax rate for state and federal taxes combined for fiscal

2025 and fiscal 2024 was 15% and 32%, respectively.

The decrease in the effective tax rate is primarily the result of state income taxes,

primarily in New Mexico, the impact of permanent differences between book and taxable income, and the reconciliation to the federal tax

have no off-balance sheet debt or unrecorded obligations and have not guaranteed the debt of any other party.

The following table summarizes

future payments we are obligated to make based on agreements in place as of March 31, 2025:

Payments due in:

less than 1 year

The combined federal and state effective

tax rate for fiscal 2026 and fiscal 2025 was 22.5% and 15.1%, respectively.

Income Taxes to the Notes to Consolidated Financial Statements for additional information.

have no off-balance sheet debt or unrecorded obligations, and we have not guaranteed the debt of any other party.

The following table

summarizes future payments we are obligated to make based on agreements in place as of March 31, 2026:

Contractual obligations:

The lease amount

represents the monthly rent amount for our principal office space in Midland, Texas under a 36-month lease agreement

expiring July 31, 2027.

Of this total obligation for the remainder of the lease, our majority shareholder will pay $10,175 less than

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

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.

Capital Resources

we have primarily used cash from operating activities, the sales of assets and funding from the credit facility as our primary capital

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.

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results may differ from these estimates.

following represents those policies that management believes are particularly important to the financial statements and that require

the use of estimates and assumptions to describe matters that are inherently uncertain.

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.

Cost Method of Accounting for Crude Oil and Natural Gas Activities .

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We also capitalize internal costs that can be directly identified with acquisition, exploration, and

development activities and do not include any costs related to production, general corporate overhead or similar activities.

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.

of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs.

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.

of oil and natural gas properties, whether or not currently being amortized, are accounted for as adjustments to capitalized costs.

or loss on the sale or other disposition of oil and gas properties is not recognized unless the sale would significantly alter the relationship

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This includes any sales of properties such as Term Assignments

and Assignments, Bill of Sales and Conveyances.

and Assignments, Bills of Sale and Conveyances.

the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged

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depletion, amortization, and impairment of crude oil and natural gas properties are generally calculated on a well-by-well, lease, or

field basis versus the “full cost” pool basis.

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 companies that

apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher DD&A

rate on our crude oil and natural gas properties.

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.

the time it was adopted, management believed that the full cost method would be preferable, as earnings tend to be less volatile than

under the successful efforts method.

However, the full cost method makes us more susceptible to significant non-cash charges during times

of volatile commodity prices because the full cost pool may be impaired when prices are low.

These charges are not recoverable when prices

return to higher levels.

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 impact from the full cost method of accounting.

However, temporary drops in commodity

prices can have a material impact on our business, including the impact from the full cost method of accounting.

Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to

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This is called a “ceiling limitation

write-down.” This impairment to our oil and gas properties does not impact cash flow from operating activities, but does reduce

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.

risk that we will be required to write down the carrying value of crude oil and natural gas properties increases when crude oil and natural

gas prices are depressed or volatile.

In addition, write-downs may occur if we experience substantial downward adjustments to our estimated

proved reserves or if purchasers cancel long-term contracts for natural gas production.

An expense recorded in one period may not be

reversed in a subsequent period even though higher crude oil and natural gas prices may have increased the ceiling applicable to the

subsequent period.

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.

of our proved reserves are based on the quantities of oil and gas that engineering and geological analysis demonstrate, with reasonable

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Because these estimates depend

on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities

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.

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In preparing financial statements in conformity with accounting principles generally accepted in the United States

of America, management is required to make informed judgments, estimates and assumptions that affect the reported amounts of assets and

liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting

In addition, significant estimates are used in determining year end proved oil and gas reserves.

Although management believes

its estimates and assumptions are reasonable, actual results may differ materially from those estimates.

The estimate of our oil and

natural gas reserves, which is used to compute DD&A and impairment of oil and gas properties, is the most significant of the estimates

and assumptions that affect these reported results.

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.

management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates.

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.

Oil and gas properties include costs that are excluded from capitalized costs being amortized.

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increase the DD&A rate.

Revenues from our royalty and non-operated working interest properties are recorded

in accordance with ASC 606, Revenue from Contracts with Customers.

Revenue is reported net of post-production costs

when such costs are contractually deducted by the operator prior to distribution.

Since the revenue

checks are generally received two to three months after the production month, the Company accrues for revenue earned but not received

by estimating production volumes and product prices.

Any identified differences between its revenue estimates and actual revenue received

historically have not been significant.

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.

Retirement Obligations .

The estimated costs of plugging, restoration and removal of facilities are accrued.

The fair value of a liability

for an asset’s retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by

increasing the carrying amount of the related long-lived asset.

The liability is accreted to its then present value each period, and

the capitalized cost is depreciated by the units of production method.

If the liability is settled for an amount other than the recorded

amount, a gain or loss is recognized.

For all periods presented, we have included estimated future costs of abandonment and dismantlement

in the full cost amortization base and amortize these costs as a component of our depletion expense.

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.

capitalized asset retirement cost is depleted using the unit-of-production method over the life of the related proved reserves.

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.

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.

Compensation .

We use the Binomial option pricing model to estimate the fair value of stock-based compensation expenses at grant date.

This expense is recognized as compensation expense in our financial statements over the vesting period.

We recognize the fair value of

stock-based compensation awards as wages in the Consolidated Statements of Operations based on a graded-vesting schedule over the vesting

Our accounts receivable includes trade receivables from joint interest owners and oil and gas purchasers.

The Company uses the Binomial option pricing model to estimate the grant-date fair value of stock-based awards.

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 includes trade receivables from joint interest owners and oil and gas purchasers.

Credit is extended

based on an evaluation of a customer’s financial condition and, generally, is uncollateralized.

based on an evaluation of a customer’s financial condition and is generally uncollateralized.

The collectibility of receivables

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on estimated useful lives of three to ten years.

The Company accounts for investments of less than 3% of any limited liability companies at cost.

The Company has no control of the

limited liability companies.

The cost of the investment is recorded as an asset on the consolidated balance sheets and when income from

the investment is received, it is immediately recognized on the consolidated statements of operations.

The Company evaluates investments

for an impairment whenever events or changes in circumstances indicate that the carrying amount of an investment may not be recoverable.

Indicators of impairment may include, but are not limited to, sustained declines in market value, investee financial condition and operating

performance, industry or economic trends, and other relevant factors.

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.

the Company reviews the carrying value of investments measured under the measurement alternative for impairment on a regular basis.

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.

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These reclassifications had no effect on previously reported results of operations, retained earnings, or net cash flows.

Based on the Company’s organizational structure, the Company has one operating segment, which is crude oil and natural gas development,

exploration and production.

In addition, the Company has a single, company-wide management team that allocates capital resources to maximize

profitability and measures financial performance as a single enterprise.

The Company determines an arrangement is a lease at inception.

Operating leases are recorded in operating lease right-of-use asset,

operating lease liability, current, and operating lease liability, long-term on the consolidated balance sheets.

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:

oil and natural gas development, exploration, and production.

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

lease right-of-use assets represent the Company’s right to use an underlying asset for the lease term, and lease liabilities represent

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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 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 judgement is required when determining the incremental

borrowing rate.

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.

Adopted Accounting Pronouncements.

In December 2023, the FASB issued ASU 2023-09, Topic 740 Income Taxes:

Improvements to Income

Tax Disclosures, which is intended to enhance the transparency and decision usefulness of income tax disclosures.

The amendments in this

standard provide for enhanced income tax information primarily through changs to the rate reconciliation and income taxes paid.

ASU is effective for fiscal years beginning after December 15, 2024.

While the adoption of this ASU will modify the company’s

disclosures, it will not have an impact on the Company’s financial position, results of operations, or liquidity.

Accounting Pronouncements Not Yet Adopted.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis