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

Liquidity and Capital Resources and Commitments

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

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

During the fiscal year ended March 31, 2012, we repurchased 4,000 shares for the treasury at an aggregate cost of $22,780.

We had working capital of $476,960 as of March 31, 2012 compared to working capital of $470,253 as of March 31, 2011, an increase of $6,707.

For the year ending March 31, 2012, cash flow from operations was $1,573,296, an 18% increase when compared to the corresponding period of fiscal 2011. Cash of $1,642,449 was used for additions to oil and gas properties, $100,000 was used for net reduction of long-term debt and $471,543 was received primarily from the sale of a term leasehold interest in oil and gas properties. Accordingly, net cash increased $319,610.

In March 2011, we purchased approximately 10.8% working interest (7.77% net revenue interest) in 160 gross acres containing five (5) wells in the Fuhrman-Mascho Field of Andrews County, Texas, for an approximate cash purchase price of $670,000 funded from our $4.9 million credit facility. During fiscal 2012, we participated in the drilling of two (2) development wells on this acreage. Our share of the costs to drill and complete these wells through March 2012 was approximately $135,000. This acreage now contains seven (7) wells - four (4) producing oil from the San Andres formation and three (3) producing oil from the Grayburg and San Andres formations at an approximate depth of 5,000 feet. All 7 of these wells are operated by Cone and Petree Oil & Gas Exploration, Inc. This property contains an additional nine (9) potential drill sites in the Grayburg and San Andres formations with more dense spacing of approximately 10 acres per well. Six (6) of these potential sites are planned to be drilled in fiscal 2013. This new spacing in the Fuhrman-Mascho Field has been shown to increase production. In March 2012, we purchased an additional working interest in this acreage for an approximate cash purchase price of $275,000. We now own a total approximate 16.2% working interest (11.66% net revenue interest) in this acreage.

In June 2011, we received $450,000 in cash from Energen Corporation for the assignment of a five year term leasehold interest in 200 acres at $2,250 per acre. The assignment covers depths of 7,680' to 11,500' feet from the surface. Mexco retained a royalty of 8.33%. This interest has potential for oil production from the Avalon and Bone Springs in separate intervals by horizontal drilling above the prolific Vermejo-Fusselman Gas Field of Loving County, Texas. Energen has plans to drill three (3) wells on this acreage during our fiscal 2012, one of these wells began drilling in April 2012.

We participated in 37 infill wells in the Yeso/Paddock formations of the Dodd-Federal Unit in the Grayburg San Andres Jackson Field of Eddy County, New Mexico. Twenty-three of these wells have already been drilled with the balance scheduled to be drilled in the next twelve months to a total depth of approximately 5,000 feet. The unit, operated by Concho Resources, Inc., currently contains approximately 133 producing wells. Mexco's working interest in this unit .185% (.14% net revenue interest). Our share of the costs to drill and complete these wells through March 2012 was approximately $45,000. For the fiscal year ending March 31, 2011, we participated in the drilling of 5 producing wells in this unit.

A joint venture in which we are a working interest partner drilled two (2) infill wells in the Strawn formation on a 160-acre tract in Andrews County, Texas. The section in which this tract is located currently contains 12 completed wells on 40-acre spacing. Our share of the costs to drill and complete these wells through March 2012 for our approximately 1% working interest was approximately $64,000.

A joint venture in which we are a working interest partner drilled two (2) development wells in the Delaware and Bone Spring Sand formations on a 160-acre tract in Eddy County, New Mexico which currently contains four (4) producing wells. Our share of the costs to drill and complete the first of these wells through March 2012 for our approximately 1% working interest was approximately $29,000.

We participated in the drilling of two (2) development wells in the Cotton Valley-Bossier formation in the Teague Field of Freestone County, Texas. The 680-acre unit, operated by Valence Operating Company, currently contains 2 producing wells. Mexco's working interest in this unit is 4.2% (3.7% net revenue interest). Our share of the costs to drill and complete these wells through March 2012 was approximately $142,000.

A joint venture in which we are a working interest partner drilled two (2) infill wells in the Strawn formation on a 160-acre tract in Glasscock County, Texas. The immediate offsetting sections in which this tract is located currently contains 14 completed wells. Our share of the costs to drill and complete these wells through March 2012 for our approximately 1% working interest was approximately $64,000.

Two joint ventures in which we are a working interest partner began drilling three (3) development wells in Lea County, New Mexico. One well is on a 560-acre tract and is to be completed in the Abo formation. The other two wells are on a 640-acre tract which contains six wells currently producing and are to be completed in Bone Spring Sand formation. Our share of the costs to drill and complete these wells through March 2012 for our approximately 1% working interest was approximately $90,000.

We acted as operator and drilled a development well in Pecos County, Texas in which Mexco owns 100% working interest (78.8% net revenue interest). This well is currently being completed. Our costs to drill this well through March 31, 2012 were approximately $735,000.

At March 31, 2012, we reported estimated PUDs of 4.0 bcfe, which accounted for 38% of our total estimated proved oil and gas reserves. This figure primarily consists of a projected 18 new wells, 5 of which we operate, and 1 new zone behind pipe from a currently producing wellbore that we also operate. We project two operated wells to be drilled in fiscal 2013 with the three remaining in fiscal 2014. Regarding the remaining 13 PUD locations operated by others, a location is currently being prepared to drill one well with plans for seven wells to follow in 2013 and five in 2014.

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 our common stock. See Note 5 of Notes to Consolidated Financial Statements for a description of our revolving credit agreement with Bank of America, N.A.

Crude oil and natural gas prices have fluctuated significantly in recent years. The effect of declining product prices on our business is significant. Lower product prices reduce our cash flow from operations and diminish the present value of our oil and gas reserves. Lower product prices also offer us less incentive to assume the drilling risks that are inherent in our business. 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 West Texas Intermediate ("WTI") posted price for crude oil has ranged from a low of $75.75 per bbl in September 2011 to a high of $110.50 per bbl in April 2011. The Henry Hub Spot Market Price ("Henry Hub") for natural gas has ranged from a low of $2.00 per MMBtu in March 2012 to a high of $4.92 per MMBtu in June 2011. On March 31, 2012 the WTI posted price for crude oil was $99.50 per bbl and the Henry Hub spot price for natural gas was $2.00 per MMBtu. Management is of the opinion that cash flow from operations and funds available from financing will be sufficient to provide adequate liquidity for the next fiscal year.

Results of Operations

Fiscal 2012 Compared to Fiscal 2011

Net income was $329,993 for the year ended March 31, 2012, a 112% increase from $155,696 for the year ended March 31, 2011.

Oil and gas sales. Revenue from oil and gas sales was $3,223,659 for the year ended March 31, 2012, a 2% increase from $3,145,247 for the year ended March 31, 2011. This resulted from an increase in oil price and production partially offset by a decrease in gas price and production. The following table sets forth our oil and gas revenues, production quantities and average prices received during the fiscal years ended March 31:

                                      2012            2011         % Difference
         Oil:
         Revenue                   $ 1,810,459     $ 1,332,395             35.9 %
         Volume (bbls)                  19,442          17,040             14.1 %
         Average Price (per bbl)   $     93.12     $     78.19             19.1 %

         Gas:
         Revenue                   $ 1,413,200     $ 1,812,852            (22.0 %)
         Volume (mcf)                  395,649         459,446            (13.9 %)
         Average Price (per mcf)   $      3.57     $      3.95             (9.6 %)

Production and exploration. Production costs were $926,215 in fiscal 2012, a 10% decrease from $1,025,932 in fiscal 2011. This was primarily the result of last year's workover and repairs on one of our operated wells in Hutchinson County, Texas in which we own a 100% working interest.

Depreciation, depletion and amortization. Depreciation, depletion and amortization ("DD&A") expense was $996,205 in fiscal 2012, a 5% decrease from $1,047,906 in fiscal 2011, primarily due to a decrease in gas production partially offset by an increase to the full cost pool amortization base and a decrease in gas reserves partially offset by an increase in oil reserves.

General and administrative expenses. General and administrative expenses were $950,690 for the year ended March 31, 2012, an 8% increase from $877,790 for the year ended March 31, 2011. This was primarily due to an increase in stock option compensation expense.

Interest expense. Interest expense was $28,840 in fiscal 2012, a 21% decrease from $36,361 in fiscal 2011, due to a decrease in borrowings.

Income taxes. There was an income tax benefit of $27,960 in fiscal 2012 compared to an income tax benefit of $15,596 in fiscal 2011. This benefit was mainly the result of an increase in intangible drilling costs. The effective tax rate for fiscal 2012 was (9%) compared to (11%) for fiscal 2011.

Fiscal 2011 Compared to Fiscal 2010

Net income was $155,696 for the year ended March 31, 2011, as compared to net income of $400,839 for the year ended March 31, 2010.

Oil and gas sales. Revenue from oil and gas sales was $3,145,247 for the year ended March 31, 2011, a 2% decrease from $3,220,763 for the year ended March 31, 2010. This resulted from a decrease in oil and gas production and partially offset by an increase in oil and gas prices. The following table sets forth our oil and gas revenues, production quantities and average prices received the fiscal year ended March 31.

                                     2011            2010          % Difference
        Oil:
        Revenue                   $ 1,332,395     $ 1,194,500               11.5 %
        Volume (bbls)                  17,040          18,036               (5.5 %)
        Average Price (per bbl)   $     78.19     $     66.23               18.1 %

            Gas:
            Revenue                   $ 1,812,852     $ 2,026,263       (10.5 %)
            Volume (mcf)                  459,446         545,991       (15.9 %)
            Average Price (per mcf)   $      3.95     $      3.71         6.5 %

Production and exploration. Production costs were $1,025,932 in fiscal 2011, a 3% decrease from $1,054,224 in fiscal 2010. This was primarily the result of a decrease in production taxes due to the decrease in oil and gas sales.

Depreciation, depletion and amortization. Depreciation, depletion and amortization ("DD&A") expense was $1,047,906 in fiscal 2011, a 6% decrease from $1,113,141 in fiscal 2010, primarily due to a decrease in production and an increase in reserves partially offset by an increase to the full cost pool amortization base.

General and administrative expenses. General and administrative expenses were $877,790 for the year ended March 31, 2011, a 1% increase from $870,558 for the year ended March 31, 2010. This was primarily due to an increase in stock option compensation expense offset by a decrease in legal fees from the previous year for preparation of the Form S-8.

Interest expense. Interest expense was $36,361 in fiscal 2011, a 10% increase from $33,082 in fiscal 2010, due to an increase in borrowings.

Income taxes. There was an income tax benefit of $15,596 in fiscal 2011 compared to an income tax benefit of $257,235 in fiscal 2010. The 2010 benefit was primarily a result of a change in estimate related to the statutory depletion carryforward upon completion of the 2008 tax return.

Contractual Obligations

We have no off-balance sheet debt or unrecorded obligations and have not guaranteed the debt of any other party. The following table summarizes our future payments we are obligated to make based on agreements in place as of March 31, 2012:

Payments due in (1):

(1) Does not include estimated interest of $46,600 less than 1 year and $139,700 1-3 years.

These amounts represent the balances outstanding under the bank line of credit. These repayments assume that interest will be paid on a monthly basis and that no additional funds will be drawn.

Alternative Capital Resources

Although we have primarily used cash from operating activities and funding from the line of credit 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 the sale of assets and/or issuances of common stock through a private placement or public offering of our common stock.

Other Matters

Critical Accounting Policies and Estimates

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

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

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

Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. 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 or lease or field basis versus the "full cost" pool basis. Additionally, gain or loss is generally recognized on all sales of crude oil and natural gas properties under the successful efforts method. As a result our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher DD&A rate on our crude oil and natural gas properties.

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

Ceiling Test. Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test each quarter. The full cost ceiling test is an impairment test to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after tax present value of the future net cash flows from proved crude oil and natural gas reserves, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, 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 charge does not impact cash flow from operating activities, but does reduce our stockholders' equity and reported earnings.

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

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

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

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

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

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

Revenue Recognition. We recognize crude oil and natural gas revenue from our interest in producing wells as crude oil and natural gas is sold from those wells, net of royalties. We utilize the sales method to account for gas production volume imbalances. Under this method, income is recorded based on our net revenue interest in production taken for delivery.

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

Recent Accounting Pronouncements

In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting. The revised rules are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. In January 2010, the Financial Accounting Standards Board ("FASB") issued guidance that aligns the FASB's oil and gas reserve estimation and disclosure requirements with the new SEC rule revisions. The accounting standards revised the definition of proved reserves to permit consideration of new technologies in evaluating oil and natural gas reserves; require the use of an average price based on the prior twelve month period rather than year-end prices; permit the disclosure of probable and possible oil and gas reserves; require the reporting of the qualifications and measures taken to assure the independence and objectivity of any business entity or employee primarily responsible for preparing or auditing the reserves estimates; and, revise the disclosure requirements for oil and gas operations. The final rules and new guidance are effective for fiscal years ending on or after December 31, 2009. Mexco adopted these requirements as of March 31, 2010 and the results of the adoption are contained herein.

In May 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2011-04, Topic 820: Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs. ASU No. 2011-04 clarifies application of fair value measurements and disclosure requirements and is effective for Mexco as of April 1, 2012. We do not believe the guidance will have an impact on our fair value measurement and disclosures.

There were various other accounting standards and interpretations issued during our fiscal year, all of which have been determined to be not applicable or significant by management and once adopted are not expected to have a material impact on the Company's financial position, operations or cash flows.