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. In the past two fiscal years, we have obtained additional financing for prospects by selling fractional working interests to industry partners at prices in excess of our cost.

Our long term strategy is on increasing profit margins while concentrating on obtaining reserves with low cost operations by acquiring and developing primarily gas properties and secondarily oil properties with potential for long-lived production.

In fiscal 2009, we primarily used cash provided by operations ($2,794,379) to fund oil and gas property acquisitions and development ($2,937,939). We had working capital of $221,989 as of March 31, 2009 compared to working capital of $627,674 as of March 31, 2008, a decrease of $405,685. This was mainly a result of a decrease in accounts receivable and cash and cash equivalents. The accounts receivable decrease was mainly a result of a decrease in oil and gas sales during the fourth quarter from a decrease in oil and gas prices.

During the third quarter of fiscal 2008, we acted as operator and drilled an exploratory well in Loving County, Texas which has been completed. We have acquired right-of-way, built a pipeline and commenced testing and sales of natural gas from this well. Our share of the costs incurred for this project through April 2009 for our 31.25% working interest is approximately $567,000.

On June 6, 2008 we purchased mineral and royalty interests contained in an aggregate of 522 acres with royalties varying from .126% to .385% in 6 producing natural gas wells, 5 proven undeveloped well locations and an additional 6 potential drill sites in the Newark East (Barnett-Shale) Field of Tarrant County, Texas for approximately $429,000. This acreage now has 8 producing natural gas wells with an additional well currently being drilled. We subsequently purchased additional royalties in this acreage on March 31, 2009 for approximately $49,000.

Effective July 1, 2008, we purchased a well in Loving County, Texas which is capable of producing from the Lower Cherry Canyon section. We are acting as operator and have re-entered the well, tested one horizon as non-productive and tested the Bell Canyon, for which we are currently purchasing right-of-way for transmission and sales of natural gas. Our share of the costs for our 50.2% working interest through April 2009 is approximately $182,000.

In September 2008, we committed to participate in the drilling of a development well in Limestone County, Texas. This well has been completed and is currently producing. Costs incurred for this project through April 2009 are approximately $35,000.

In September 2008, we acted as operator and re-entered a well in Ward County, Texas to an approximate depth of 14,000 feet to test the upper and lower Pennsylvanian intervals. This well was recompleted, perforated, acid fraced and is currently being tested after completion of a pipeline for sales of natural gas. Costs incurred for this project through April 2009 for our 25.5% working interest are approximately $174,000. We also own a 2% overriding royalty interest in this well.

On October 16, 2008, we purchased interests in approximately 143 mineral acres amounting to an approximate 10% net royalty in three gas wells located in Johnson County, Texas for approximately $1,275,000. This property contains three
(3) development wells in the Newark East (Barnett Shale) Field which were put on production in mid-November 2008. Approximately 28 of the 143 acres are outside of the drilling and spacing unit for these three wells and are also available for further development. A Family Limited Partnership of a director and employee of the Company received a finder's fee of 2.5% of the mineral interest purchased in lieu of a cash payment as disclosed in a report to the SEC on Form 8-K dated October 15, 2008.

We continue to focus our efforts on the acquisition of royalties in areas with significant development potential.

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. See Note 3 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. During the second quarter of fiscal 2009, oil and gas prices began trending downward, while drilling, completion and operating costs remained high. 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 make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, the West Texas Intermediate ("WTI") posted price for crude oil has ranged from a low of $30.28 per bbl in December 2008 to a high of $145.31 per bbl in July 2008. The Henry Hub Spot Market Price ("Henry Hub") for natural gas has ranged from a low of $3.58 per MMBtu in March 2009 to a high of $13.31 in July 2008 per MMBtu. On March 31, 2009 the WTI posted price for crude oil was $49.64 per bbl and the Henry Hub spot price for natural gas was $3.58 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 2009 Compared to Fiscal 2008

Net income increased from $713,644 for the year ended March 31, 2008 to $1,170,570 for the year ended March 31, 2009, an increase of 64%.

Oil and gas sales. Revenue from oil and gas sales increased 25% from $3,887,955 in 2008 to $4,876,627 in 2009. This increase was attributable to an increase in oil price and gas production partially offset by a decrease in gas prices and oil production. The average oil price increased 7% from $77.05 per bbl in 2008 to $82.22 per bbl in 2009 and the average gas price decreased 4% from $6.70 in 2008 to $6.41 per mcf in 2009.

Production and exploration. Production costs decreased 4% from $1,240,305 in 2008 to $1,195,584 in 2009, primarily as a result of a 67% decrease in repairs and maintenance to operated wells in the El Cinco field offset by increased production and ad valorem taxes due to the increase in oil and gas sales and gas production. Oil production decreased 3% from 17,504 bbls in 2008 to 17,065 bbls in 2009 and gas production increased 43% from 379,048 mcf in 2008 to 542,099 mcf in 2009.

Depreciation, depletion and amortization. Depreciation, depletion and amortization ("DD&A") expense increased 34% from $779,618 in 2008 to $1,046,120 in 2009 due to an increase in production and an increase in full cost pool partially offset by an increase in gas reserves.

General and administrative expenses. General and administrative expenses increased 7% from $821,786 in 2008 to $876,756 in 2009, primarily as a result of an increase in salaries.

Interest expense. Interest expense decreased 22% from $105,312 in 2008 to $81,961 in 2009 due to a decrease in average borrowings and interest rates during the current fiscal year.

Income taxes. Income tax expense increased from $217,594 in 2008 to $528,262 in 2009, an increase of $310,668. This increase was attributable to our increased income.

Fiscal 2008 Compared to Fiscal 2007

Net income increased from $608,385 for the year ended March 31, 2007 to $713,644 for the year ended March 31, 2008, an increase of 17%.

Oil and gas sales. Revenue from oil and gas sales increased 31% from $2,969,325 in 2007 to $3,887,955 in 2008. This increase was attributable to an increase in oil and gas prices and oil and gas production. The average oil price increased 30% from $59.48 per bbl in 2007 to $77.05 per bbl in 2008 and the average gas price increased 15% from $5.82 in 2007 to $6.70 per mcf in 2008.

Production and exploration. Production costs increased 42% from $870,778 in 2007 to $1,240,305 in 2008, primarily as a result of an increase in repairs and maintenance to operated wells in the El Cinco field and increased production taxes due to the increase in oil and gas sales and production. Oil production increased 5% from 16,738 bbls in 2007 to 17,504 bbls in 2008 and gas production increased 12% from 339,174 mcf in 2007 to 379,048 mcf in 2008.

Depreciation, depletion and amortization. DD&A expense increased 19% from $652,826 in 2007 to $779,618 in 2008 due to an increase in production and an increase in full cost pool partially offset by an increase in reserves.

General and administrative expenses. General and administrative expenses decreased 1% from $829,180 in 2007 to $821,786 in 2008, primarily as a result of a decrease in stock option compensation expense partially offset by an increase in engineering and geological services for evaluation of projects.

Interest expense. Interest expense increased 338% from $24,046 in 2007 to $105,312 in 2008 due to an increase in average borrowings during the current fiscal year.

Income taxes. Income tax expense increased from a tax benefit of $28,050 in 2007 to a tax expense of $217,594 in 2008, an increase of $245,644. This increase was attributable to our increased income and a small revision of prior year estimates.

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.

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, 2009:

                                                   Payments Due In: (1)
                                 Total        less than 1 year       1-3 years       3 years
Contractual obligations:
Secured bank line of credit   $ 1,400,000     $               -     $ 1,400,000     $       -

(1) Does not include estimated interest of $40,300 less than 1 year and $120,800 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.

Other Matters

Critical Accounting Policies and Estimates

In preparing financial statements, management makes informed judgments 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 prescribed by SEC Regulation S-X Rule 4-10. The test determines 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 included in this report are prepared in accordance with GAAP and SEC guidelines. 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.

Our proved reserve information included in this report was based on evaluations prepared by independent petroleum engineers. 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, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.

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 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. Although management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates. Significant estimates affecting these financial statements include the estimated quantities of proved oil and gas reserves, the related present value of estimated future net cash flows and the future development, dismantlement and abandonment costs.

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") or a charge is made against earnings for those international operations where a reserve base has not yet been established. Impairments transferred to the DD&A pool increase the DD&A rate. Costs excluded for oil and gas properties are generally classified and evaluated as significant or individually insignificant properties.

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. We had no material gas imbalances.

Asset Retirement Obligations. The estimated costs of 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 April 2008, the FASB issued FASB Staff Position ("FSP") No. SFAS No. 142-3, Determination of the Useful Life of Intangible Assets ("FSP SFAS No. 142-3"). FSP SFAS No. 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, Goodwill and Other Intangible Assets ("SFAS No. 142"). The intent of FSP SFAS No. 142-3 is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141R and other applicable accounting literature. FSP SFAS No. 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and must be applied prospectively to intangible assets acquired after the effective date. We are currently evaluating the potential impact, if any, of FSP SFAS No. 142-3 on our financial statements.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles, which has been established by the FASB as a framework for entities to identify the sources of accounting principles and for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with US GAAP. SFAS No. 162 is effective 60 days following the SEC's approval of the Public Company Accounting Oversight Board's ("PCAOB") amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. The effective date of SFAS No. 162 was November 15, 2008. The adoption of this Standard did not have a material impact on our financial statements.

In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and natural gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new disclosure requirements are effective for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. The Company is currently assessing the impact that adoption of this rule will have on our financial statements, which will vary depending on commodity prices.