CAUTIONARY STATEMENT

You should read the following discussion and analysis in conjunction with our unaudited condensed consolidated financial statements and the related notes thereto contained elsewhere in this report. The information contained in this quarterly report on Form 10-Q is not a complete description of our business or the risks associated with an investment in our common stock. We urge you to carefully review and consider the various disclosures made by us in this report and in our other reports filed with the Securities and Exchange Commission, or SEC, including our annual report on Form 10-K for the year ended March 31, 2009 and subsequent reports on Form 8-K, which discuss our business in greater detail.

In this report we make, and from time to time we otherwise make, written and oral statements regarding our business and prospects, such as projections of future performance, statements of management's plans and objectives, forecasts of market trends, and other matters that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Statements containing the words or phrases "will likely result," "are expected to," "will continue," "is anticipated," "estimates," "projects," "believes," "expects," "anticipates," "intends," "target," "goal," "plans," "objective," "should" or similar expressions identify forward-looking statements, which may appear in documents, reports, filings with the Securities and Exchange Commission, news releases, written or oral presentations made by officers or other representatives made by us to analysts, stockholders, investors, news organizations and others, and discussions with management and other of our representatives. For such statements, we claim the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995.

Our future results, including results related to forward-looking statements, involve a number of risks and uncertainties. Such risks and uncertainties include, but are not limited to, changes in local, regional, and national economic and political conditions, the effect of governmental regulation, competitive market conditions, our ability to obtain additional financing, and other risks detailed herein and from time to time in our SEC reports. No assurance can be given that the results reflected in any forward-looking statements will be achieved. Any forward-looking statement speaks only as of the date on which such statement is made.

Overview of Our Business

We are engaged in the exploration, development and acquisition of oil and gas properties, primarily located in the state of Texas. We seek to increase oil and gas reserves and production through internally generated drilling projects, coupled with complementary acquisitions.

We own approximately 9,500 gross acres of leasehold, which include 5,700 acres of exploratory and developmental prospects as well as 3,800 acres of enhanced oil recovery prospects. We have built a multi-year inventory of drilling projects and drilling locations and currently have enough acreage to sustain several years of drilling.

Our corporate offices are located at 3880 Hulen Street, Suite 500, Fort Worth, Texas 76107. Our telephone number is (817) 989-7367.

Business Strategy

Our objective is to build shareholder value by establishing and consistently growing our production and reserves with a strong emphasis on cost control and risk mitigation. Our strategy is (1) to control operations of all our leases via our affiliated operating companies, (2) to acquire and develop leasehold in key regional resource development plays while utilizing existing infrastructure and engaging in long-term drilling and development programs, and (3) to acquire leasehold in mature fields and implement enhanced oil recovery programs.

Industry Environment

The globalization of the world's economy, the rapid development of the emerging markets, and increased commodity speculation have recently resulted in unprecedented commodity pricing and volatility. Oil prices peaked at unprecedented highs in July 2008 before contracting significantly. At their low in January 2009, oil prices were down more than 75% from the July highs. Prices have since nearly doubled to approximately $70 per barrel.

While natural gas is also a fungible commodity, it is more regional in nature than oil. Constant changes in regional supplies and demand have resulted in significant pricing volatility in the natural gas market as well. Natural gas prices (the Houston Ship Channel index) peaked at $13 per MMBTU in early July 2008 and have since then dropped by more than 75%. Natural gas prices remain weak with current pricing under $4 per MMBTU.

The rapid run up in commodity prices encouraged substantial drilling, which resulted in upward pressure on finding and development costs. For example, during last fiscal year, a shortage of pipe caused casing and tubing prices to dramatically increase, which resulted in a material increase in total completion costs.

The commodity pricing volatility accompanied with cost volatility has significantly reduced operating margins and has negatively impacted our ability to accurately forecast cash flows.

The recent reduction in commodity pricing for natural gas has helped ease drilling and service costs pressures. However, we expect them to remain at a high level relative to past pricing. In addition, we expect lease operating expenses to continue to rise as producers are forced to make operational enhancements to maintain production in more mature fields.

We believe that in order for an independent oil and gas producer to be successful, the producer must either operate its leases effectively or have significant operational control over its oil and gas properties. As commodity prices fluctuate, controlling costs through operations will make the difference between turning a profit and incurring a financial loss.

Principal Components of Our Cost Structure

• Direct Operating Expenses. These are day-to-day costs incurred to bring hydrocarbons out of the ground and to the market together with the daily costs incurred to maintain our producing properties. Such costs also include work-over repairs to our oil and gas properties not covered by insurance. To minimize and help control our costs, we acquired a work-over drilling rig and a swab rig in June of 2007. We recently purchased and refurbished a shallow well oil drilling rig which will be used to drill our Corsicana Nacatoch and Pecan Gap wells.

• Production and Ad Valorem Taxes. These costs are primarily paid based on a percentage of market prices or at fixed rates established by federal, state or local taxing authorities.

• Exploration Expense. The costs include geological and geophysical costs, seismic costs, delay rentals and the costs of unsuccessful wells or dry holes. While our current asset mix requires a minimum of geological and geophysical costs and seismic costs, it is possible this component of our cost structure could sharply increase depending upon future property acquisitions.

• Plugging Costs. The Corsicana field is over one hundred years old and has hundreds of abandoned well bores scattered throughout the properties. In order to properly execute our enhanced oil recovery projects, we need to plug these abandoned, worn out well bores. Since the wells are fairly shallow, we are able to cement in the entire well bore at a cost of less than $1,500 per well.

• General and Administrative Expenses. Overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of finding our working interest partners, costs of managing our production and development operations, audit and other professional fees and legal compliance are included in general and administrative expense. General and administrative expense includes stock-based compensation expense (non-cash) associated with the adoption of SFAS No. 123(R), amortization of restricted stock grants as part of employee compensation.

• Interest. We increased our levels of debt during fiscal year 2009, and in the future, we may finance a larger portion of our working capital requirements and acquisitions with borrowings under a credit facility or with longer-term public traded debt securities. As a result, interest expense could become a much more prevalent component of our cost structure.

• Depreciation, Depletion and Amortization. As a successful efforts company, we capitalize all costs associated with our acquisition and all successful development and exploration efforts, and apportion these costs to each unit of production through depreciation, depletion and amortization expense. This also includes the systematic, monthly depreciation of our oilfield equipment assets.

• Changes in Estimates. Changes in estimates of proved reserves significantly impact the depletion expense we record each year. When proved reserves increase, our depletion rate decreases, resulting in a lower depletion expense and higher net income. Conversely, as proved reserves decrease, our depletion rate increases, resulting in a higher depletion expense and lower net income. Changes in estimates of proved reserves are frequently the result of changes in commodity prices, changes in operating costs, and reservoir performance history. While depletion is a non-cash expense, volatility in commodity prices and the resulting volatility in depletion can have a material impact on our profitability and on certain leverage ratios.

• Income Taxes. We are subject to federal income taxes but are currently not in a tax paying position for regular federal income taxes, primarily due to the current deductibility of intangible drilling costs ("IDC"). Currently, we are not subject to state income taxes. Virtually all of our Federal taxes are deferred; however, at some point, we will utilize all of our net operating loss carry-forwards and we will recognize current income tax expense and continue to recognize current tax expense as long as we are generating taxable income.

Results and Analysis of Financial Condition, Cash Flows and Liquidity

During the quarter ended June 30, 2009, we sold approximately 7,175 barrels of oil compared with approximately 14,630 barrels of oil for the quarter ended June 30, 2008, a decrease of approximately 50%.

The average price for oil sold during the quarter ended June 30, 2009 was $56.50 per barrel compared with the average price for the quarter ended June 30, 2008 of $123.01 per barrel, a decrease of 54%.

We sold approximately 111,160 mcf of gas for the quarter ended June 30, 2009 compared with approximately 109,755 mcf of gas for the same period a year earlier, an increase of approximately 1%. The average price for natural gas sold during the quarter ended June 30, 2009 was $1.91 per mcf (net of transportation, compression and CO2 charges) compared with $8.68 per mcf for the quarter ended June 30, 2009, a decrease of approximately 78%.

Oil and gas revenues for the three months ended June 30, 2009 were $618,071 compared with $2,752,747 for the three months ended June 30, 2008, a decrease of approximately 78%.

During the quarter ended June 30, 2009, we incurred drilling and completion costs of approximately $135,000.

On June 30, 2009, we had $518,000 in cash and total assets of $23.5 million. Debt consisted of accounts and notes payables to non-related parties of $10.9 million, of which, $10.8 million is long-term. We also had accounts and notes payables to related parties of $3.7 million.

During the quarter, we drew $1 million on the Union Bank credit facility secured by our assets. The material terms of the credit facility were reported on our Form 8-K filed on November 4, 2008. The remaining credit available under the credit facility at quarter end was $3.2 million.

We continue to consider various other financing options which may or may not be implemented during this fiscal year.

Cash Flow
Our principal sources of cash are operating cash flow, the sale of a portion of the working interest in our drilling projects, the credit facility and other financing options, including debt and equity, which may be available to us from time to time. Our operating cash flow is highly dependent on oil and gas prices.

Based on current projections and oil and gas futures prices, the balance of the 2010 capital program is expected to be funded with internal cash flow and the proceeds of the credit facility.

Capital Requirements
Our primary needs for cash are for exploration of the Pecan Gap acreage in our Corsicana leasehold, development drilling in our Barnett Shale properties, expanding the enhanced oil recovery projects in our Corsicana properties, and the acquisition of additional oil and gas properties. Due to the tightening credit and equity markets, the increased costs, and the recent contraction in commodity pricing, we have suspended our development drilling program in the Barnett Shale and have deferred planned expansion of the enhanced oil recover project in Corsicana. Management has set a capital expenditure budget of $3 million for fiscal year 2010.

The capital expenditure budget will primarily be invested on the Pecan Gap drilling program. The wells are approximately 1,500 feet deep and cost approximately $100,000 each to drill. We have working interest partners that have agreed to participate in the drilling program and we may drill as many as 35 wells during the fiscal year. We expect to retain between 50% and 75% of each well. The balance of the capital expenditure budget will be invested in the drilling of two additional Barnett wells to meet our drilling requirements and in the completion of two Barnett wells that were drilled during the prior fiscal year.

There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to efficiently develop our properties and offset inherent declines in production and proved reserves. Even if we are successful in raising capital through the sources specified, there can be no assurances that any such financing would be available in a timely manner or on terms acceptable to us and our shareholders. Additional equity financing could be dilutive to our shareholders, and any debt financing could involve restrictive covenants with respect to future capital raising activities and other financial and operational matters.

Future Commitments
In addition to our capital expenditure program, we are committed to making cash payments in the future on two types of contracts: note agreements and operating leases. As of June 30, 2009, we have no capital leases nor have we entered into any material long-term contracts for equipment, nor do we have any off-balance sheet debt or other such unrecorded obligations.

The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at June 30, 2009. In addition to the contractual obligations listed on the table below, our balance sheet at June 30, 2009 reflects accrued interest payable on our debt of $136,027.

                                         Fiscal Years Ending March 31,
                                         2010          2011         2012        Thereafter       Total
Office Lease Payments                $   93,100    $       -   $          -   $          -   $     93,100
Notes Payable - Related Parties               -            -              -       3,518,92      3,518,924
Senior Secured Note Payable                   -            -     10,800,000              -     10,800,000
                                     $   93,100    $       -   $ 10,800,000   $  3,518,924   $ 14,412,024

Hackberry Prospect Acquisition
On May 20, 2009, the Company entered into a Purchase and Sale Agreement to acquire 13,000 acres leasehold estate with rights to acquire an additional 30,000 acres designated within an area of mutual interest, known as the Hackberry Project. The Company also entered into a related Development Agreement providing for the operator of the prospect and its development.

The closing of the acquisition and related development was subject to certain conditions precedent, and the agreements provided that if the transactions did not close by August 1, 2009, both the Purchase and Sale Agreement and the Development Agreement would terminate pursuant to their own terms. The transactions were not consummated by August 1, 2009, and the agreements have therefore been terminated and are of no further force and effect.

Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements to enhance liquidity and capital resource position, or for any other purpose.

Inflation and Changes in Prices
Our revenues, the value of our assets, and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in oil and gas prices and the costs to produce our reserves. Oil and gas prices are subject to significant fluctuations that are beyond our ability to control or predict. The hedges put in place in the prior year have all expired.

In July, the Company placed hedges on a portion of our future production. The hedging contracts we entered into have locked the price we receive for oil for the balance of calendar 2009 in at $70.40 per barrel for 2,000 barrels per month. We also collared prices for 2,000 barrels of oil per month for calendar year 2010 with a floor of $65 per barrel and a ceiling of $85 per barrel. For natural gas, we locked the price we receive for 20,000 MMBTU per month for the balance of 2009 at $4.205 per MMBTU. From January through June 2010, we locked natural gas prices for 20,000 MMBTU per month at $5.54 per MMBTU. From July through December 2010, we collared natural gas prices for 20,000 MMBTU per month at a floor of $5.50 per MMBTU and a ceiling of $6.50 per MMBTU.

As our production grows, we may increase the number of hedges we have in place. Additionally, we may place hedges further into the future.

Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and accelerated during the first quarter, commodity prices for oil and gas increased significantly. The higher prices led to increased activity in the industry and, consequently, rising costs. These costs trends have put pressure not only on our operating costs but also on our capital costs. Industry capital costs have nearly doubled during the last two years. Industry analysts expect the trend to continue during the next fiscal year.

Critical Accounting Estimates

Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at year-end and the reported amounts of revenues and expenses during the year. We base our estimates on historical experience and various other assumptions that we believe are reasonable; however, actual results may differ.

Certain accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions is material due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (b) the impact of the estimates and assumptions on financial condition or operating performance is material.

Successful Efforts Method of Accounting

We account for our exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and natural gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area.

The successful efforts method of accounting can have a significant impact on the operational results reported when we enter a new exploratory area in hopes of finding an oil and natural gas field that will be the focus of future developmental drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional exploration expenses when incurred.

To ensure the reliability of our reserve estimates, we engage independent petroleum consultants to prepare an estimate of proved reserves. The SEC defines proved reserves as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Although our engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, the estimation of reserves requires engineers to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually and consider recent production levels and other technical information. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price and cost changes and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in the depletion rates utilized by us. We cannot predict what reserve revisions may be required in future periods.

We monitor our long-lived assets recorded in property, plant and equipment in our consolidated balance sheet to ensure they are fairly presented. We must evaluate our properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable oil and gas reserves that will be produced from a field, the timing of future production, future production costs, future abandonment costs, and future inflation. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or gas, unfavorable adjustment to reserves, physical damage to production equipment and facilities, a change in costs, or other changes to contracts, environmental regulations or tax laws. All of these factors must be considered when testing a property's carrying value for impairment. We cannot predict whether impairment charges may be required in the future. We are required to develop estimates of fair value to allocate purchase prices paid to acquire businesses to the assets acquired and liabilities assumed under the purchase method of accounting. The purchase price paid to acquire a business is allocated to its assets and liabilities based on the estimated fair values of the assets acquired and liabilities assumed as of the date of acquisition. We use all available information to make these fair value determinations.

Deferred Taxes

We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed many months after the close of a calendar year, tax returns are subject to audit which can take years to complete and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carry forwards and other deductible differences. We routinely evaluate deferred tax assets to determine the likelihood of realization. A valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are not likely to be realized. In determining deferred tax liabilities, accounting rules require OCI to be considered, even though such income or loss has not yet been earned.

At June 30, 2009, deferred tax liabilities exceeded deferred tax assets by $1.36 million. We may be challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in our various income tax returns. Although we believe that we have adequately provided for all taxes, gains or losses could occur in the future due to changes in estimates or resolution of outstanding tax matters.

Contingent Liabilities

A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of costs can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent . . .