The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with the financial statements and the accompanying notes included elsewhere in this Form 10-K.

Statements in our discussion may be forward-looking. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations. See "Disclosures Regarding Forward-Looking Statements" at the beginning of this Annual Report and "Risk Factors" in Item 1A for additional discussion of some of these factors and risks.

Overview of Our Business

We are an independent natural gas and oil company engaged in the acquisition, development, and exploration of oil and gas properties, primarily in Texas. Our objective is to build a balanced portfolio consisting of oil and gas producing properties and reserves in both resource (developmental) and enhanced

oil recovery (redevelopment) plays. We will expand reserves through internally generated drilling projects coupled with complementary acquisitions.

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and gas and on our ability to find, develop and acquire oil and gas reserves that are economically recoverable. Our profitability depends upon our ability to control operations of our oil and gas assets.

We have a single company-wide management team that administers all properties as a whole rather than by independent operating segments. We track only basic operational data by area and we do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis.

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.

Industry Environment

We operate entirely within the United States, a mature region for the exploration and production of oil and gas. As a mature region, the size and frequency of new discoveries is declining, while finding and development costs are increasing.

We believe that there remain certain areas in the southern Mid-continent region which are under-explored or have not been fully explored and developed with the benefit of newly available exploration, production and reserve enhancement technology. Examples of such technology include advanced 3-D seismic processing, hydraulic reservoir fracture stimulation, advances in well logging and analysis, and enhanced oil recovery practices.

Another characteristic of a mature region is the historical exit of larger independent producers and major oil companies from such regions. These companies, searching for larger new discoveries, have ventured increasingly overseas and offshore, de-emphasizing their onshore United States assets. This movement out of mature basins by larger companies has provided acquisition opportunities for companies that are capable of

quickly analyzing opportunities, well positioned financially to quickly close an acquisition, and have the technical expertise to generate additional value from these assets.

In other situations, larger independent producers and major integrated oil companies have allowed smaller companies the opportunity to explore and develop reserves on their undeveloped acreage through joint ventures and farm-in arrangements.

We believe the acquisition market for natural gas properties has become extremely competitive as producers vie for additional production and expanded drilling opportunities. During the last fiscal year, leasehold acquisition values reached historic highs. While these prices have moderated with the decline in natural gas commodity prices, we expect these values to increase in the near future. As natural gas demand rebounds, we expect drilling and service costs pressures to increase, resulting in higher finding and development costs. In addition, we expect lease-operating expenses to continue to rise as producers are forced to make operational enhancements to maintain production in aging fields.

Crude oil and natural gas are commodities that are traded on regulated markets. The price that we receive for the crude oil and natural gas we produce is largely a function of market supply and demand. Demand for natural gas in the United States has increased dramatically over the last ten years. Demand is impacted by general economic conditions, estimates of gas in storage, weather and other seasonal conditions, including hurricanes and tropical storms. Demand for crude oil has also increased over the last ten years while the increase in supply has not increased proportionately resulting in a tight market. Market conditions involving over or under supply of crude oil and natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we saw extreme volatility during the last fiscal year. We expect the volatility to continue in the future. A substantial or extended decline in oil and gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and gas reserves that may be economically produced and our ability to access capital markets.

We derive our revenues from the sale of crude oil and natural gas that is produced from our properties. Revenues are a function of the volume produced and the prevailing market price at the time of sale. The price of oil and natural gas is the primary factor affecting our revenues.

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. During the March 31, 2009 we purchased and began refurbishing 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

Barnett Shale Project: During the fiscal year ended March 31, 2009, we completed the seven wells that were awaiting completion at the beginning of the fiscal year. We also drilled and completed six wells. At year-end, there were two wells drilled and awaiting completion. ReoStar retained an average working interest in these wells of 51.75% at a total net investment of $6.5 million.

Corsicana Project: We continued injecting surfactant polymer in phase I of the polymer project. We drilled 16 wells for phase II of the polymer project at a total net investment of $600,000. Rather than permit phase II wells individually, we applied for an area injection permit. At the end of the fiscal year, the permit had not yet been approved by the regulatory authorities. We will begin injection in phase II upon approval of the area wide injection permit.

We drilled two unsuccessful exploratory wells in Corsicana, one Pecan Gap test well and one Glen Rose test well. We sold 50% working interests in the wells to industry partners under a turn-key contract. Our dry hole costs associated with these wells was minimal based on the terms of the associated drilling contracts.

In December 2008, we drilled two successful Pecan Gap wells in the Corsicana area at a total net investment of $268,000. We retained a 50% working interest in these wells.

The average price per barrel of oil during the fiscal year was $89.44 compared with $80.48 for the fiscal year ended March 31, 2008. The average price realized per thousand cubic feet (MCF) of gas produced during the fiscal year was $5.27 compared with $6.25 fiscal year ended March 31, 2008

Oil and gas production for the year increased 35% to a total of 124,968 BOE compared with 92,193 BOE 67,821 for the fiscal year ended March 31, 2008. Oil and gas revenue for the year increased 33% to a total of $6.5 million compared to $4.9 million for the fiscal year ended March 31, 2008. We had a net loss of $2.0 million for the fiscal year compared to net income of $796,000 for the prior fiscal year.

During fiscal year ended March 31, 2009, our cash provided from operations was $825,000 and we invested $10 million on capital expenditures. Financing activities provided net cash of $9.0 million. The Company entered into a $25 million senior secured credit facility with an initial borrowing base of $14 million. The Company borrowed $9.8 million against the borrowing base during the fiscal year ended March 31, 2009.

On March 31, 2009, we had $426,000 in cash and total assets of $23.0 million. Debt consisted of payables to non-related parties of $9.1 million, of which $9.0 million were long-term note payables. We also had accounts and notes payables to related parties of $3.6 million.

Cash is required to fund capital expenditures necessary to offset inherent declines in production and reserves.. Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves.

We are in the process of securing additional capital financing. The additional financing may be in the form of additional equity, which would be dilutive to current shareholders. The financing may be in the form of a convertible debt instrument and the conversion feature would be dilutive to current shareholders. The additional financing could be a hybrid of the two. The proceeds of the financing will be used to close the acquisition of the South Texas leasehold, stage 1 of the South Texas drilling program, funding the fiscal year 2010 capital expenditure program in the Barnett Shale properties, refinancing the related party debt, and working capital.

Cautionary Statement: There can be no assurance that we will be successful in raising capital, whether in the form of equity, convertible debt, or a combination of the two. 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 our management and current shareholders. Additional equity financing will be dilutive to our then existing shareholders, and any debt financing could involve restrictive covenants with respect to future capital raising activities and other financial and operational matters.

Long-term cash flows are subject to a number of variables including the level of production and prices as well as various economic conditions that have historically affected the oil and gas business. A material drop in oil and gas prices or a reduction in production and reserves would reduce our ability to fund capital expenditures, meet financial obligations and/or remain profitable. We operate in an environment with numerous financial and operating risks, including, but not limited to, the inherent risks of the search for, development and production of oil and gas, the ability to buy properties and sell production at prices which provide an attractive return and the highly competitive nature of the industry. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings or the issuance of debt or equity securities. 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.

Cash Flow

Our principal sources of cash are net cash generated by oil and gas operations, the sale of a portion of the working interest in our drilling projects, and the issuance of equity or debt securities. Our operating cash flow is highly dependent on oil and gas prices.

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

Capital Requirements

Our primary needs for cash are for exploration and development of our Barnett Shale properties, establishing the enhanced oil recovery project the Pecan Gap drilling program in our Corsicana properties, and the acquisition of additional oil and gas properties, both in unconventional gas plays and re-development of mature fields. During the three months ended March 31, 2007, $4.5 million of capital was expended on Barnett Shale drilling projects, during the fiscal year ended March 31, 2008, $18.2 million of capital was expended on Barnett Shale drilling projects, and during the fiscal year ended March 31, 2009, $12 million of capital was expended on Barnett Shale drilling. For fiscal year 2008, $12.2 million of the capital program was funded via the sale of working interests on a turn-key basis and the balance of the capital program was funded by cash flow from operations and the proceeds of the private placement. For fiscal year 2009, $6.6 million of the capital program was funded via the sale of working interests on a turn-key basis and the balance of the capital program was funded by cash flow from operations and the proceeds of the senior secured credit facility.

We repurchased working interests in several of our Barnett properties during fiscal year 2009 for a total cost of $0.4 million.

Our capital expenditure budget for fiscal year 2010 is $27.5 million. Of this, $20 million is budgeted for the acquisition and stage I drilling of the 13,000 acres in south Texas, $7 million is budgeted for drilling in the Barnett Shale, and $0.5 million is budgeted for the Corsicana surfactant polymer project expansion and Pecan Gap drilling program. Our capital expenditure budget will be partially funded from our credit facility and cash flow from the properties. The majority of the capital expenditure budget will be funded from a planned equity financing.

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 March 31, 2009, we do not have any 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 March 31, 2008. In addition to the contractual obligations listed on the table below, our balance sheet at March 31, 2008 reflects accrued interest payable on our debt of $109,000 which is payable throughout the rest of 2008.

                                Fiscal year ended March 31
In thousands                   2010        2011       2012        Thereafter
    Office Lease           $  131,000    $    -   $         -   $          -
    Senior Credit Facility          -         -     9,800,000              -
Related Party Notes                 -         -             -      3,518,924

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. 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 2008 and 2009, commodity prices for oil and gas increased significantly. The higher prices led to increased activity in the industry and, consequently, sharply rising costs. These costs trends have put pressure not only on our operating costs but also on our capital costs.

Management's Discussion of 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.

Oil and Gas Properties

To ensure the reliability of our reserve estimates, we engage independent petroleum consultants to prepare an estimate of proved reserves. Proved the SEC defines 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. See Note 3 to the consolidated financial statements for information on these acquisitions.

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 . . .