REOS 10-K Annual Report March 31, 2010 | Alphaminr
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REOS 10-K Fiscal year ended March 31, 2010

Balance Sheet
Cash Flow
Income Statement
Debt
REOSTAR ENERGY CORP
10-K 1 reo10k033110.htm REOSTAR ENERGY CORP - Form 10-K Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K


[x] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended March 31, 2010

Commission file number 000-26139

REOSTAR ENERGY CORPORATION
(Name of small business issuer in its charter)

Nevada
20-8428738
(State or other jurisdiction of
incorporation or organization)
(IRS Employer Identification Number)

3880 Hulen St., Ste 500, Fort Worth, TX
76107
(Address of principal executive offices)
(Zip Code)

Issuer's telephone number: 817-989-7367

Securities registered under Section 12(b) of the Exchange Act:
None

Securities registered under Section 12(g) of the Exchange Act:

Common Stock, $.001 par value
(Title of class)

Check whether the issuer is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. o

Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B contained in this form, and no disclosure will be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

Revenue for the fiscal year ended March 31, 2010 is $3,533,722 and the aggregate market value of the voting stock held by non-affiliates of the registrant based on the closing bid price of such stock as of March 31, 2010 amounted to $2,307,592.

The number of shares outstanding of the registrant's common stock as of March 31, 2010 was 80,743,912 shares.



Table of Contents



DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement for the registrant's 2010 annual meeting of shareholders to be filed with the SEC within 120 days after the end of the fiscal year ended March 31, 2010 are incorporated by reference in Part III of this Form 10-K.

Transitional Small Business Disclosure Format (check one): Yes o No x







REOSTAR ENERGY CORPORATION
FORM 10-K ANNUAL REPORT
FISCAL YEAR ENDED MARCH 31, 2010
TABLE OF CONTENTS

PART I
Page No.
Item 1. Business
1
Item 1A. Risk Factors
7
Item 1B. Unresolved Staff Comments
13
Item 2. Properties
13
Item 3. Legal Proceedings
15
Item 4. Submission of Matters to a Vote of Security Holders
16
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
16
Item 6. Selected Financial Data
17
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
17
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
23
Item 8. Financial Statements and Supplementary Data
F-1
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
24
Item 9A(T). Controls and Procedures
24
Item 9B. Other Information
24
PART III
Item 10. Directors, Executive Officers and Corporate Governance
24
Item 11. Executive Compensation
24
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
24
Item 13. Certain Relationships and Related Transactions and Director Independence
25
Item 14. Principal Accountant Fees and Services
25
Item 15. Exhibits and Financial Statement Schedules
25
SIGNATURES
28
Forrest A. Garb & Associates Estimated Reserves Report
Certification by the President and CEO Pursuant to Section 302
Certification by the CFO Pursuant to Section 302
Certification by the President and CEO Pursuant to Section 906
Certification by the CFO Pursuant to Section 906



Table of Contents

Disclosures Regarding Forward-Looking Statements

Certain information included in this report, other materials filed or to be filed with the Securities and Exchange Commission (the "SEC"), as well as information included in oral statements or other written statements made or to be made by us contain or incorporate by reference certain statements (other than statements of historical fact) that constitute 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. When used herein, the words "budget," "budgeted," "assumes," "should," "goal," "anticipates," "expects," "believes," "seeks," "plans," "estimates," "intends," "projects" or "targets" and similar expressions that convey the uncertainty of future events or outcomes are intended to identify forward-looking statements. Where any forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that while we believe these assumptions or bases to be reasonable and to be made in good faith, assumed facts or bases almost always vary from actual results and the difference between assumed facts or bases and the actual results could be material, depending on the circumstances. It is important to note that our actual results could differ materially from those projected by such forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable and such forward-looking statements are based upon the best data available at the date this report is filed with the SEC, we cannot assure you that such expectations will prove correct. Factors that could cause our results to differ materially from the results discussed in such forward-looking statements include, but are not limited to, the following: the factors described in Item 1A of this report under the heading "Risk Factors," production variance from expectations, volatility of oil and gas prices, hedging results, the need to develop and replace reserves, the substantial capital expenditures required to fund operations, exploration risks, environmental risks, uncertainties about estimates of reserves, competition, litigation, government regulation, political risks, our ability to implement our business strategy, costs and results of drilling new projects, mechanical and other inherent risks associated with oil and gas production, weather, availability of drilling equipment and changes in interest rates. All such forward-looking statements in this document are expressly qualified in their entirety by the cautionary statements in this paragraph, we do not undertake, and specifically disclaim any obligation, to update or revise such statements to reflect new circumstances or unanticipated events as they occur, and we urge readers to review and consider disclosures we make in this and other reports that discuss factors germane to our business, including our reports on Forms 10-K, 10-Q, and 8-K subsequently filed from time to time with the SEC.

PART I

ITEM 1. BUSINESS

General
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 on currently owned assets, coupled with complementary acquisitions.

At year-end 2010, we owned approximately 9,000 acres of leasehold, which includes 5,000 acres of exploratory and developmental prospects as well as 4,000 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.

ReoStar was incorporated in Nevada on November 29, 2004 under the name Goldrange Resources, Inc. In February of 2007 we changed our name to ReoStar Energy Corporation.

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


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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 through 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.

Significant Accomplishments in Fiscal Year 2010

• Leasehold Acquisition and Development:

• Barnett Shale . Our main area of interest in the Barnett Shale play is located in the "oil window" of the Barnett in southwest Cooke County, Texas.

We completed, and began production in the two wells that were in process as of March 31, 2009.
• Corsicana Enhanced Oil Recovery ("EOR") Project . We entered into negotiations to test a new chemical foam technology that appears to have similar sweep efficiencies as surfactant polymer but at a reduced operational cost. We expect to deploy the technology in the wells originally drilled for our Phase II of the surfactant polymer project.
• Corsicana deeper zone exploration . We successfully drilled and completed two deeper exploratory wells in the Pecan Gap zone in the Corsicana acreage and expect to continue drilling Pecan Gap on our acreage in Corsicana.
• Corsicana technology survey . The Company is currently testing a new technology in the Corsicana field involving the detection and recording of helium atoms through sub-surface sensors that are being placed throughout our leasehold. This technology could assist the Company in its mapping of the Pecan Gap reservoir could substantially affect the results of subsequent drilling into that zone.

• Concentrate in Core Operating Areas . We currently focus in one region: the Southern Mid-continent region of the United States (which includes the Barnett Shale of North Central Texas and our Corsicana EOR prospect in East Central Texas). Concentrating our drilling and producing activities in these core areas allows us to develop the regional expertise needed to interpret specific geological and operating trends and develop economies of scale. Operating developmental projects (such as our Barnett Shale prospects) and Enhanced Oil Recovery prospects in the same core area allow us to achieve reserve growth, balance our portfolio between oil and natural gas, and minimize some of the operational risks inherent in our industry, while leveraging the benefits of the existing infrastructure.

During the fiscal year, our wholly owned subsidiary, ReoStar Operating, Inc., assumed operations in our Corsicana field.

• Manage Our Risk Exposure . We continue to sell a portion of the working interests in the development wells we drill, which allows us to spread the risk by drilling more wells for the same capital expenditure budget.

Plans for fiscal year 2011

Barnett Shale

In December 2008, we suspended our Barnett Shale development due to depressed natural gas prices. We do not expect to renew the development program during this fiscal year. However, we expect to resume the development program during the next fiscal year.


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Corsicana

We have completed our analysis of the results of Phase I of our surfactant polymer flood. We have concluded that the results of the program warrant execution of Phase II. However, during the course of our evaluation, potential new technology with similar sweep efficiencies was evaluated. Based upon the data, we believe the new technology could be employed at a substantial cost savings when compared with a surfactant polymer flood. We have entered into negotiations with the company that owns the technology and expect to begin implementation of a pilot program to test the technology in the second quarter of the fiscal year.

We are also testing a new technology in the Corsicana field involving the detection and recording of helium atoms through the drilling of one-meter holes in 300 plotted locations throughout our leasehold. The technology is owned by one of our largest shareholders and has been successful in its application in foreign oil fields. This technology is able to detect and map helium atoms in the soil, which are always present in hydrocarbon molecules. This technology could assist the Company in its mapping of the Pecan Gap reservoir in leasehold and could substantially affect the results of subsequent drilling in that zone. This Company is not being charged for the direct costs associated with the implementation of the helium technology.

Production, Revenues and Price History

The following table sets forth information regarding oil and gas production, and revenues for ReoStar Energy.

Years Ending
March 31,
2010
March 31,
2009
March 31,
2008
Production
Oil (Bbl)
23,949
45,105
33,602
Gas (Mcf)
404,131
479,180
351,538
Revenues
Crude Oil $
1,613,235
$
4,034,376
$
2,704,468
Gas
1,406,275
2,523,693
2,197,604
Total
3,019,510
6,558,069
4,902,072
Average Sale Price per Bbl
67.36
89.44
$
$80.49
Average Sale Price per MCF
3.48
5.27
$
6.25
Lease Operating Costs (per BOE)
20.13
20.79
$
23.05
Severance Taxes (per BOE)
1.71
3.00
$
3.13
Average Sale Price (per BOE)
33.07
52.48
$
53.17
Average Sale Price (per MCFE)
5.51
8.75
$
8.86

(a) Natural Gas was converted to BOE at the rate of 1 barrel equals 6 MCF.

Competition

We encounter substantial competition in developing and acquiring oil and gas properties, securing and retaining personnel, conducting drilling and field operations and marketing production. Competitors in exploration, development, acquisitions and production include the major oil companies as well as numerous independent oil companies, individual proprietors and others. Although our sizable acreage position and core-area concentration provide some competitive advantages, many competitors have financial and other resources substantially exceeding ours. Therefore, competitors may be able to pay more for desirable leases and to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources allow. Our ability to replace and expand our reserve base depends on our ability to attract and retain quality personnel and our ability to identify and acquire suitable producing properties and prospects for future drilling.


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Employees

As of April 1, 2010, ReoStar Energy Corporation and our subsidiaries had 13 full-time and 4 part-time employees.

All of ReoStar's full-time employees are eligible to receive equity awards approved by the Compensation Committee of the Board of Directors. No employees are covered by a labor union or other collective bargaining arrangement. We believe that the relationship with our employees is excellent. We regularly utilize independent consultants and contractors to perform various professional services, particularly in the areas of drilling, completion, field and on-site production operation services, mainly through our affiliated operator, Rife Energy Operating, Inc.

Available Information

We maintain an internet website under the name "www.reostarenergy.com." Information contained on or connected to our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. Our Code of Ethics is available on our website and available to any stockholder who provides a written request to Investor Relations at 3880 Hulen Street, Suite 500, Fort Worth, Texas 76107.

We file annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934. The public may read and copy any materials that we file with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers, including REOSTAR, that file electronically with the SEC. The public can obtain any document we file with the SEC at "www.sec.gov."

Marketing and Customers

We market nearly all of our oil and gas production from the properties we operate for both our interest and that of the other working interest owners and royalty owners. All of our gas produced from the Barnett Shale is sold pursuant to a gas contract with Copano Field Services/North Texas LLC. The contract expires May 31, 2017 and provides for two stages of gathering fees. For all wells in production through December 31, 2010, a gathering fee of $0.55 per MMBTU is assessed against our revenue. Thereafter, for all wells in production as of December 31, 2010, no gathering fee will be assessed. Currently, none of our gas is sold under long-term fixed price contracts. Our Barnett oil is currently sold to Parnon Gathering, Inc. under a month to month contract until such time as either party cancels by providing thirty (30) days advance written notice to the other party of intent to cancel. The contract pays Platts plus minus $1.00 based on Plains - North Texas Sweet posted price.

Oil and gas purchasers are selected on the basis of price, credit quality and service. For a summary of purchasers of our oil and gas production that accounted for 10% or more of consolidated revenue, see Note 13 to our financial statements. Because alternative purchasers of oil and gas are usually readily available, we believe that the loss of any of these purchasers would not have a material adverse effect on us.

During the fiscal year, we implemented a comprehensive commodity price hedging program. The Company entered into a swap contract for 2,000 barrels of oil per month from August through December 2009. The contract locked in the price of oil at $70.40 per barrel. The Company entered into a swap contract for 20,000 MMBTU of natural gas per month from August through December 2009. The contract locked in the price of natural gas at $4.205 per MMBTU. The Company entered into a swap contract for 20,000 MMBTU of natural gas per month from January 2010 through June 2010. The contract locks in the price of natural gas at $5.54 per MMBTU.

During the fiscal year ended March 31, 2010, the Company entered into put and call contracts, which collar 2,000 barrels of oil per month during calendar 2010. The floor is $65 per barrel and the ceiling is $85 per barrel. The Company also entered into put and call contracts which collar 20,000 MMBTU of natural gas per month from July 2010 through December 2010. The floor is $5.50 per MMBTU and the ceiling is $6.50 per MMBTU.

Proximity to local markets, availability of competitive fuels and overall supply and demand are factors affecting the prices for which our production can be sold. Market volatility due to international political developments, overall energy supply and demand, fluctuating weather conditions, economic growth rates and other factors in the United States and worldwide has had, and will continue to have, a significant effect on energy prices.


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For additional information, see "Risk Factors".

Governmental Regulation

Federal, state and local laws and regulations substantially affect our operations. In particular, oil and gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing crude oil and natural gas properties have statutory provisions regulating the exploration for and production of crude oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements in order to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individuals wells.

In August 2005, Congress enacted the Energy Policy Act of 2005 ("EPAct 2005"). Among other matters, the EPAct 2005 amends the Natural Gas Act ("NGA"), to make it unlawful for "any entity", including otherwise non-jurisdictional producers such as ReoStar, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory Commission ("FERC"), in contravention of rules prescribed by the FERC. On January 20, 2006, the FERC issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sale or gathering, but does apply to activities or otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects a significant expansion of FERC's enforcement authority. ReoStar does not anticipate it will be affected any differently than other producers of natural gas.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Congress, the states, the FERC, and the courts regularly consider additional proposals and proceedings that affect the oil and gas industry. We cannot predict when or whether any such proposals may become effective.

Environmental Matters

Our operations are subject to stringent federal, state and local laws governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental departments such as the Environmental Protection Agency ("EPA") issue regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, frontier and other protected areas, require some form of remedial action to prevent pollution from former operations such as plugging abandoned wells, and impose substantial liabilities for pollution resulting from operations. In addition, these laws, rules and regulations may restrict the rate of production. The regulatory burden on the oil and gas industry increases the cost of doing business, affecting growth and profitability. Changes in environmental laws and regulations occur frequently, and changes that result in more stringent and costly waste handling, disposal or clean-up requirements could adversely affect our operations and financial position, as well as the industry in general. We believe we are in substantial compliance with current applicable environmental laws and regulations. Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters during fiscal year ended 2010, nor do we anticipate that such expenditures will be material in fiscal year ended 2011.

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The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include owners or operators of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. Furthermore, although petroleum, including crude oil and natural gas, is not a "hazardous substance" under CERCLA, at least two courts have ruled that certain wastes associated with the production of crude oil may be classified as "hazardous substances" under CERCLA and that such wastes may therefore give rise to liability under CERCLA. Beyond CERCLA, state laws regulate the disposal of oil and gas wastes, and periodically new state legislative initiatives are proposed that could have a significant impact on us. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damages allegedly caused by the release of hazardous substances or other pollutants into the environment pursuant to environmental statutes, common law or both.

The Federal Water Pollution Control Act ("FWPCA") imposes restrictions and strict controls regarding the discharge of produced waters and other oil and gas wastes into waters of the United States. Permits must be obtained to discharge pollutants into state and federal waters. The FWPCA and analogous state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other hazardous substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. State water discharge regulations and Federal National Pollutant Discharge Elimination System permits applicable to the oil and gas industry generally prohibit the discharge of produced water, sand and some other substances into coastal waters. The cost to comply with zero discharges mandated under federal and state law has not had a material adverse impact on our financial condition and results of operations.

Some oil and gas exploration and production facilities are required to obtain permits for their storm water discharges. Costs may be incurred in connection with treatment of wastewater or developing and implementing storm water pollution prevention plans. The Resource Conservation and Recovery Act ("RCRA") as amended, generally does not regulate most wastes generated by the exploration and production of oil and gas. RCRA specifically excludes from the definition of hazardous waste "drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy." However, these wastes may be regulated by the EPA or state agencies as non-hazardous solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, can be regulated as hazardous wastes. Although the costs of managing wastes classified as hazardous waste may be significant, we do not expect to experience more burdensome costs than similarly situated companies.

The Oil Pollution Act ("OPA") requires owners and operators of facilities that could be the source of an oil spill into "waters of the United States" (a term defined to include rivers, creeks, wetlands and coastal waters) to adopt and implement plans and procedures to prevent any spill of oil into any waters of the United States. OPA also requires affected facility owners and operators to demonstrate that they have sufficient financial resources to pay for the costs of cleaning up an oil spill and compensating any parties damaged by an oil spill. Substantial civil and criminal fines and penalties can be imposed for violations of OPA and other environmental statutes.

Stricter standards in environmental legislation may be imposed on the oil and gas industry in the future. For instance, legislation has been proposed in Congress from time-to-time that would alter the RCRA exemption by reclassifying certain oil and gas exploration and production wastes as "hazardous wastes" and make the waste subject to more stringent handling, disposal and clean-up restrictions. If such legislation were enacted, it could have a significant impact on our operating costs, as well as the industry in general. Compliance with environmental requirements generally could have a material adverse effect on our capital expenditures, earnings or competitive position. Although we have not experienced any material adverse effect from compliance with environmental requirements, no assurance may be given that this will continue.

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ITEM 1A. RISK FACTORS

An investment in our common stock is speculative and involves a high degree of risk and uncertainty. You should carefully consider the risks described below, together with the other information contained in our reports filed with the SEC, including the consolidated financial statements and notes thereto of our company, before deciding to invest in our common stock. The risks described below are not the only ones facing our company. Additional risks not presently known to us or that we presently consider immaterial may also adversely affect our company. If any of the following risks occur, our business, financial condition and results of operations and the value of our common stock could be materially and adversely affected.

The Company received a qualified going concern opinion in the report from its auditors.

In their report dated June 29, 2010, the Company's auditors indicated there was substantial doubt about the Company's ability to continue as a going concern without additional fund-raising. Accordingly, unless we raise additional working capital, project financing and/or revenues grow to support our business plan we may be unable to remain in business

Volatility of oil and natural gas prices significantly affects our cash flow and capital resources and could hamper our ability to produce oil and gas economically.

Oil and natural gas prices are volatile, and a decline in prices would adversely affect our profitability and financial condition. The oil and natural gas industry is typically cyclical, and prices for oil and natural gas have been highly volatile. Historically, the industry has experienced severe downturns characterized by oversupply and/or weak demand. In recent years, higher oil and natural gas prices have contributed to increased earnings industry wide. However, long-term supply and demand for oil and natural gas is uncertain and subject to a myriad of factors such as:

• the domestic and foreign supply of oil and gas;
• the price and availability of alternative fuels;
• weather conditions;
• the level of consumer demand;
• the price of foreign imports;
• world-wide economic conditions;
• political conditions in oil and gas producing regions; and
• domestic and foreign governmental regulations.

Decreases in oil and natural gas prices from current levels could adversely affect our revenues, net income, cash flow and economically recoverable proved reserves. Significant price decreases could have a material adverse effect on our operations and limit our ability to fund capital expenditures. Without the ability to fund capital expenditures, we would be unable to replace reserves and production.

High operating costs are inherent in enhanced oil recovery projects and could impair our ability to produce oil and gas economically.

The Company has initiated a surfactant polymer flood, which is classified as an enhanced oil recovery project. The cost of the surfactants and polymers, the cost of preparing the mixture for injection, the cost of injection, the cost of monitoring the quality of the injected solution, and the cost of monitoring the results all contribute to operating expenses which are significantly higher than operating expenses incurred using primary and secondary recovery techniques. Additionally, the response time, response rate, and overall recovery rate of a surfactant polymer flood are uncertain, which could materially impact the operating cost per unit produced.

Due to the higher operating costs (which for the fiscal year ended March 31, 2008 averaged more than $30.00 per BOE), a significant decline in commodity prices could magnify the negative impact on net income, cash flow and proved reserves.


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Hedging transactions may limit our potential gains and involve other risks.

To manage our exposure to price risk, we may, from time to time, enter into hedging arrangements, utilizing commodity derivatives with respect to a significant portion of our future production. The goal of hedging is to lock in prices so as to limit volatility and increase the predictability of cash flow. These transactions may limit potential gains if oil and natural gas prices rise above the price established by the hedge. In addition, hedging transactions may cause risk of financial loss in certain circumstances.

Information concerning our reserves and future net reserve estimates is uncertain.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their values, including many factors beyond our control. Estimates of proved reserves are by their nature uncertain. Although we believe these estimates are reasonable, actual production, revenues and costs to develop will likely vary from estimates, and these variances could be material.

The accuracy of any reserve estimate is a function of the quality of available data; engineering and geological interpretation and judgment; assumptions used regarding quantities of oil and natural gas in place; recovery rates; and future commodity pricing.

Actual prices, production, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those assumed in our estimates, and such variances may be material. Any variance in the assumptions could materially affect the estimated quantity and value of the reserves.

If oil and natural gas prices decrease or exploration efforts are unsuccessful, we may be required to take write-downs of our oil and natural gas properties.

This could occur when oil and natural gas prices are low, if we have downward adjustments to our estimated proved reserves, increases in our estimates of operating or development costs, deterioration in our exploration results, unsatisfactory results in our enhanced oil recovery projects, or mechanical problems with wells where the cost to re-drill or repair does not justify the expenditures required.

Accounting rules require that the carrying value of oil and natural gas properties be periodically reviewed for possible impairment. "Impairment" is recognized when the book value of a proven property is greater than the expected undiscounted future net cash flows from that property and on acreage when conditions indicate the carrying value is not recoverable. We may be required to write down the carrying value of a property based on oil and natural gas prices at the time of the impairment review, as well as a continuing evaluation of drilling results, production data, economics and other factors. While an impairment charge reflects our long-term ability to recover an investment, it does not impact cash or cash flow from operating activities, but it does reduce our reported earnings and negatively impacts our leverage ratios.

Our business is subject to operating hazards and environmental regulations that could result in substantial losses or liabilities.

Oil and natural gas operations are subject to many risks, including well blowouts, mechanical failures, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic natural gas and other environmental hazards and risks. If any of these hazards occur, we could sustain substantial losses as a result of:

• injury or loss of life;
• severe damage to or destruction of property, natural resources, and equipment;
• pollution or other environmental damage;
• clean-up responsibilities;
• regulatory investigations and penalties; or
• suspension of operations.


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As we drill to deeper horizons and in more geologically complex areas, we could experience a greater increase in operating and financial risks due to inherent higher reservoir pressures and unknown down-hole risk exposures. As we continue to drill deeper, the number of rigs capable of drilling to such depths will be fewer and we may experience greater competition from other operators.

Our operations are subject to numerous and increasingly strict federal, state and local laws, regulations and enforcement policies relating to the environment. We may incur significant costs and liabilities in complying with existing or future environmental laws, regulations and enforcement policies and may incur costs arising out of property damage or injuries to employees and other persons. These costs may result from our current and former operations and even may be caused by previous owners of property we own or lease. Any past, present or future failure by us to completely comply with environmental laws, regulations and enforcement policies could cause us to incur substantial fines, sanctions or liabilities from cleanup costs or other damages. Incurrence of those costs or damages could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses.

In accordance with our operating agreements, the operator maintains insurance against some, but not all, of these potential risks and losses. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. We do not maintain business interruption insurance.

In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs that is not fully covered by insurance, it could have a material adverse affect on our financial condition and results of operations.

We are subject to financing and interest rate exposure risks.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, which limit our ability to pursue acquisition opportunities and place us at a competitive disadvantage.

Many of our current and potential competitors have greater resources than ours, and we may not be able to successfully compete in acquiring, exploring and developing new properties.

We face competition in every aspect of our business, including, but not limited to, acquiring reserves and leases, obtaining goods, services and employees needed to operate and manage our business and marketing oil and natural gas. Competitors include multinational oil companies, independent production companies and individual producers and operators. Many of our competitors have greater financial and other resources than we do.

The demand for field services and their ability to meet that demand may limit our ability to drill and produce our oil and natural gas properties.

Due to current industry demands, well service providers and related equipment and personnel are in short supply. This will result in escalating prices, the possibility of poor services coupled with potential damage to down-hole reservoirs and personnel injuries. Such pressures will likely increase the actual cost of services, extend the time to secure such services and add costs for damages due to accidents sustained from the over use of equipment and inexperienced personnel.

The oil and natural gas industry is subject to extensive regulation.

The oil and natural gas industry is subject to various types of regulations in the United States by local, state and federal agencies. Legislation affecting the industry is under constant review for amendment or expansion, frequently increasing our regulatory burden. Numerous departments and agencies, both state and federal, are authorized by statute to issue rules and regulations binding on participants in the oil and natural gas industry. Compliance with such rules and regulations often increases our cost of doing business and, in turn, decreases our profitability.


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Acquisitions are subject to the risks and uncertainties of evaluating reserves and potential liabilities and may be disruptive and difficult to integrate into our business.

We could be subject to significant liabilities related to acquisitions. It generally is not feasible to review in detail every individual property included in an acquisition. Ordinarily, a review is focused on higher valued properties. However, even a detailed review of all properties and records may not reveal existing or potential problems in all of the properties, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not always inspect every well we acquire, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is performed.

In addition, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our acquisition strategy is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue our acquisition strategy may be hindered if we are not able to obtain financing on terms acceptable to regulatory approvals or us.

Acquisitions often pose integration risks and difficulties. In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Future acquisitions could result in our incurring additional debt, contingent liabilities, expenses and diversion of resources, all of which could have a material adverse effect on our financial condition and operating results.

Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.

Our success is highly dependent on our management personnel. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel is intense. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected.

Our future success depends on our ability to replace reserves that we produce.

Because the rate of production from oil and natural gas properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional oil and natural gas reserves. Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline as reserves are produced. Future oil and natural gas production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot assure you that we will be able to find or acquire and develop additional reserves at an acceptable cost.

New technologies may cause our current exploration and drilling methods to become obsolete.

The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are not able to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected.


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Our business depends on oil and natural gas transportation facilities, most of which are owned by others.

The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties. The unavailability of or lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. We generally do not purchase firm transportation on third party facilities and therefore, our production transportation can be interrupted by those having firm arrangements.

Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

The disruption of third-party facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. We have no control over when or if such facilities are restored or what prices will be charged. A total shut-in of production could materially affect us due to a lack of cash flow, and if a substantial portion of the production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flow.

Indebtedness could limit our ability to successfully operate our business.

If we decide to pursue additional acquisitions, our capital expenditures will increase both to complete such acquisitions and to explore and develop any newly acquired properties. Our existing operations will also require ongoing capital expenditures. We may choose to increase debt in order to finance any of these potential capital expenditure requirements. The degree to which we are leveraged could have other important consequences, including the following:

• we may be required to dedicate a substantial portion of our cash flows from operations to the payment of our indebtedness, reducing the funds available for our operations;
• a portion of our borrowings are at variable rates of interest, making us vulnerable to increases in interest rates;
• we may be more highly leveraged than some of our competitors, which could place us at a competitive disadvantage;
• our degree of leverage may make us more vulnerable to a downturn in our business or the general economy;
• the terms of our credit arrangements could contain numerous financial and other restrictive covenants;
• our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
• we may have difficulties borrowing money in the future.

Any failure to meet our debt obligations could harm our business, financial condition and results of operations.

If our cash flow and capital resources are insufficient to fund our current or future debt obligations, we may be forced to sell assets, seek additional equity or restructure our debt. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and impair our liquidity.

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The current global financial crisis may adversely affect our business, operating results and financial condition.

The global financial markets are in turmoil, and the economies of the United States and many other countries have recently been in recession, which may be severe and prolonged and have been characterized by high unemployment, limited availability of credit and capital, increased rates of default and bankruptcy and decreased consumer and business spending. These developments could negatively affect our business, operating results and financial condition in a number of ways. For example, this recession has had an unprecedented negative impact on the global credit and capital markets, resulting in financing terms that are less attractive to borrowers, and in many cases, the unavailability of certain types of debt or capital financing. If this crisis continues or worsens, and if we are required to obtain financing in the near term to meet our working capital or other business needs, we may not be able obtain that financing. Further, even if we are able to obtain the financing we need, it may be on terms that are not favorable to us, with increased financing costs and restrictive covenants.

We exist in a litigious environment.

Any constituent could bring suit or allege a violation of an existing contract. This action could delay when operations can actually commence or could cause a halt to production until the courts resolve such alleged violations. Not only could we incur significant legal and support expenses in defending our rights, planned operations could be delayed which would impact our future operations and financial condition. Such legal disputes could also distract management and other personnel from their primary responsibilities.

Common stockholders will be diluted if additional shares are issued.

We may incur debt that provides for a conversion to equity. Additionally, we may issue stock as consideration for additional property acquisitions. If we issue additional shares of our common stock in the future, it may have a dilutive effect on our current outstanding stockholders.

Dividend limitations.

Our ability to pay dividends may be limited by covenants imposed under future debt arrangements.

Our financial statements are complex.

Due to accounting rules, our financial statements continue to be complex, particularly with reference to hedging, asset retirement obligations, equity awards, and deferred taxes. We expect such complexity to continue and possibly increase.

Our stock price may be volatile and you may not be able to resell shares of our common stock at or above the price you paid.

The price of our common stock fluctuates significantly, which may result in losses for investors. To date our stock has been lightly traded, with the average daily volume being quite low. The low trading volume may prevent you from liquidating your position in our stock quickly. Additionally, the low trading volume may contribute significantly to price volatility. We expect our stock to be subject to fluctuations as a result of a variety of factors, including factors beyond our control. These include:

• changes in oil and natural gas prices;
• variations in quarterly drilling, re-completions, acquisitions and operating results;
• changes in financial estimates by securities analysts;
• changes in market valuations of comparable companies;
• additions or departures of key personnel; or
• future sales of our stock.


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We may fail to meet expectations of our stockholders or of securities analysts at some time in the future, and our stock price could decline as a result. Furthermore, the ability to access capital has been somewhat impaired due to the financial downturn, which could impact the Company's ability to do the same.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable

ITEM 2. PROPERTIES

The information below summarizes certain data for our core operating areas for the year ended March 31, 2010. Segment reporting is not applicable to us as we have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. 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.

We conduct drilling, production and field operations in the Barnett Shale of North Central Texas, and the Corsicana field of East Central Texas.

Barnett Shale

The Barnett Shale is a non-conventional natural gas resource play located in North Texas. It underlies approximately 5,000 square miles and at least 17 counties. Our leases lie in the north western portion of the Barnett Shale, an area known as the "oil window," due to its production of both oil and gas.

We have drilled and own interests in 71 completed wells, all of which are operated by Rife Energy Operating, Inc., a non-publicly traded affiliated company owned by a shareholder who controls more than 25% of our outstanding stock. Our average working interest is 47%, and our average net revenue interest is 36%. We have approximately 5,215 acres under lease, the majority of which is not classified as proven. During the fiscal year ended March 31, 2010, our Barnett Shale production consisted of 404,131 MCF of natural gas and 23,949 barrels of oil, or approximately 91,300 BOE (547,825 MCFE).

Proved developed producing reserves consisted of 1,920 MMCF of natural gas and 58 M barrels of oil, or, 378 MBOE (2,267 MMCFE). Proved developed non-producing reserves consisted of 33 MMCF of natural gas and 8 M barrels of oil, or, 13 MBOE (81 MMCFE). Total proved developed reserves at March 31, 2010 were 392 MBOE (2,348 MMCFE). Total proven, undeveloped reserves consisted of 16,820 MMCF natural gas and 643 M barrels of oil, or, 3,446 MBOE (20,680 MMCFE).

At March 31, 2010, we had a Barnett Shale drilling inventory of 50 proven drilling locations and more than 100 probable drilling locations.

Corsicana Field

We own interests in 77 producing well bores and 199 inactive wells. During the fiscal year, we transitioned operation of all of our properties in Corsicana from a non-publicly traded affiliate to a ReoStar Operating, Inc. Our average working interest is 95%, and our average net revenue interest is 76%. During the fiscal year ended March 31, 2010, our oil production in the Corsicana field totaled 10,300 barrels of oil.

The Nacatoch reservoir is fairly shallow with depths of less than 1,000 feet. While this field has been producing for more than one hundred years, several engineering studies have estimated that more than 80% of the original reserves still remain in place or approximately 100 MMBO.

We are evaluating optional EOR techniques including the use of chemicals (micellar flood), steam, and fire floods.

There are many alternative reservoirs between 1000 and 7000 feet, which are being evaluated for optimal exploitation. The company feels that there are tremendous opportunities in the multiple zones within this range and it plans on attempting to produce from each one.


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During the fiscal year ended March 31, 2010, the Company drilled three Pecan Gap test wells. Two of the wells were successfully completed. The Company has identified 7 additional proven undeveloped drilling locations in the Pecan Gap formation and plans to beginning drilling these wells in the fourth quarter of the fiscal year. If these wells are successful, the Company expects to begin an extensive drilling program, and may drill up to 200 more Pecan Gap wells. The Pecan Gap formation lies at about 1,800 feet, and the wells cost approximately $130,000 to drill and complete. The Company has secured co-financing for these wells from an industry partners who have purchased working interests in the first three wells and expects to sell up to 50% of any additional Pecan Gap wells we drill.

We are also testing a new technology in the Corsicana field involving the detection and recording of helium atoms through the drilling of one-meter holes in 300 plotted locations throughout our leasehold. The technology is owned by one of our largest shareholders and has been successful in its application in foreign oil fields. This technology is able to detect and map helium atoms in the soil, which are always present in hydrocarbon molecules. This technology could assist the Company in its mapping of the Pecan Gap reservoir in leasehold and could substantially affect the results of subsequent drilling in that zone. This Company is not being charged for the direct costs associated with the implementation of the helium technology.

As of March 31, 2010, total proved developed reserves were 32 MBOE and proved undeveloped reserves totaled 40 MBOE.

East Texas Properties

During the fiscal year ended March 31, 2010, the Company divested of its East Texas assets.

Proven Reserves

Proven oil and gas reserves are defined as the estimated quantities 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, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

See financial statement footnote number 17, "Supplemental Info on Oil and Gas Exploration, Development, and Production Activities" for the disclosures required by FASB ASC 932 and more detailed information regarding our proven reserves.

At year-end 2010, the independent petroleum-consulting firm of Forrest Garb and Associates, Inc. reviewed our reserves. These engineers were selected for their geographic expertise and their history in engineering enhanced oil recovery prospects similar to our Corsicana properties. At March 31, 2010, these consultants reviewed 100% of our proved reserves.

All estimates of oil and gas reserves are subject to uncertainty. The following table sets forth the estimated proven reserves in barrel of oil equivalents and the benchmark prices used in projecting them (in thousands except prices):

Estimated Proved Reserves
Barnett
Shale
Corsicana
Field
Total
Proved Developed (MBOE)
392
32
424
Proved Undeveloped (MBOE)
3,446
40
3,486
Total Proven Reserves at March 31, 2010
3,838
72
3,910
Benchmark Pricing
Natural Gas per mmbtu
$3.99
Crude Oil per barrel
$70.03

There are numerous uncertainties inherent in estimating reserves and related information and different reservoir engineers often arrive at different estimates for the same properties. No estimates of our reserves have been filed with or included in reports to another federal authority or agency.


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Wells are classified as crude oil or natural gas according to their predominant production stream.

The day-to-day operations of oil and gas properties are the responsibility of the operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs or contracts for field personnel and performs other functions. An operator receives reimbursement for direct expenses incurred in the performance of its duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged by unaffiliated third parties. The charges customarily vary with the depth and location of the well being operated. The operator of our Barnett Shale properties is affiliated with ReoStar and is owned by shareholders who own more than 25% of our issued and outstanding common stock.

Undeveloped Acreage Expirations

A significant amount of our Barnett Shale acreage is not yet held by production. However, due to our planned drilling schedules and lease renewal provisions, we do not anticipate significant leasehold expirations during the next two years.

Our Corsicana properties are held by production.

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, often minimal investigation of record title is made at the time of lease acquisition. Investigations are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include:

• customary royalty interests;
• liens incident to operating agreements and for current taxes;
• obligations or duties under applicable laws;
• development obligations under oil and gas leases; or
• burdens such as net profit interests.

Our headquarters are located at 3880 Hulen St, Suite 500, Fort Worth, Texas. We lease approximately 12,000 square feet of office space under a lease and sublease approximately one- half of the space to our affiliated operating entity, which contributes to the costs of leasing and maintenance of the leasehold, pro-rata to their respective usage. The lease expires on January 31, 2011. We pay rent at a rate of $1.26 per square foot, per month. Our administrative and office facilities are suitable for their respective uses.

ITEM 3. LEGAL PROCEEDINGS

On September 15, 2008, a royalty owner in the Corsicana polymer pilot, representing approximately one-third of the mineral ownership, filed an amendment to a suit originally filed in 2007. The amendment was filed to include the Company as a defendant. The suit, filed in the 13th Judicial District Court in Navarro County, Texas, alleges the lease has expired because no oil was produced from January 2005 through September 2005. The plaintiff has asked the court to declare the lease to be void; demands payment for any oil produced and sold subsequent to the time the lease expired; demands that all equipment and salvage located on the lease be given by court order to the plaintiff; and asks that any plugging liability be adjudged to be the responsibility of the Company.

The other royalty owners representing the remaining two-thirds mineral ownership have ratified the lease.


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In October 2008, the court issued an order requiring the Company and plaintiff to attend mediation to settle the matter. The Company and plaintiff attended mediation in Corsicana, Texas, but were unable to resolve the matter during mediation. In March, the plaintiff filed a motion for summary judgment, which the court has denied. The Company is evaluating which actions are the most appropriate for the Company to take in respect of this matter, and we intend to continue to defend this matter vigorously or otherwise resolve this matter in a manner that we believe will not have a material adverse effect on our business, financial condition and results of operations.

If the plaintiff should prevail in the lawsuit, the amount of the loss contingency cannot be reasonable estimated; therefore no expense for this contingency has been recorded on the accompanying financial statements.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to a vote of our security holders during the fourth quarter of 2010.

PART II

ITEM 5. MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our common stock is currently quoted for trading on Over-the-Counter Bulletin Board (OTCBB) maintained by the Financial Industry Regulatory Authority (FINRA) under the symbol "REOS". There was no active market or any trading volume with respect to the shares of our common stock in the periods prior to the quarter ended December 31, 2006.

The following table sets forth the high and low closing sale price of our common stock, as reported by the National Association of Securities Dealers Composite for each quarter during the past two fiscal years.

Fiscal 2009 High Low
30-Jun-09 $0.51 $0.06
30-Sep-09 $0.50 $0.10
31-Dec-09 $0.49 $0.11
31-Mar-10 $0.39 $0.08
Fiscal 2009 High Low
30-Jun-08 $0.95 $0.20
30-Sep-08 $0.74 $0.20
31-Dec-08 $0.50 $0.10
31-Mar-09 $0.30 $0.05

Holders of Record

On March 31, 2010, there were approximately 90 holders of record of our common stock.

Dividends

We have not paid any cash dividends on our Common Stock, and do not anticipate paying cash dividends on our Common Stock in the next year. We anticipate that any income generated in the foreseeable future will be retained for the development and expansion of our business. Future dividend policy is subject to the discretion of the Board of Directors and will depend upon a number of factors, including future earnings, debt service, debt covenants, capital requirements, business conditions, the financial condition of the Company and other factors that the Board of Directors may deem relevant.


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ITEM 6. SELECTED FINANCIAL DATA

Not applicable.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 annual report on 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.


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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 fiscal year ended March 31, 2009 we completed refurbishment of a shallow well oil drilling rig which will be used to drill our Corsicana Nacatoch and Pecan Gap wells.


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• 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 FASB ASC 718, amortization of restricted stock grants as part of employee compensation.

• Interest. We increased our levels of debt during fiscal year 2010, 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, 2010, we completed the two wells that were awaiting completion at the beginning of the fiscal year. ReoStar retained a 60% working interest in these wells at a total net investment of $955,000.

Corsicana Project: We completed injection of surfactant polymer in phase I of the polymer project and conducted an evaluation as to the effectiveness of the flood. We concluded that the flood was a scientific success and that further flooding was warranted. However, during the course of the evaluation, we were introduced to a different chemical flood technology that we believe will provide similar sweep efficiencies at a lower operating cost. We have begun negotiations to implement the technology in the wells that were originally drilled for Phase II of the polymer flood. We expect to initiate a pilot flood in the second quarter of the 2011 fiscal year.


19

Table of Contents

We drilled one unsuccessful Pecan Gap exploratory well in Corsicana. We sold 75% working interests in the well 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. We drilled two successful Pecan Gap wells in the Corsicana area at a total net investment of $72,612. We retained a 25% working interest in these wells.

The average sales price per barrel of oil during the fiscal year was $67.36 compared with $89.44 for the fiscal year ended March 31, 2009. The average price realized per thousand cubic feet (MCF) of gas produced during the fiscal year was $3.48 compared with $5.27 compared with for the fiscal year ended March 31, 2009

Oil and gas production for the year decreased 27% to a total of 91,304 BOE compared with 124,968 BOE for the fiscal year ended March 31, 2009. Oil and gas revenue for the year decreased 54% to a total of $3.0 million compared to $6.5 million for the fiscal year ended March 31, 2009. We had a net loss of $3.1 million compared to a net loss of $2.0 million for the prior fiscal year.

During fiscal year ended March 31, 2010, our cash used in operations was $455,000 and we used $700,000 in investing activities. Financing activities provided net cash of $1.0 million.

On March 31, 2010, we had $277,000 in cash and total assets of $21.3 million. Debt consisted of payables to non-related parties of $10.8 million, which were all classified as current due to the technical defaults under the senior secured credit facility. See Note 5 in the footnotes for more information. 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.

In their report dated June 29, 2010, the Company's auditors indicated there was substantial doubt about the Company's ability to continue as a going concern without adequate fund-raising. Accordingly, unless we raise additional working capital, project financing and/or revenues grow to support our business plan, we may be unable to remain in business.

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.


20

Table of Contents

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 2011 capital program is expected to be funded with the proceeds of the senior secured credit facility, internal cash flow, and debt or equity financing from investors.

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. For fiscal year 2010, the $2.0 million capital expended was funded by proceeds from the senior secured credit facility and working capital.

Our capital expenditure budget for fiscal year 2011 is $1.5 million. Of this, $1 million is budgeted for Barnett Shale and $0.5 million is budgeted for the Corsicana micellar flood pilot. Our capital expenditure budget will be partially funded from 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, 2010, 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, 2010. In addition to the contractual obligations listed on the table below, our balance sheet at March 31, 2010 reflects accrued interest payable on our debt of $88,500 which is payable throughout the rest of 2010.

Fiscal year ended March 31
In thousands
2011
2012
2013
Thereafter
Office Lease $
149,270
$
-
$
-
$
-
Senior Credit Facility
10,800,000
-
-
-
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.


21

Table of Contents

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.


22

Table of Contents

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 year-end 2010, deferred tax liabilities exceeded deferred tax assets by $639,000. 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 must often 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 contingencies and make our best estimate of when to record losses for these matters based on available information. Although we continue to monitor all contingencies closely, particularly our outstanding litigation, we currently have no material accruals for contingent liabilities.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.


23

Table of Contents

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS


Page
Report of Independent Registered Public Accounting Firm F-2
Consolidated Balance Sheet, March 31, 2010 F-3
Consolidated Statements of Operations, Years Ended March 31, 2009 and 2010 F-4
Consolidated Statements of Stockholders' Equity, Years Ended March 31, 2000 and 2010 F-5
Conolidated Statements of Cash Flows, Years Ended March 31, 2009 and 2010 F-6
Notes to Financial Statements F-8


F-1

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the Board of Directors and Stockholders
ReoStar Energy Corporation
Fort Worth, Texas 76107


We have audited the accompanying consolidated balance sheets of ReoStar Energy Corporation as of March 31, 2010 and 2009, and the related consolidated statements of operations, stockholders' equity, and cash flows for the years then ended. ReoStar Energy Corporation's management is responsible for these consolidated financial statements. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of ReoStar Energy Corporation as of March 31, 2010 and 2009, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has a working capital deficit of $9,195,946 due to default on loan covenants and borrowing base requirements of their lender. These conditions raise substantial doubt about the Company's ability to continue as a going concern. Management's plans regarding this matter are described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.



/s/ Killman, Murrell & Company, P.C.
Killman, Murrell & Company, P.C.
Odessa, Texas
June 29, 2010

F-2

Table of Contents

ReoStar Energy Corporation
Consolidated Balance Sheets

March 31, 2010
March 31, 2009
ASSETS
Current Assets:
Cash $
277,307
$
426,430
Accounts Receivable:
Oil and Gas - Related Party
639,738
337,879
Related Party
561,169
1,107,854
Other
-
15,760
Inventory
130,886
7,514
Other Current Assets
248,759
6,317
Total Current Assets
1,857,859
1,901,754
Notes Receivable
213,619
553,536
Oil and Gas Properties - successful efforts method
26,847,329
25,254,777
Less Accumulated Depletion and Depreciation
(9,034,348
)
(6,206,558
)
Oil and Gas Properties (net)
17,812,981
19,048,219
Other Depreciable Assets:
2,028,487
2,171,654
Less Accumulated Depreciation
(427,013
)
(315,093
)
Other Depreciable Assets (net)
1,601,474
1,856,561
Leasehold Held for Sale
-
150,000
Total Assets $
21,485,933
$
23,510,070
LIABILITIES
Current Liabilities:
Accounts Payable $
278,233
$
22,033
Revenue Payable
20,912
-
Payable to Related Parties
148,550
148,550
Other Current Liabilities
93,923
-
Accrued Expenses
140,390
106,141
Accrued Expenses - Related Parties
88,458
130,870
Current Portion of Long-Term Debt
10,283,339
-
Total Current Liabilities
11,053,805
407,594
Notes Payable
-
8,955,202
Notes Payable - Related Parties
3,518,924
3,518,924
Total Long-Term Debt
3,518,924
12,474,126
Asset Retirment Obligation
324,773
344,079
Deferred Tax Liability
639,034
1,702,782
Total Liabilities
15,536,536
14,928,581
Commitments & Contingencies:
-
-
Stockholders' Equity
Common Stock, $.001 par,200,000,000 shares authorized and
80,743,912 and 80,353,912 shares outstanding on
March 31, 2010 and 2009, respectively
80,743
80,353
Additional Paid-In-Capital
11,460,893
10,959,965
Treasury Stock, at cost
(12,240
)
-
Retained Deficit
(5,579,999
)
(2,458,829
)
Total Stockholders' Equity
5,949,397
8,581,489
Total Liabilities & Stockholders' Equity $
21,485,933
$
23,510,070

See Accompanying Notes to Consolidated Financial Statements
F-3

Table of Contents

ReoStar Energy Corporation
Consolidated Statements of Operations

Years Ended
Mar. 31, 2010
Mar. 31, 2009
Revenues
Oil and Gas Sales $
3,019,510
$
6,558,069
Sale of Leases
170,174
18,005
Other Income
344,038
458,365
3,533,722
7,034,439
Costs and Expenses
Oil and Gas Lease Operating Expenses
1,840,151
2,598,208
Workover Expenses
90,736
114,683
Severance and Ad Valorem Taxes
233,367
427,307
Delay Rentals
5,000
2,975
Plugging Costs and Expired Leases
43,594
433,976
Depletion and Depreciation
3,589,316
3,487,440
ARO Accretion
40,567
-
General and Administrative:
Salaries and Benefits
840,782
874,418
Legal and Professional
732,047
720,771
Other General and Administrative
495,967
701,687
Interest, net of capitalized interest of $555,575 and
$537,024 for the years ended March 31, 2010 and
March 31, 2009, respectively
-
3,780
7,911,527
9,365,245
Other Income (Expense)
Interest Income
18,445
79,876
Hedging Gains (Losses)
174,442
(6,745
)
Loss on Equity Method Investments
-
(206,561
)
Loss from operations before income taxes
(4,184,918
)
(2,464,236
)
Income Tax Benefit
1,063,748
460,402
Net Loss $
(3,121,170
) $
(2,003,834
)
Basic and Diluted Loss per Common Share:
Net Loss per Common Share $
(0.04
) $
(0.02
)
Weighted Average Common Shares Outstanding
80,593,912
80,300,804

See Accompanying Notes to Consolidated Financial Statements
F-4

Table of Contents

ReoStar Energy Corporation
Consolidated Statements of Stockholders' Equity
Years Ended March 31, 2009 and 2010

Common Stock
Number of
Shares
Amount
Paid-In
Capital
Treasury
Stock
Retained
Deficit
Total
Balance, March 31, 2008
80,181,310
$
80,181
$
9,553,346
$
-
$
(454,995
) $
9,178,532
Common Stock Issued for
Penalty Shares
172,602
172
172,430
-
-
172,602
Warrants Issued for short-term
note payable
-
-
36,967
-
-
36,967
Warrants Issued in connection
with consulting contract
-
-
300,000
-
-
300,000
Warrants Issued for success
fee related to senior secured
credit facility
-
-
375,000
-
375,000
Employee and director
stock options granted
-
-
522,222
-
-
522,222
Net Loss 2009
-
-
-
-
(2,003,834
)
(2,003,834
)
Balance, March 31, 2009
80,353,912
80,353
10,959,965
-
(2,458,829
)
8,581,489
Common Stock Issued with
consulting contracts
390,000
390
175,110
-
-
175,500
Treasury Stock
-
-
-
(12,240
)
-
(12,240
)
Employee and director stock
options granted
-
-
325,818
-
-
325,818
Net Loss 2009
-
-
-
-
(3,121,170
)
(3,121,170
)
Balance, March 31, 2009
80,743,912
$
80,743
$
11,460,893
$
(12,240
) $
(5,579,999
) $
5,949,397

See Accompanying Notes to Consolidated Financial Statements
F-5

Table of Contents

ReoStar Energy Corporation
Consolidated Statements of Cash Flows

Fiscal Year Ended
Operating Activities:
Mar. 31, 2010
Mar. 31, 2009
Net Loss $
(3,121,170
) $
(2,003,834
)
Adjustments to reconcile net loss to net cash from operating activities:
Deferred Income Tax Benefit
(1,063,748
)
(460,402
)
Depletion, Depreciation, & Amortization
3,589,316
3,487,440
Expired Leases
43,594
433,976
Non-employee stock based compensation
175,500
300,000
Stock based compensation
325,818
307,240
Penalty shares
-
172,602
Loss on Equity Method Investment
-
206,561
ARO Accretion
40,567
-
ARO on Sold Properties
(87,516
)
-
Treasury Stock Received for Asset Sale Proceeds
(12,240
)
-
Changes in Operating Assets and Liabilities
Changes in Accrued Liabilities
(8,163
)
(685,671
)
Change in Inventory
(123,372
)
(2,766
)
Change in Related Party Receivables/Payables
(56,143
)
(1,369,752
)
Changes in Other Receivables
15,760
(15,760
)
Changes in Other Current Assets
-
6,745
Changes in Hedging Activity
(148,519
)
-
Change in Revenue Receivables
(301,859
)
530,527
Change in Revenue Payable
20,912
-
Changes in Accounts Payable
256,200
(81,446
)
Net Cash provided (used) from operating activities
(455,063
)
825,460
Investing Activities:
Oil & Gas Drilling, Completing and Leasehold Acquisition Costs
(2,024,820
)
(8,706,952
)
Change in Related Party Payable related to drilling
602,828
(1,547,136
)
Net Investment in Leasehold Sold
350,690
-
Investment in Other Depreciable Assets
(184,633
)
(534,287
)
Net Investment in Other Depreciable Assets Sold
221,957
-
Investment in Equity Method Investment
-
(64,166
)
Note Receivable (Advances)
(213,619
)
-
Note Receivable Collections
553,537
801,692
Net Cash used in continuing activities
(694,060
)
(10,050,849
)
Financing Activities:
Notes Payable Advances Net of Loan Fees
1,000,000
10,401,254
Notes Payable Principal Payments
-
(1,342,100
)
Related Party Note (Payments)
(200,000
)
-
Related Party Note Advances
200,000
-
Net Cash provided by continuing activities
1,000,000
9,059,154
Net Decrease in cash
(149,123
)
(166,235
)
Cash - Beginning of the year
426,430
592,665
Cash - End of the year $
277,307
$
426,430

See Accompanying Notes to Consolidated Financial Statements
F-6

Table of Contents
ReoStar Energy Corporation
Consolidated Statements of Cash Flows
(Continued)

Year Ended
Mar. 31, 2010
Mar. 31, 2009
Supplemental Disclosure of Cash Flow Information
Cash paid during period for:
Interest $
621,107
$
466,792
Income Taxes $
-
$
-
Non Cash Investing and Financing Activities
Treasury Stock Received for Asset Sale $
(12,240
) $
-
Stock Based Loan Costs $
-
$
375,000
Stock Issued for Interest $
-
$
36,967
Stock Based Compensation $
325,818
$
522,222
Stock Based Consulting Fees $
175,500
$
300,000


See Accompanying Notes to Consolidated Financial Statements
F-7

Table of Contents

REOSTAR ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2010 AND 2009

(1) SUMMARY OF ORGANIZATION AND NATURE OF BUSINESS

REOSTAR ENERGY CORPORATION ("REOSTAR ," "we," "us," or "our") is engaged in the exploration, development and acquisition of oil and gas properties primarily in Texas. We seek to increase our reserves and production primarily through drilling, complementary acquisitions, and the development of enhanced oil recovery prospects.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation
The financial statements and notes are representations of the Company's management who are responsible for their integrity and objectivity. The Company's accounting policies conform to accounting principles generally accepted in the United States of America and have been consistently applied in the preparation of these consolidated financial statements.

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, ReoStar Operating, Inc., ReoStar Leasing, Inc. and ReoStar Gathering, Inc. Intercompany accounts and transactions have been eliminated in consolidation.

Going Concern
The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America with the assumption that the Company will be able to realize its assets and discharge its liabilities in the normal course of business. The Company has a working capital deficit of $9,195,946. This working capital deficit was precipitated because the Company could not meet its covenant or borrowing base requirements of their lender due in part to a reduction in their borrowing base. Therefore the note payable to Union Bank of California was classified as current. A complete discussion regarding the transactions leading to the default is more fully discussed in Note 5. The Company's ability to continue as a going concern is further contemplated upon its ability to complete certain capital generating activities in the future. Management's plan in this regard is to secure additional funds through equity financing activities. These conditions raise substantial doubt about the Company's ability to continue as a going concern. The financial statements do not include any adjustments to the amounts and classifications of assets and liabilities that might be necessary should the Company be unable to continue as a going concern.

Use of Estimates
The preparation of financial statements in accordance with generally accepted accounting principles ("GAAP") in the United States 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. Actual results could differ from the estimates and assumptions used.

Income per Common Share
Basic net income per share is calculated based on the weighted average number of common shares outstanding. Diluted net income per share assumes issuance of stock compensation awards and exercise of stock warrants, provided the effect is not anti-dilutive.

Revenue Recognition
Oil, gas, and natural gas liquids revenues are recognized when the products are sold and delivery to the purchaser has occurred. Although receivables are concentrated in the oil and gas industry, we do not view this as unusual credit risk.


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Cash and Equivalents
Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less.

Allowance for Doubtful Accounts
We regularly review our accounts receivable for quality of accounts receivable. Other than related party receivables, we accrue a provision for doubtful accounts equal to 20% of any accounts receivable balance that has aged more than one hundred twenty (120) days. As of March 31, 2010, we had no accounts receivable balances over the 120 day threshold, therefore, no allowance for doubtful accounts has been accrued.

Inventory
Inventory consists of tubing, rods, casing, and storage tanks and is stated at the lower of cost (first-in, first-out) or market value.

Oil and Gas Properties
Oil and gas investments are accounted for by the successful efforts method of accounting. Accordingly, the costs incurred to acquire property (proved and unproved), all development costs, and successful exploratory costs are capitalized, whereas the costs of unsuccessful exploratory wells are expensed.

Oil and gas properties consisted of the following at March 31, 2010 and 2009:

2010
2009
Producing Leasehold $
23,999,312
$
22,159,295
Non-Producing Leasehold
1,063,346
1,081,482
Well in Process
229,476
1,014,380
Capitalized Interest
1,555,195
999,620
26,847,329
25,254,777
Less accumulated depletion and amortization
(9,034,348
)
(6,206,558
)
$
17,812,981
$
19,048,219
Depletion of capitalized oil and gas well costs is provided using the units of production method based on estimated proved developed oil and gas reserves of the respective oil and gas properties. Cost, net of estimated salvage value, is recovered on each property via depletion.

The carrying value of capitalized oil and gas property costs is compared annually to the future net revenues attributed to the related proved developed oil and gas reserves. If such costs exceed the future net revenues of the related proved oil and gas reserves, an impairment provision is recorded.

Our policy is to minimize risks associated with drilling exploratory wells by selling most of the working interest associated with each particular well on a turn-key basis (up to 80% of the working interest may be sold). The proceeds are credited to the net book value of the property. In the event the proceeds from selling the working interest exceed the total cost of acquiring the leasehold and drilling the well, we record the net proceeds in excess of cost as gain on the sale of oil and gas properties.

Gain or loss is recognized from the sale of any interest of proven developed properties.


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Depletion
Our proven oil and gas properties are depleted using a field level cost center. A field is defined as an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas of interest, etc. A reservoir is defined as a porous and permeable underground formation containing a natural accumulation of producible oil or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

If all the oil and gas properties in a field-wide cost center are proven properties, then all of the leasehold costs will be aggregated and depleted on a units-of-production basis over the total proved reserves of the field. If the cost center contains some properties that are proved and some properties that are unproved, only the proved property leasehold costs are aggregated and depleted. The total capitalized costs for wells and equipment is also aggregated and depleted on a units-of-production basis over the total proved developed reserves of the field.

Other Depreciable Assets
Other depreciable assets consisted of the following at March 31, 2010 and 2009:

2010
2009
Buildings $
409,764
$
409,764
Office Equipment
130,256
130,256
Property and Equipment
1,488,467
1,631,634
2,028,487
2,171,654
Less accumulated depreciation
(427,013
)
(315,093
)
$
1,601,474
$
1,856,561
Depreciation
The workover, service, and swab rigs are depreciated using the straight-line method over the estimated useful life of 10 years. Computer equipment is depreciated using the straight-line method over the estimated useful life of 3 years. All other equipment is depreciated using the straight-line method over 5 years.

Interest Expense
ReoStar capitalizes interest expense related to the financing obtained to acquire and develop oil and gas properties. Capitalized interest associated with oil and gas properties is recovered via depletion, using the overall depletion rate on producing properties.

Deferred Taxes
Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors include our expectation to generate sufficient taxable income including tax credits and operating loss carryforwards.

Stock-based Compensation
The Company accounts for its stock options and warrants in accordance FASB ASC 718, "Compensation - Stock Compensation". In accordance with FASB ASC 718, the Company recognizes stock-based compensation expense based on the fair value of the stock options (or warrants) on the date of grant. The fair value of the stock options (or warrants) at the date of grant is amortized over the vesting period, with the offsetting credit to additional paid in capital. If the stock options are exercised, the proceeds are credited to share capital. Likewise, if the stock warrants are exercised, the proceeds are credited to share capital.

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Comprehensive Income
FASB ASC 220, "Comprehensive Income," establishes standards for reporting and financial statement presentation of comprehensive income, its components and accumulated balances. Comprehensive income is defined to include all changes in equity except those resulting from investments by owners and distributions to owners. Among other disclosures, FASB ASC 220 requires that all items that are required to be recognized under current accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements. The Company does not have comprehensive income items requiring disclosure of comprehensive income.

Impairment of Long-Lived Assets
In accordance with FASB ASC 360, "Property, Plant and Equipment", long lived assets, such as oil and gas properties and equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount of the fair value less costs to sell and are no longer depreciated. The assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet.

Contingencies
Certain conditions may exist as of the date the financial statements are issued, which may result in a loss to the Company, but which will only be resolved when one or more future events occur or fail to occur. The Company's management and legal counsel assess such contingent liabilities, and such assessment inherently involves an exercise of judgment. In assessing loss contingencies related to legal proceedings that are pending against the Company, or unasserted claims that may result in such proceedings, the Company's legal counsel evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of the liability can be estimated, the estimated liability is accrued in the Company's financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed.

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees are disclosed.

Financial Instruments
The carrying amount of financial instruments including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value, unless otherwise stated, as of March 31, 2010. The carrying amount of long-term debt approximates market value due to the use of market interest rates.

Fair value estimates of financial instruments are made at the period end based on relevant information about financial markets and specific financial instruments. As these estimates are subjective in nature, involving uncertainties and matters of significant judgment, they cannot be determined with precision. Changes in assumptions can significantly affect estimated fair value.


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Asset Retirement Obligation
Our financial statements reflect the fair value for asset retirement obligation, which consist of estimated future plugging and abandonment expenditures related to our oil and gas properties, to the extent they can be reasonably estimated. The asset retirement obligation is recorded as a liability at its estimated present value at the asset's inception, with an offsetting increase to producing properties on the consolidated balance sheet. Periodic accretion of the discount of the estimated liability is recorded as an expense in the consolidated statements of operations.

Recent Accounting Pronouncements
The FASB established the FASB Accounting Standards Codification ("Codification") as the source of authoritative U.S. generally accepted accounting principles ("GAAP") recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements issued for interim and annual periods ending after September 15, 2009. The codification has changed the manner in which U.S. GAAP guidance is referenced, but did not have an impact on our consolidated financial position, results of operations or cash flows.

In January 2010, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2010-06, "Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements." This ASU requires some new disclosures and clarifies some existing disclosure requirements about fair value measurement as set forth in Accounting Standards Codification ("ASC") 820. ASU 2010-06 amends ASC 820 to now require: (1) a reporting entity should disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers; and (2) in the reconciliation for fair value measurements using significant unobservable inputs, a reporting entity should present separately information about purchases, sales, issuances, and settlements. In addition, ASU 2010-06 clarifies the requirements of existing disclosures. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Early application is permitted. The Company will comply with the additional disclosures required by this guidance upon its adoption in January 2010.

Also in January 2010, the FASB issued Accounting Standards Update No. 2010-03, "Extractive Activities-Oil and Gas-Oil and Gas Reserve Estimation and Disclosures." This ASU amends the "Extractive Industries-Oil and Gas" Topic of the Codification to align the oil and gas reserve estimation and disclosure requirements in this Topic with the SEC's Release No. 33-8995, "Modernization of Oil and Gas Reporting Requirements (Final Rule)," discussed below. The amendments are effective for annual reporting periods ending on or after December 31, 2009, and the adoption of these provisions on December 31, 2009 did not have a material impact on our consolidated financial statements.

On December 31, 2008, the Securities and Exchange Commission (SEC) issued Release No. 33-8995, "Modernization of Oil and Gas Reporting Requirements (Final Rule)," which adopted major revisions to its rules governing oil and gas company reporting requirements. These include provisions that permit the use of new technologies to determine proved reserves, and allow companies to disclose their probable and possible reserves to investors. Previously, the rules limited disclosure to only proved reserves. The new disclosure requirements also require companies to report the independence and qualifications of the person primarily responsible for the preparation or audit of reserve estimates, and to file reports when a third party is relied upon to prepare or audit reserves estimates. The new rules also require that oil and gas reserves be reported and the full-cost ceiling value calculated using an average price based upon the prior 12-month period. The new oil and gas reporting requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, with early adoption not permitted.

In August 2009, the FASB issued ASU No. 2009-05, "Fair Value Measurements and Disclosures (Topic 820) - Measuring Liabilities at Fair Value," related to fair value measurement of liabilities. This update provides clarification that in circumstances in which a quoted price in an active market for an identical liability is not available, a reporting entity is required to measure fair value using one or more valuation techniques. This guidance is effective for the first reporting period beginning after issuance.


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In June 2009, the FASB issued guidance under ASC 105, "Generally Accepted Accounting Principles." This guidance established a new hierarchy of GAAP sources for non-governmental entities under the FASB Accounting Standards Codification. The Codification is the sole source for authoritative U.S. GAAP and supersedes all accounting standards in U.S. GAAP, except for those issued by the SEC. The guidance was effective for financial statements issued for reporting periods ending after September 15, 2009. The adoption had no impact on the Company's financial position, cash flows or results of operations.

In May 2009, the FASB issued guidance under ASC 855 "Subsequent Events," which sets forth: (1) the period after the balance sheet date during which management of reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (2) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements and (3) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. The guidance was effective on a prospective basis for interim or annual financial periods ending after June 15, 2009.

In April 2009, the FASB updated its guidance under ASC 820, "Fair Value Measurements and Disclosures," related to estimating fair value when the volume and level of activity for an asset or liability have significantly decreased and identifying circumstances that indicate a transaction is not orderly. The guidance was effective for interim and annual reporting periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009. The adoption of this guidance did not have any impact on the Company's results of operations.

Also in April 2009, the FASB updated its guidance under ASC 825, "Financial Instruments," which requires disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This guidance also requires those disclosures in summarized financial information at interim reporting periods. The guidance was effective for interim reporting periods ending after June 15, 2009 with early adoption permitted for periods ending after March 15, 2009.

The FASB updated its guidance under ASC 805, "Business Combinations," in April 2009, which addresses application issues on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. This guidance was effective for business combinations occurring on or after the beginning of the first annual period on or after December 15, 2008.

In June 2008, the FASB updated its guidance under ASC 260, "Earnings Per Share." This guidance clarified that all unvested share-based payment awards with a right to receive nonforfeitable dividends are participating securities and provides guidance on how to allocate earnings to participating securities and compute basic earnings per share using the two-class method. This guidance was effective for fiscal years beginning after December 15, 2008. The Company adopted this guidance on January 1, 2009. The adoption did not have a material impact on the Company's earnings per share calculations.

In March 2008, the FASB issued guidance under ASC 815, "Derivatives and Hedging," which changes the disclosure requirements for derivative instruments and hedging activities. Entities will be required to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for, and how derivative instruments and related items affect an entity's financial position, operations and cash flows. This guidance was effective as of the beginning of an entity's fiscal year that begins after November 15, 2008. The Company adopted this guidance on January 1, 2009.

(3) DEFERRED TAX LIABILITY
Our income tax benefit from operations was $1,063,748 and $460,402 for the years ended March 31, 2010 and 2009, respectively. A reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows:

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March 31,
2010
March 31,
2009
Federal Statutory Tax Rate
35%
35%
State
0%
0%
Consolidated Effective Tax Rate
35%
35%
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax provisions. Our income tax expense (benefit) is as follows:


Years Ended March 31,
2010
2009
Current income tax expense
Federal $
-
$
-
State
-
-
Total current tax expense
-
-
Deferred income tax (benefit) from continuing operations
Federal
(1,063,748
)
(460,402
)
State
-
-
Total income tax benefit $
(1,063,748
) $
(460,402
)
The income tax provision differs from the amount computed at the statutory rate of 35% as follows:

Years Ended March 31,
2010
2009
Rate
35%
35%
Tax on Income from Continuing Operations at Statutory Rate $
(1,464,721
) $
(862,483
)
Increase (decrease) resulting from:
Permanent differences
400,973
402,081
Income Tax Provision $
(1,063,748
) $
(460,402
)


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Significant components of deferred tax assets and liabilities are as follows:

March 31,
2010
March 31,
2009
Deferred Tax Assets:
Net Operating Loss Carryforward $
1,950,405
$
751,045
Other Deferred Tax Assets
146,544
-
Total Deferred Tax Assets
2,096,949
751,045
Deferred Tax Liabilities
Oil and Gas Properties Basis
2,475,875
2,086,984
Other Deferred Tax Liabilities
260,108
366,843
Total Deferred Liabilites
2,735,983
2,453,827
Net Deferred Tax Liability $
639,034
$
1,702,782
At March 31, 2010 and 2009, we had net operating loss carryforwards for tax purposes of approximately $5.6 million and $2.2 million, of which, approximately $3.4 million and $2.2 million expire on March 31, 2030 and 2029, respectively.

(4) EARNINGS PER COMMON SHARE

The average stock price for both years was less than the strike price of the outstanding stock warrants and stock options. Therefore, there were no dilutive common stock equivalents as of March 31, 2010 and 2009. The following table sets forth the computation of basic earnings per common share.

March 31,
2010
March 31,
2009
Numerator
Net Income (Loss) $
(3,121,170
) $
(2,003,834
)
Denominator
Weighted Average Shares Outstanding - Basic
80,593,912
80,300,804
Basic - Net Income $
(0.04
) $
(0.02
)

(5) INDEBTEDNESS

The following debt was outstanding as of March 31, 2010 and March 31, 2009, respectively:

Lease Notes Payable. The Company had three lease bank obligations related to the acquisition of certain leasehold in the Fayetteville Shale play. All three obligations were non-recourse in nature and required repayment of the principal as the acquired leasehold was drilled or when the underlying leasehold was sold. The Company fully impaired the underlying acreage during the year ended March 31, 2009 (see Note 9 for more information). Since the obligations are non-recourse in nature, the Company has written off the related lease bank obligations as of March 31, 2009.

Senior Secured Credit Facility. As of March 31, 2010 and 2009, respectively, the Company had outstanding principal of $10,800,000 and $9,800,000 on the note. The Company incurred costs associated with the note (including legal fees and investment banking fees) of approximately $1 million. The loan fees are amortized over the life of the note, and amortization for the years ended March 31, 2010 and 2009 was approximately $325 thousand and $190 thousand, respectively. The carrying value of the note is reduced by the loan costs net of amortization, leaving a carrying balance of approximately $10,283,000 and $8,955,000, respectively. At March 31, 2010 the interest rate was 5.75%.

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On October 30, 2008, we entered into a $25 million senior secured credit facility with lenders led by Union Bank, N.A. ("UB"), as administrative agent and as issuing lender. Pursuant to the terms of the senior credit facility, the initial borrowing base was set at $14 million and is subject to re-determination every six months with one optional re-determination allowed between scheduled re-determinations. During the fiscal year ended March 31, 2010, the borrowing base was adjusted downward to $7.6 million leaving an over-advance of $3.2 million. The Company lacks the liquidity to repay the over-advance.

The credit facility is secured by all of the Company's assets and is senior to all other long-term debt. The outstanding principal is due October 30, 2011. However, if, pursuant to the terms of the senior credit facility, specific evens of default occur, the due date of all outstanding principal and accrued interest may be accelerated. Specific events of default include, but are not limited to: payment defaults; breaches of representations and warranties, and covenants; insolvency; a "change of control" in our ownership as described in the senior credit agreement; and a "material adverse change" as described in the senior credit agreement.

The senior credit facility requires us to comply with certain credit metrics, such as the maintenance of minimum working capital, certain ratios of debt to EBITDA (as defined in the senior credit facility), maintenance of a minimum EBITDA to interest, and places a cap on Capital Expenditures each year. Each metric is further defined below.

Working capital, defined as consolidated current assets less consolidated current liabilities is required to be at least $1.5 million as of the last day of each fiscal quarter. Current assets includes the unused amount available under the senior credit facility. We were not in compliance with the working capital requirement as of March 31, 2010.

The leverage ratio is as follows: (a) for each fiscal quarter, the ratio of (i) Funded Debt (as defined in the senior credit facility) to (ii) consolidated EBITDA for the four fiscal quarter periods then ended must not be greater than 3.50 to 1.00. For the purposes of calculating the leverage ratio, the definition of "Funded Debt" does not include Notes Payable to Shareholders that has been subordinated to the senior credit facility. EBITDA is defined as Consolidated Net Income adjusted plus, to the extent deducted in determining net income, interest expense, income taxes, depletion, depreciation, amortization, and other non-cash charges for the period. We were not in compliance with the leverage ratio as of March 31, 2010.

The interest coverage ratio is the ratio of our consolidated EBITDA for the four fiscal quarter periods then ended to our consolidated Interest Expense for the four fiscal quarters then ended must be at least 3.00 to 1.00. We were not in compliance with the interest coverage ratio as of March 31, 2010.

In February, Union Bank formally notified the Company of non-compliance under the above covenants and the over-advance resulting from the revision of the borrowing base. See the Form 8-K filed on February 17, 2010.

The senior credit agreement imposes certain restrictions on us and our subsidiaries, subject to specific exceptions, including, but not limited to, the following: (i) incurring additional liens; (ii) incurring additional debt; (iii) merging or consolidating or selling, transferring, assigning, farming-out, conveying or otherwise disposing of any property; (iv) making certain payments, including cash dividends to our stockholders; (v) making any loans, advances or capital contributions to, or making any investment in, or purchasing or committing to purchase any stock or other securities or interests in any person or any oil and natural gas properties or activities related to oil and natural gas properties unless with regard to new oil and natural gas properties, such properties are mortgaged to UB, as administrative agent, or with regard to new subsidiaries, such subsidiaries execute a guaranty, pledge agreement, security agreement and mortgage in favor of UB, as administrative agent; and (vi) entering into affiliate transactions on terms that are not at least as favorable to us as comparable arm's length transactions.


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Notes Payable to Related Parties. ReoStar has a note payable to ReoStar's President and CEO. The note was renewed in October 2008 and matures on April 1, 2012. The note bears interest of 8%. The principal balance of the note on March 31, 2010 and 2009 was $324,330 and $324,330, respectively. The note is subordinated to the Senior Secured Credit Facility.

ReoStar has a note payable to a limited partnership owned by the Chairman of the Board. The note was renewed in October 2008 and matures on April 1, 2012. The note provides for an interest rate of 5.95%. The principal balance at March 31, 2010 and 2009 was $3,194,594 and $3,194,594, respectively. The note is subordinated to the Senior Secured Credit Facility.

The following table summarizes our note payable repayment obligations.

Fiscal Years Ending March 31,
2011
2012
2013
2014
Thereafter
Total
Note Payable - Shareholder
-
-
324,330
-
-
324,330
Note Payable - Shareholder
-
-
3,194,594
-
-
3,194,594
Senior Secured Credit Facility
10,800,000
-
-
-
-
10,800,000
$
10,800,000
$
-
$
3,518,924
$
-
$
-
$
14,318,924
Payables to Related Party. ReoStar contracts with the operators of its oil and gas properties to drill and complete all new wells. The operators are affiliated entities owned by a ReoStar shareholder who owns more than 20% of ReoStar stock. The outstanding payable to the operators as of March 31, 2010 and 2009 was $0 and $148,550, respectively.

Accrued Expenses. Accrued expenses consist of accrued interest expense totaling $0 and $23,030, royalty payable totaling $101,395 and $68,406, and severance and sales taxes payable totaling $38,995 and $14,705 at March 31, 2010 and 2009, respectively.

Accrued interest payable to related parties aggregated of $88,458 and $130,870 on March 31, 2010 and 2009, respectively.

(6) CAPITAL STOCK
We have authorized capital stock of 200 million shares of common stock. The following is a schedule of changes in the number of outstanding common shares since March 31, 2008.
Shares Outstanding
Shares Outstanding March 31, 2008
80,181,310
Shares issued as penalty for late registration of private placement shares
172,602
Balance at March 31, 2009
80,353,912
Shares issued as compensation to consultants
390,000
Balance at March 31, 2010
80,743,912
During the fiscal years ended March 31, 2007 and 2008, the Company issued shares via a private placement offering. The private placement subscription agreement provided for additional penalty shares to be issued in the event the stock was not registered with the Securities Exchange Commission within 90 days of subscription. During the fiscal year ended March 31, 2009, the company issued 172,602 penalty shares because the registration was not completed within the specified time period for some, but not all, of the private placement subscriptions. The penalty stock was valued at $1.00 per share based upon the bid price on the relevant date and an expense of $172,602 was recorded for the year ended March 31, 2009.


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The private placement subscription agreement also provided for the issuance of 1 warrant for each share of stock issued. The warrants had a strike price of $1.50 per share and expired in two years. In total, the Company issued 11,462,000 warrants in conjunction with the private placement offering in 2007. Of these, 6,605,000 warrants were scheduled to expire by March 31, 2009. The remaining 4,757,000 warrants were scheduled to expire in the quarter ending June 30, 2009. In April 2009, the Company extended the expiration date for all of the warrants to June 16, 2009. All of the warrants have since expired.

There were stock option grants issued to members of ReoStar's Board of Directors of 100,000 shares during the year ended March 31, 2008. The stock options were valued at $69,856 using the Black-Scholes model with a volatility of 183.59% and a strike price of $1.11. Of the stock options, one-third vested on March 31, 2008 at an expense of $39,376, one-third vested on March 31, 2009 at an expense of $21,251, and the balance vested on March 31, 2010 at an expense of $9,229.

At March 31, 2008, there were 350,000 shares of unvested restricted stock granted to two of the Company's officers outstanding. In July 2008, the Board approved an employee stock option plan that provides for stock options up to 8,000,000 shares. The Board canceled the restricted stock grants and replaced them with stock options. Stock options were issued to three of the Company's officers totaling 2,500,000 shares. The options were granted on July 25, 2008 and were valued at $873,348 using the Black-Scholes model with a volatility of 194.44% and a strike price of $0.35 per share. Of the stock options, one-third vested on March 31, 2009, one-third vested on March 31, 2010, and the balance will vest on March 31, 2011. During the fiscal year ended March 31, 2010, one of the officers resigned. In lieu of severance, the officer and the company agreed that the balance of the unvested options would vest immediately. Amounts expensed were $316,589 and $480,338 for the years ended March 31, 2010 and 2009, respectively.

Salaries and Benefits expense included stock based compensation expense of $325,818 and $307,240 for the years ended March 31, 2010 and 2009, respectively.

During the fiscal year ended March 31, 2009, the Company issued 1,250,000 warrants to purchase 1 share of stock to our investment banking firm as part of the success fee in closing the Union Bank of California senior secured credit facility. The warrants were issued October 31, 2008 when the Company's stock price was $0.30 per share. The warrants have a strike price of $0.50 per share and are scheduled to expire October 31, 2012. Using the Black-Scholes model, the warrants were valued at $375,000.

The Company issued 100,000 warrants to purchase 1 share of stock to a private lender in lieu of interest during the fiscal year ended March 31, 2009. The warrants were issued on June 11, 2008 and expire on June 30, 2012. The stock was trading at $0.50 at the time of issue and the strike price is also $0.50 per share. Using the Black-Scholes model, the warrants were valued at $36,967.

The Company issued 1,000,000 warrants to a consultant during the fiscal year ended March 31, 2009. The warrants were issued effective January 1, 2009 and are scheduled to expire December 31, 2019. The strike price of $0.30 per share is equal to the market price on the date of issue. Using the Black-Scholes model, the warrants were valued at $300,000.

The Company issued 390,000 shares of stock to various consultants during the fiscal year ended March 31, 2010. The stock was valued $175,500 - the average price on the date the stock was issued. An expense of $175,500 was included in Legal and Professional expenses during the year.

(7) TREASURY STOCK
In February 2010, the Company acquired 102,000 shares of its common stock in conjunction with the sale of two oil and gas leases at a cost of $12,240. The Company accounts for treasury stock using the cost method and includes treasury stock as a component of stockholder's equity.


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(8) FAIR VALUE ESTIMATES
In September 2006, the FASB issued FASB ASC 820, "Fair Value Measurements and Disclosures". The objective of FASB ASC 820 is to increase consistency and comparability in fair value measurements and to expand disclosures about fair value measurements. FASB ASC 820 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. FASB ASC 820 applies under other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements.

The Company measures its derivative instruments in accordance with FASB Codification Topic 820-10. Topic 820-10 specifies a valuation hierarchy based on whether the inputs to those valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect the Company's own assumptions. These two types of inputs have created the following fair value hierarchy:

• Level 1 - Quoted prices for identical instruments in active markets;
• Level 2 - Quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets; and
• Level 3 - Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable.

Type of Contract
Balance Sheet Location
Estimated
Fair Value
Natural Gas Swaps Other Current Assets $
98,856
Natural Gas Collars Other Current Assets
143,587
Total Current Derivative Assets
242,443
Crude Oil Swaps Other Current Liabilities
-
Crude Oil Collars Other Current Liabilities
(93,923
)
Total Current Derivative Liabilities
(93,923
)
Crude Oil Collars Other Non-Current Liabilities
-
Natural Gas Collars Other Non-Current Liabilities
-
Total Non-Current Derivative Liabilities
-
Total Net Derivative Assets $
148,520
This hierarchy requires the Company to minimize the use of unobservable inputs and to use observable market data, if available, when estimating fair value. The fair value of the options and warrants and derivative assets and liabilities at March 31, 2010 was as follows:

Fair Value Measurements at Reporting Date Using
Quoted
Prices in
Active
Markets for
Identical
Assets
Significant
Other
Observable
Inputs
Significant
Unobservable
Inputs
(Level 1)
(Level 2)
(Level 3)
Total
Options $
-
$
325,818
$
-
$
325,818
Derivative Assets and Liabilities, net $
148,520
$
-
$
-
$
148,520


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The fair value of the options and warrants and long-lived assets held for sale at March 31, 2009 was as follows:

Fair Value Measurements at Reporting Date Using
Quoted
Prices in
Active
Markets for
Identical
Assets
Significant
Other
Observable
Inputs
Significant
Unobservable
Inputs
(Level 1)
(Level 2)
(Level 3)
Total
Options and Warrants $
-
$
1,234,189
$
-
$
1,234,189
Long-lived Assets Held For Sale $
-
$
150,000
$
-
$
150,000

Options and warrants were valued using the Black-Scholes model.

Certain east Texas leases were valued using an agreed upon sales price in connection with the pending sale of the leases.

(9) ASSET RETIRMENT OBLIGATION

The asset retirement obligation ("ARO") represents the estimated present value of the amount we will incur to plug and abandon our producing properties at the end of their productive lives, in accordance with applicable state laws.

We recorded the initial ARO during the fiscal year ended March 31, 2009. We calculated the present value of the ARO by applying an annual inflation factor of 3% to the current cost to plug and abandon our producing properties in order to estimate the future cost to plug and abandon the properties. We discounted the future costs to present values using a discount rate of 12.5% (the credit adjusted risk free rate). The carrying cost of the property was increased by the present value of the ARO and a liability was recorded. At March 31, 2010 and 2009, our liability for ARO was approximately $325,000 and $344,000, respectively, all of which was classified as non-current. Our asset retirement obligations are recorded as current or non-current liabilities based on the estimated timing of the related cash flows.

(10) ABANDONED LEASEHOLD

In 2005, The Company's predecessors acquired certain non-producing leasehold in the Fayetteville Shale. The leases had 5 year terms and will begin to expire during the fiscal year ending March 31, 2011. During the year ended March 31, 2008, the Company's management concluded that the acreage no longer fit with the rest of the Company's portfolio of oil and gas properties and decided to offer the acreage for sale. The Company received some initial indications of interest in the property, however, mid-way through the fiscal year, natural gas prices declined substantially. As of March 31, 2009, we had not received any offers on the property, and based upon the continuing low natural gas price and relatively short remaining term of the leases, management concluded that an impairment should be recorded and that the appropriate fair value of the leases was zero. Therefore, the Fayetteville acreage was fully impaired.


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The acreage was acquired with non-recourse financing. The financing agreements provide for repayment of the money loaned to acquire the property only as the property was drilled or out of the proceeds of a sale. Since we no longer plan to drill the property and there appears to be no market for the leasehold, the full amount of the liabilities related to the acquisition of the Fayetteville acreage and all accrued interest was offset against the cost.

For the year ended March 31, 2009, a net abandonment loss of $424,000 was recorded related to the impairment of the Fayetteville Shale leasehold.

(11) COMMITMENTS AND CONTINGENCIES

Office Lease
We signed a six-month extension to the long-term sublease in January 2010. The lease provides for base rent of $14,927 monthly. The lease is scheduled to expire in July 2010. The minimum base rent until the lease expires on July 31, 2010 is $59,708.

Plugging
Some of the Corsicana oil and gas leases have been producing for more than one hundred years and there are approximately one hundred abandoned wells scattered throughout the leases. In order for tertiary recovery efforts to be successful, we will need to cement in the old wells. Since the wells are relatively shallow, we are able to completely plug each well for less than $1,500. We consider these plugging costs to be costs of developing the field. Successful efforts accounting requires that such development costs be capitalized, consequently, the plugging costs are capitalized as part of the project. Because these costs are related to the planned tertiary recovery project, rather than a retirement of an asset, management has not included the cost of plugging these old well bores in the asset retirement obligation. No contingency has been recorded as management believes the plugging costs to be immaterial

(12) NOTE RECEIVABLE
ReoStar had a note receivable from our drilling contractor. The note is secured by the rig that was dedicated to our Barnett Shale acreage. During the year, the outstanding note principal was paid in full. The outstanding principal balance on March 31, 2010 and 2009 was $0 and $553,536, respectively.

During fiscal year 2010, the Company sold two oil and gas leases in east Texas. The purchase and sales agreement provides for monthly production payments equal to 10% of the gross revenue attributable to the working interests sold commencing with May 2010 production. The production payments will continue until a total of $165,000 has been collected by the Company. The Company estimates the present value of the production payments to be $112,991 using a discount rate of 10%. A note receivable in that amount was recorded.

During fiscal year 2010, the Company sold the balance of the east Texas assets. The purchase and sales agreement provides for consideration consisting of $10,000 cash, 102,000 shares of the Company's stock, and a promissory note. The promissory note provides for monthly production payments equal to 50% of the net proceeds attributable to production from two oil and gas leases and $50 per hour of billable rig work completed in each 30 day period. The first payment is due in May 2010 and production payments will continue until a total of $112,500 is collected. The Company estimated the present value of the payments to be $100,628 using a discount rate of 10%. A note receivable in that amount was recorded.

(13) MAJOR CUSTOMERS
We market our production on a competitive basis. Gas produced in the Barnett is sold under a long-term contract scheduled to expire on May 31, 2017. Oil purchasers may be changed on 30 days notice. The price for oil is generally equal to a posted price set by major purchasers in the area or is based on NYMEX pricing, adjusted for quality and transportation. We sell to oil and gas purchasers on the basis of price, credit quality and service. For the years ended March 31, 2010 and 2009, three customers, Parnon Gathering, Inc; Copano Field Services, North Texas LLC; and Plains Marketing L.P. accounted for nearly 100% of total oil and gas sales. Since our products are commodities and since there are numerous purchasers that service our markets, we believe that the loss of any one customer would not have a material adverse effect on our results.

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(14) CREDIT RISK
We frequently maintain a balance in our bank accounts in excess of the federally insured limits.

(15) DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT
The Company does not engage in speculative derivative activities or derivative trading activities, nor does it use derivatives with leverage features. The Company uses derivative instruments from time to time to manage market risks resulting from the fluctuations in the prices of crude oil and natural gas. The gains and losses resulting from changes in the fair value of derivatives are recorded in operations. See Note 8 for the fair values of the derivatives as of March 31, 2010.

The Company may periodically enter into derivative contracts, including price swaps and costless collars utilizing put and call options, which require payments to (or receipts from) counterparties based upon the differential between a fixed price and a variable price for a fixed quantity of crude oil or natural gas without delivering the physical product. The notional amount of the financial instruments is based upon production forecasts from existing wells.

During the fiscal year ended March 31, 2010, the Company entered into a swap contract for 2,000 barrels of oil per month from August through December 2009. The contract locked in the price of oil at $70.40 per barrel. The Company entered into a swap contract for 20,000 MMBTU of natural gas per month from August through December 2009. The contract locked in the price of natural gas at $4.205 per MMBTU. The Company entered into a swap contract for 20,000 MMBTU of natural gas per month from January 2010 through June 2010. The contract locks in the price of natural gas at $5.54 per MMBTU.

During the fiscal year ended March 31, 2010, the Company entered into put and call contracts which collar 2,000 barrels of oil per month during calendar 2010. The floor is $65 per barrel and the ceiling is $85 per barrel. The Company also entered into put and call contracts which collar 20,000 MMBTU of natural gas per month from July 2010 through December 2010. The floor is $5.50 per MMBTU and the ceiling is $6.50 per MMBTU.

There were no net premiums paid or received when the Company entered into these contracts.

The following table reflects open commodity derivative hedging contracts as of March 31, 2010, the associated volumes, and the corresponding reference price.

Settlement Period
Monthly
Volumes
Fixed Price
Price
Floor
Price
Ceiling
Natural Gas Swaps
1/01/10 - 6/30/10
20,000
MMBTU $
5.54
N/A
N/A
Crude Oil Collars
1/01/10 - 12/31/10
2,000
BBLS
N/A
$
65.00
$
85.00
Natural Gas Collars
7/1/10 - 12/31/10
20,000
MMBTU
N/A
$
5.50
$
6.50


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(16) SUBSEQUENT EVENTS
In May 2009, the FASB issued FASB ASC 855, "Subsequent Events". ASC 855 establishes general standards of accounting for and disclosure of events after the balance sheet date but before financial statements are issued or are available to be issued. The adoption in the fourth quarter of 2009 did not have any material impact on the Company's financial statements. Accordingly, the Company evaluated subsequent events through June 29, 2010, the date the financial statements were issued.

(17) SUPPLEMENTAL INFO ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED).
The following information concerning our natural gas and oil operations has been provided pursuant to FASB ASC 932, "Extractive Industries - Oil and Gas". All of our natural gas and oil producing activities are located in Texas.

Capitalized Costs Relating to Oil and Gas Producing Activities
Fiscal Year Ended March 31,
2010
2009
Unproved oil and gas properties $
564,804
$
484,198
Proved oil and gas properties
24,727,330
23,770,959
Support Equipment and facilities
-
-
Capitalized Interest
1,555,195
999,620
Total Capitalized Cost of Oil and Gas Properties
26,847,329
25,254,777
Less accumulated depletion, depreciation, and amortization
(9,034,348
)
(6,206,558
)
Net Capitalized Costs $
17,812,981
$
19,048,219
Costs incurred in Oil and Gas Producing Activities

Fiscal Year Ended March 31,
2010
2009
Property Acquisition Costs
Proved $
422,963
$
427,676
Unproved
91,810
15,472
Exploration Costs
235,003
267,212
Development Costs
719,470
7,393,929
Asset retirement costs recognized
27,643
344,079
Total Costs Incurred $
1,496,889
$
8,448,368

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Results of Operations for Producing Activities:

The following reflects results of operations for the fiscal years ended March 31, 2010 and 2009:

Fiscal Year Ended March 31,
2010
2009
Oil & Gas Revenue $
3,019,510
$
6,558,069
Gain on Sale of Oil & Gas Leases
170,174
18,005
Production Costs
2,164,254
3,140,198
Exploration Costs
5,000
2,975
Expired Leases and Plugging Costs
43,594
433,969
Depreciation, Depletion, & Amortization
2,765,126
2,968,429
(1,788,290
)
30,503
Income Taxes at 35%
625,902
(10,676
)
Results of operations for oil and gas producing
activities (excluding corporate overhead and
financing costs) 		$
(1,162,389
) $
19,827
Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)

We engaged Forrest A. Garb & Associates, Inc. to conduct a reserve study and to estimate our reserves of crude oil, condensate, natural gas liquids and natural gas. Reserves are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgmental decisions are required to estimate reserves. Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors.

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 those proved reserves which can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered as a result of additional investments for drilling new wells to offset productive units, recompleting existing wells, and/or installing facilities to collect and transport production.

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, when 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.

Production quantities shown are net volumes sold. These may differ from volumes withdrawn from reservoirs due to inventory changes, and, especially in the case of natural gas, volumes consumed for fuel and/or shrinkage from extraction of natural gas liquids.

The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future net cash flows because prices, costs and governmental policies do not remain static, appropriate discount rates may vary, and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts.

The March 31, 2010 report utilizes the preceding 12-month average on the first trading day of the month spot price posted for West Texas Intermediate crude oil and Henry Hub natural gas in accordance with updated SEC guidelines. The March 31, 2010 oil price was $70.03 per barrel ("Bbl") and has been adjusted by lease for gravity, transportation fees, and regional price differentials. The March 31, 2010 natural gas price per thousand cubic feet (MCF) was based on a benchmark price of $3.99 per


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Table of Contents

million British thermal units ("MMBtu") and has been adjusted by lease for Btu content, transportation fees and regional price differentials. The March 31, 2009 report utilizes the base crude oil and natural gas prices in effect at March 31, 2009 in accordance with the SEC guidelines then in effect. For the reserves at March 31, 2009, the base crude oil and natural gas prices were $49.65 per Bb and $3.58 per MMbtu, respectively. The base prices for both crude oil and natural gas are adjusted by the normal price differential between the prices we historically have received for our products and the spot price quoted on the relevant market exchange.

Our proved reserves (000's omitted) are summarized in the table below.

Oil
(MBBL)
Gas
(MMCF)
Reserves at March 31, 2008
1,411
18,809
Revisions of previous estimates
(739
)
(11,269
)
Improved recovery
-
-
Purchases of minerals in place
1
25
Extensions and discoveries
397
4,725
Production
(45
)
(479
)
Sales of minerals in place
-
-
Reserves at March 31, 2009
1,025
11,811
Revisions of previous estimates
(650
)
(3,735
)
Improved recovery
-
-
Purchases of minerals in place
-
-
Extensions and discoveries
442
11,101
Production
(24
)
(404
)
Sales of minerals in place
(12
)
-
Reserves at March 31, 2010
781
18,773
Revisions of previous estimates: The table above identifies downward revisions in both oil and gas reserves for the year ended March 31, 2009. The downward revision is primarily a function of price. The base oil price at March 31, 2009 was more than 51% lower than the base price included in the previous reserve report. The table above identifies downward revisions in both oil and gas reserves for the year ended March 31, 2010. The downward revision is primarily related to corrections to the projected decline curves of our Barnett Shale properties.

Purchases of minerals in place: The Company has continued its working interest repurchase program in its Barnett Shale properties. Throughout both years, the company repurchased small working interests in several wells.

Extensions and discoveries: The Company successfully drilled 8 of the Barnett shale locations that were classified as proven undeveloped properties for the years ending March 31, 2009. The successful drilling of the wells resulted in additional proven undeveloped reserves in offset locations. During the year ended March 31, 2010, multiple successful wells were drilled in leasehold acreage offsetting our Barnett Shale acreage. Based upon these successful wells and our drilling history, an additional 33 proven undeveloped drilling locations were identified. All wells classified as proven undeveloped are expected to be drilled within 5 years of our fiscal year end.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

The following summarizes the policies we used in the preparation of the accompanying natural gas and oil reserve disclosures, standardized measures of discounted future net cash flows from proved natural gas and oil reserves and the reconciliations of standardized measures from year to year. The information disclosed, as prescribed by FASB ASC 932, is an attempt to present the information in a manner comparable with industry peers.

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The information is based on estimates of proved reserves attributable to our interest in natural gas and oil properties as of April 1, 2010. These estimates were prepared by an independent petroleum engineering firm, Forest Garb and Associates, Inc. Proved reserves are estimated quantities of natural gas and crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:
• Estimates are made of quantities of proved reserves and future amounts expected to be produced based on current year-end economic conditions.
• Estimated future cash inflows are calculated by applying the benchmark prices of natural gas and oil relating to our proved reserves to the quantities of those reserves produced in each future year. For the March 31, 2010 reserve report, SEC guidelines required the benchmark price for both oil and gas to be based upon the preceding 12-month average of the first trading-day of the month spot price on the most relevant exchange. For the March 31, 2009, SEC guidelines required the benchmark price for both oil and gas to be the closing price on the last trading-day of the fiscal year.
• Future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on current year-end economic conditions.
• The resulting future net cash flows are discounted to present value by applying a discount rate of 10%.

The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of our natural gas and oil reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in the industry.

The standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves as of March 31, 2010 and 2009 is as follows:

As of March 31,
In Thousands
2010
2009
Future Cash Inflows $
127,486
$
90,391
Future Production and Development Costs
(89,762
)
(55,865
)
Income Taxes
(13,204
)
(12,084
)
Future Net Cash Flows
24,520
22,442
10% Annual Discount
(17,359
)
(12,120
)
Standardized Measure of Discounted Future Net Cash Flow $
7,161
$
10,322

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The following reconciles the change in the standardized measure of discounted future net cash flow during the fiscal years ended March 31, 2010 and 2009:

Year Ended March 31,
In Thousands
2010
2009
Balance at beginning of yea $
10,322
$
68,301
Net change in prices and production costs
11,145
(194,933
)
Net changes in future development costs
(20,306
)
6,807
Sales of oil & gas produced net of production costs
(452
)
(3,533
)
Extensions and discoveries
20,698
23,664
Previously estimated development costs incurred
532
8,243
Revisions of previous quantity estimates
(8,419
)
(10,020
)
Purchases of reserves
-
427
Net change in income taxes
(1,120
)
59,271
Accretion of discount
(5,239
)
52,095
End of Year $
7,161
$
10,322






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ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A(T). CONTROLS AND PROCEDURES

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined in 13a-15(e) of the Securities Exchange Act of 1934, or the Exchange Act). Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures are effective.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, our management concluded that our internal control over financial reporting was effective as of March 31, 2010.

This annual report does not include an attestation report of the company's registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by the company's registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management's report in this annual report.

There have been no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Rule 13a-15 or 15d-15 under the Exchange Act that occurred during the quarter ended March 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Not Applicable.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

The information required by this Item is incorporated by reference from the information under the captions entitled "Election of Directors-Nominees," "Executive Officers" and "Section 16(a) Beneficial Ownership Reporting Compliance" in our definitive proxy statement to be filed with the SEC within 120 days after the end of the fiscal year ended March 31, 2010.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this Item is incorporated by reference from the information under the caption entitled "Executive Officer Compensation and Other Information" in our definitive proxy statement to be filed with the SEC within 120 days after the end of the fiscal year ended March 31, 2010.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this Item is incorporated by reference from the information under the caption entitled "Security Ownership of Certain Beneficial Owners and Management" in our definitive proxy statement to be filed with the SEC within 120 days after the end of the fiscal year ended March 31, 2010.



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Table of Contents

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

The information required by this Item is incorporated by reference from the information under the caption entitled "Certain Transactions" in our definitive proxy statement to be filed with the SEC within 120 days after the end of the fiscal year ended March 31, 2010.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this Item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of the fiscal year ended March 31, 2010.

ITEM 15. EXHIBITS INDEX

(a) Financial statements

Reference is made to the Index and Financial Statements under Item 8 in Part II hereof where these documents are listed.



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(b) Financial statement schedules

Financial statement schedules are either not required or the required information is included in the consolidated financial statements or notes thereto filed under Item 8 in Part II hereof.

(c) Exhibits

The exhibits to this Annual Report on Form 10-K are set forth below.

Number Exhibit Description
3(i).1 Articles of Incorporation filed with the Nevada Secretary of State on November 29, 2004. (Incorporated by reference from the registrant's registration statement on Form SB-2 filed on September 8, 2005.)
3(i).2 Certificate of Change filed with the Nevada Secretary of State on November 21, 2006. (Incorporated by reference from the registrant's registration statement on Form 8-K filed on November 30, 2006.)
3(i).3 Certificate of Amendment filed with the Nevada Secretary of State on February 7, 2007. (Incorporated by reference from the registrant's registration statement on Form SB-2 filed on August 1, 2007.)
3(ii).1 Bylaws. (Incorporated by reference from the registrant's registration statement on Form SB-2 filed on August 1, 2007.)
10.2 Contribution Agreement by and among the registrant, JMT Resources, Ltd., REO Energy, Ltd., and Benco Operating, Inc. dated February 1, 2007. (Incorporated by reference from the registrant's current report on Form 8-K filed on February 6, 2007.)
10.5 Joint Operating Agreement dated February 1, 2007 by Rife Energy Operating, Inc. and the registrant. (Incorporated by reference from the registrant's registration statement on Form SB-2 filed on August 1, 2007.)
10.6 Joint Operating Agreement by and between the registrant and Texas MOR, Inc. dated February 1, 2007. (Incorporated by reference from the registrant's registration statement on Form SB-2 filed on August 1, 2007.)
10.7 Employee Confidentiality and Property Agreement by and between the registrant and Scott Allen. (Incorporated by reference from the registrant's registration statement on Form SB-2 filed on August 1, 2007.)




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10.8 Employee Confidentiality and Property Agreement by and between the registrant and Mark S. Zouvas. (Incorporated by reference from the registrant's registration statement on Form SB-2 filed on August 1, 2007.)
10.9 Employee Confidentiality and Property Agreement by and between the registrant and Brett Bennett. (Incorporated by reference from the registrant's registration statement on Form SB-2 filed on August 1, 2007.)
10.10 Office Lease Agreement by and between the registrant as tenant and Hulen South Tower Limited as landlord
21.1 List of Subsidiaries of the Registrant (Incorporated by reference from the registrant's Form 10-K filed on July 14, 2009).
23.1 Forrest A. Garb & Associates Estimated Reserves Report.
31.1 Certification by the CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Certification by the CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 Certification by the CEO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 Certification by the CFO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

REOSTAR ENERGY CORPORATION
Date:  June 29, 2010 By: /s/ Mark S. Zouvas
Mark S. Zouvas
President, Chief Executive Officer and Director

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Mark S. Zouvas and Scott Allen, jointly and severally, his attorney-in-fact, with the power of substitution, for him in any and all capacities, to sign any amendments to this annual report on Form 10-K and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorneys-in-fact, or his substitute or substitutes, may do or cause to be done by virtue hereof.

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


SIGNATURE
TITLE
DATE
/s/ Mark S. Zouvas President, Chief Executive Officer and Director
June 29, 2010
Mark S. Zouvas (Principal Executive Officer)
/s/ Scott Allen Chief Financial Officer and Director July 14, 2008
June 29, 2010
Scott Allen (Principal Financial Officer)
/s/ M. O. Rife III Chairman of the Board of Directors
June 29, 2010
M. O. Rife III
/s/ Jean-Baptiste Heinzer Director
June 29, 2010
Jean-Baptiste Heinzer
/s/ Alan Rae Director
June 29, 2010
Alan Rae



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TABLE OF CONTENTS
Part IItem 1. Business GeneralItem 1A. Risk FactorsItem 1B. Unresolved Staff CommentsItem 2. PropertiesItem 3. Legal ProceedingsItem 4. Submission Of Matters To A Vote Of Security HoldersPart IIItem 5. Market For Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity Securities Market InformationItem 6. Selected Financial DataItem 7. Management's Discussion and Analysis Of Financial Condition and Results Of OperationsItem 7A. Quantitative and Qualitative Disclosures About Market RiskItem 8. Financial Statements and Supplementary DataItem 9. Change in and Disagreements with Accountants on Accounting and Financial Disclosure NoneItem 9. Change in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9a(t). Controls and ProceduresItem 9B. Other Information Not ApplicableItem 9B. Other InformationPart IIIItem 10. Directors, Executive Officers, and Corporate GovernanceItem 11. Executive CompensationItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersItem 13. Certain Relationships and Related Transactions and Director IndependenceItem 14. Principal Accounting Fees and ServicesItem 15. Exhibits Index

Exhibits

10.10 Office Lease Agreement by and between the registrant as tenant and Hulen South Tower Limited as landlord 23.1 Forrest A. Garb & Associates Estimated Reserves Report. 31.1 Certification by the CEO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification by the CFO Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification by the CEO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification by the CFO Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.