Edgar Filing: ReoStar Energy CORP

REOSTAR ENERGY CORP - Form 10-KSB/A

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

FORM 10-KSB/A

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

For the fiscal year ended March 31, 2008

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-KSB 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, 2008 is $5,490,331 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, 2008 amounted to $15,487,172.

The number of shares outstanding of the registrant's common stock as of March 31, 2008 was 80,181,310 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement for the registrant's 2008 annual meeting of shareholders to be filed with the SEC within 120 days after the end of the fiscal year ended March 31, 2008 are incorporated by reference in Part III of this Form 10-KSB.

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

EXPLANATORY NOTE: ReoStar Energy Corporation is amending its Annual Report on Form 10-KSB to provide the Report of Independent Registered Public Accounting Firm dated June 2, 2008 and to amend the Index to Financial Statements. The remaining Items contained within this Amendment No. 1 to Annual Report on Form 10-KSB/A consist of all other Items originally contained in our Annual Report on Form 10-KSB for the fiscal year ended March 31, 2008 originally filed with the Securities and Exchange Commission on July 15, 2008.

REOSTAR ENERGY CORPORATION
FORM 10-KSB ANNUAL REPORT
FISCAL YEAR ENDED MARCH 31, 2008
TABLE OF CONTENTS

PART I	Page No.
Item 1. Description of Business	1
Item 2. Description of Properties	13
Item 3. Legal Proceedings	16
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 Small Business Issuer Purchases of Equity Securities	16
Item 6. Management's Discussion and Analysis or Plan of Operation	17
Item 7. Financial Statements	F-1
Item 8. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	24
Item 8A(T). Controls and Procedures	24
Item 8B. Other Information	24

PART III
Item 9. Directors, Executive Officers, Promoters, Control persons and Corporate Governance; Compliance with Section 16(a) of the Exchange Act	24
Item 10. Executive Compensation	24
Item 11. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	24
Item 12. Certain Relationships and Related Transactions and Director Independence	25
Item 13. Exhibits	25
Item 14. Principal Accountant Fees and Services	26

GLOSSARY

SIGNATURES	27
Subsidiaries of Registrant
Consent of Independent Registered Public Accounting Firm
Consent of Forest Garb & Associates
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

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 1 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-KSB, 10-QSB, and 8-K subsequently filed from time to time with the SEC.

PART I

ITEM 1. DESCRIPTION OF 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, coupled with complementary acquisitions.

At year-end 2008, a certified engineering firm valued our proven reserves at $425,445,500, which reflects the present value of our future net cash flows from reserves before income taxes, discounted at 10 percent.

At year-end 2008, we owned approximately 20,000 gross (16,250 net) acres of leasehold, which includes 16,000 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.

Business Strategy

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

Significant Accomplishments in Fiscal Year 2008

• 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 sold approximately 1,475 net acres outside our main area of interest and acquired bolt-on acreage of approximately 710 gross acres (approximately 533 net acres) contiguous to the acreage we hold in Cooke County. We drilled, completed, and began production in twelve wells and drilled another seven wells that we anticipate will be completed in the first quarter of fiscal year 2009. Additionally, we repurchased working interests in 30 wells at a cost of approximately $1.8 million. We identified zones up-hole in most of our existing wells that show significant hydro-carbon producing potential in addition to the proven reserves located in the Barnett Shale interval. In February, we successfully moved up-hole from the Barnett and re-completed one well into the Forestburg limestone formation. The re-completed well had an IP of 40 barrels of oil and 50 mcf gas per day at a cost of approximately $50,000.

•	Corsicana Enhanced Oil Recovery (EOR) Project. We began injecting surfactant polymer in our pilot project in mid-June 2007. The initial results have been positive. Average daily production in the pilot project increased by 50% for the fourth quarter when compared to pre-pilot production for the first quarter of the fiscal year. We have initiated the second phase of our polymer flood program and as of the date of this filing have drilled 12 new wells in an area immediately south to our injection facility adjacent to the pilot wells. To date, we have injected over 162,000 bbls of a polymer-surfactant solution into our pilot acreage and expanded the area to include an additional 100 acres. We have also drilled 1 of 4 planned and permitted deep exploration wells with our working interest partner and expect to drill the remaining three during the second quarter of fiscal year 2009.

•	Fayetteville Shale Mineral Interests. We have decided to sell our acreage in Fayetteville Shale as it lies outside of our geographic area of interest.

•	Tri-County Gas Gathering System. In June 2007, we sold our interest in the Tri-County Gas Gathering System for a gain of approximately $2.2 million. The 8-k filed on June 7, 2007 is incorporated herein by reference.

• 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 Enhanced Oil Recovery 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 allows 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.

• Manage Our Risk Exposure. We continue to sell a portion of the working interests in the development wells we drill. Currently, we sell our working interests on a turnkey basis, which helps us to save costs. Due to our focus on controlling costs, we are able to extend economic considerations to not only our third-party working interest investors, but to ourselves in the form of a higher retained interest.

Plans for fiscal year 2009

Barnett Shale

Our drilling budget for the Barnett acreage is $20.5 million for fiscal year 2009. The drilling budget will allow us to complete the seven wells that were in process at year-end and drill and complete 30 more wells in our main area of interest in Cooke County. We will retain up to 60% working interest in the new wells. We expect to fund the drilling with the proceeds of a debt facility, proceeds from the sale of up to 40% working interest in each well on a turnkey basis, and cash flow.

We expect to re-complete at least 20 wells in up-hole zones in fiscal year 2009 at an average cost for our working interest of approximately $50,000 per well. We expect to fund the entire re-completions out of cash flow.

Corsicana

We began drilling the second stage of the surfactant-polymer project in the first quarter. A total of 13 new wells are in the process of being drilled, of which four wells will be injectors and nine will be producers. The expansion will continue the drilling pattern established whereby each injector has approximately four producers surrounding it (inverted five-spot drilling pattern). To date, 12 of the second stage wells have been drilled and the Company is in the process of adding pumps to facilitate the increase in volume of surfactant -polymer being injected. The Company also intends to add an alkali to its injection solution, which will help stabilize clays existent in the formation and improve the sweep efficiency of the flood.

We expect to begin drilling Phase III of the surfactant-polymer project in October and continue with additional development during the third quarter of the fiscal year. We expect to drill as many as 36 additional wells by the end of the fiscal year.

We have acquired deeper rights on several leases and plan to drill up to 4 exploratory wells in the area. We plan to drill three wells in the Pecan Gap formation and one well in the Glen Rose formation. We have mitigated the exploration risk associated with drilling these deeper wells by selling a 50% working interests in each of these wells to our industry partner.

All of the planned tertiary project wells are shallow (800 ft.), and cost approximately $60,000 each to drill and complete. Total capital expenditure budget for fiscal 2009 for the Corsicana project is $3.5 million. The budget will be funded primarily with proceeds from a debt facility.

Production, Revenues and Price History

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

			March 31,	December 31,
	Years Ending		2008		2006		2005
Production
	Oil (Bbl)		33,602		34,607		8,965
	Gas (Mcf)		351,538		199,282		94,358
	Total (BOE)		92,192		67,821		24,691

Revenues
	Crude Oil	$	2,704,468	$	1,772,649	$	555,097
	Gas		2,197,604		1,101,642		554,102
	Total		4,902,072		2,874,291		1,109,199

Average Sale Price (per BOE)		$	53.17	$	42.38	$	44.92

(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 identify and acquire suitable producing properties and prospects for future drilling.

Employees

Non-publicly traded affiliates operate our oil and gas properties. The affiliated operating companies are owned and managed by ReoStar shareholders that collectively own more than 50% of our stock. As of April 1, 2008, the aggregate number of employees and affiliated employees totaled 46.

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.

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-KSB and should not be considered part of this report or any other filing that we make with the SEC. We make available, free of charge, on our website, the annual report on Form 10-KSB, quarterly reports on Form 10-QSB, current reports on Form 8-K and amendments to those reports, as soon as reasonably practicable after providing such reports to the SEC. Also, our Code of Ethics is available on our website and in print 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-KSB, quarterly reports on Form 10-QSB 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."

Effective February 1, 2007 three entities contributed certain assets to Goldrange Resources, Inc. ("Goldrange") in exchange for stock. The contributing entities were under common control prior to the transaction, and immediately after the transactions, the former shareholders of the contributing entities owned 80.4% of the issued and outstanding stock of Goldrange. The contribution was accounted for as a reverse merger, therefore, all assets are carried on the balance sheet at historical cost. The predecessor entities kept accounting records based on a calendar year end. However, Goldrange's year end was March 31. Therefore, for prior years, all data presented reflects data using a calendar year end.

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 mcf 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 Cimmarron Gathering, LP 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 10 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.

In the third quarter we initiated a hedging program. We purchased oil put contracts of 1,000 barrels per month through September 2008. The hedging program was intended to protect downside price risk in the oil markets. Both oil and gas markets have recently experienced a significant increase in pricing. We expect to implement a more comprehensive hedging program during this fiscal year with unaffiliated third parties for portions of our production to achieve more predictable cash flows and to reduce our exposure to down-side price risk.

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.

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 2008, nor do we anticipate that such expenditures will be material in fiscal year ended 2009.

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.

RISK FACTORS

We are subject to various risks and uncertainties in the course of our business. The following summarizes some, but not all, of the risks and uncertainties that may adversely affect our business, financial condition or results of operations.

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 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.

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 increases 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, craterings, 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

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 downhole 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, 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 we have 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.

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.

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.

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.

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.

ITEM 2. DESCRIPTION OF PROPERTIES

The information below summarizes certain data for our core operating areas for the year ended March 31, 2008. 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, the Corsicana field of East Central Texas, and the Fayetteville Shale of Central Arkansas.

Barnett Shale

We have drilled and own interests in 59 completed wells, all of which are operated by Rife Energy Operating, Inc., a non-publicly traded affiliate. Our average working interest is 40%, and our average net revenue interest is 30 percent. We have approximately 6,500 gross (5,800 net) acres under lease, the majority of which is not classified as proven.

Proved developed producing reserves were 739 MBOE, and proved developed non-producing reserves were 698 MBOE. The majority of the proved developed non-producing reserves represented the reserves associated with the 7 wells that were drilled, but were not yet completed. Total proved developed reserves at March 31, 2008 were 1,437 MBOE. Total proven, undeveloped reserves were 2,642 MBOE.

At March 31, 2008, we had a Barnett Shale development inventory of more than 250 drilling locations and 17 proven re-completions. Development projects include re-completions and infill drilling (current field rules provide for 20 acre spacing).

Corsicana Field

We own interests in 67 producing well bores and 199 inactive wells. All of our properties in Corsicana are operated by Texas MOR, Inc, a non-publicly traded affiliate. Our average working interest is 95%, and our average net revenue interest is 76%. Currently, the active wells produce an average of 37 barrels of oil per day. We commenced flooding on our polymer pilot in June of 2007. Production in the polymer pilot wells during the fourth quarter increased by 50% when compared to production on those well before the polymer flood began.

The oil reserves in the field are 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 believe the Polymer flood will allow us to achieve a marked increase in production volumes and give us the ability to prove larger reserves estimates.

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. Currently, the Company has scheduled four exploration wells into two of these zones, the Pecan Gap and the Glen Rose formations. The Company has secured co-financing for these wells from an industry partner who has purchased a 50% working interest in each of these deep wells.

In addition to the Polymer flood, we are evaluating optional EOR techniques including the use of steam and fire floods. Working in conjunction with New Mexico State University and funded from a federal grant program, we will jointly study the reservoir dynamics of the field to determine which enhanced oil recovery technique will optimize the recoverable reserves.

As of March 31, 2008, total proved developed reserves were 430 MBOE and proved undeveloped reserves totaled 10,393 MBOE.

East Texas Properties

We own interest in 4 leases in eastern Texas and western Louisiana. Our average working interest is 50% and our average net revenue interest is 40%.

As of March 31, 2008, total proved developed reserves were 9 MBOE and proved undeveloped reserves totaled 9 MBOE.

Fayetteville Shale

We own 6,450 net acres in the Fayetteville Shale located in Arkansas. The leasehold interests are not contiguous and we expect to sell the acreage during fiscal year 2009. No wells have been drilled on this acreage and no reserve values have been assigned to the leasehold interests.

Proven Reserves

At year-end 2008, the independent petroleum-consulting firm of Forrest Garb and Associates 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, 2008, 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, estimated future net revenues from proved reserves, the present value of those net revenues and the expected benchmark prices used in projecting them (in thousands except prices):

Reserves	Barnett Shale	Corsicana Field	E. Texas Field	Total
Proved Developed (MBOE)	1,437	430	9	1,876
Proved Undeveloped (MBOE)	2,642	10,393	9	13,044
Total Proven Reserves at March 31, 2008	4,079	10,823	18	14,920

Estimated Future Net Revenues (M$)	175,177	754,202	669	930,048

Present Value of Future Net Revenues (M$)	89,447	335,509	489	425,445

Benchmark Pricing

	Natural Gas per mcf	$9.86
	Crude Oil per barrel	$101.54

Future net revenues represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Such calculations, prepared in accordance with Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities," are based on costs and prices in effect at March 31, 2008. There can be no assurance that the proved reserves will be produced within the periods indicated and prices and costs will not remain constant. 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 since year-end.

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. Our operators are affiliated with ReoStar and are owned by shareholders who own more than 15% 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 due not anticipate significant leasehold expirations during the next two years.

Our Corsicana properties and east Texas properties are held by production. Our Fayetteville acreage has an initial five-year term with an option for an additional five years. We have not drilled any wells in the Fayetteville Shale.

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 one-half of the 12,000 square feet of office space under a sublease with the remaining half occupied by our affiliated operating entities, each of which contribute to the costs of leasing and maintenance of the leasehold, pro-rata to their respective usage. The term of the sub-lease is three years, and we pay rent at a rate of $1 per square foot, per month. Our administrative and office facilities are suitable for their respective uses.

ITEM 3. LEGAL PROCEEDINGS

We do not know of any material, active or pending legal proceedings against us, nor are we involved as a plaintiff in any material proceedings or pending litigation.

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 2008.

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 2008	High	Low
June 30, 2007	$1.28	$1.05
September 30, 2007	$1.30	$1.02
December 31, 2007	$1.42	$0.80
March 31, 2008	$1.04	$0.62

Fiscal 2007	High	Low
June 30, 2006	$Nil	$Nil
September 30, 2006	$Nil	$Nil
December 31, 2006	$1.26	$0.05
March 31, 2007	$1.33	$0.95

Holders of Record

On March 31, 2008, there were approximately 80 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, capital requirements, business conditions, the financial condition of the Company and other factors that the Board of Directors may deem relevant.

Recent Sales of Unregistered Securities

In April 2007, we issued 350,000 shares of restricted common stock pursuant to employment agreements with certain of the Company's officers. The shares were issued pursuant to Section 4(2) of the Securities Act.

ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION

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 Item 6, "Selected Financial Data", the financial statements and the accompanying notes included elsewhere in this Form 10-KSB.

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 1 for additional discussion of some of these factors and risks.

Overview of Our Business

We are an independent natural gas and oil company engaged in the acquisition, development, and exploration of oil and gas properties, primarily in Texas. Our objective is to build a balanced portfolio consisting of oil and gas producing properties and reserves in both resource (developmental) and enhanced oil recovery (redevelopment) plays. We will expand reserves through internally generated drilling projects coupled with complementary acquisitions.

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

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

Successful Efforts Method of Accounting

We account for our exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery

and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

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

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

Industry Environment

We operate entirely within the United States, a mature region for the exploration and production of oil and gas. As a mature region, while new discoveries of oil and gas occur in the United States, the size and frequency of these 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 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 like ours 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. Acquisition values have reached historic highs and we expect these values to remain high in the near future. 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. 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

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.

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

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

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

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

• Interest. We carry minimum levels of debt, but in the future, we may finance a 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.

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

Results and Analysis of Financial Condition, Cash Flows and Liquidity

During the fiscal year ended March 31, 2008, we drilled and completed 12 wells in our Barnett Shale project. At year-end, there were seven wells drilled and awaiting completion. ReoStar retained an average working interest in these wells of 44.5% at a total net investment of $7.1 million. The following chart summarizes pertinent reserve information for our Barnett Shale properties at March 31, 2008 and March 31, 2007:

	Discounted Cash Flows @ 10%					Net Reserves (MBOE)
		2008		2007	% Change	2008	2007	% Change
Proved Developed	$	37,209,260	$	7,781,890	478.2%	1,437	426	337.0%
Proved Undeveloped		52,238,110		2,323,380	2248.4%	2,642	409	646.4%
	$	89,447,370	$	10,105,270	885.2%	4,079	835	488.4%

We began injecting surfactant polymer in the pilot project in June 2007. Production responded positively with monthly production for the fourth quarter on the pilot increasing by 50% when compared to the pre-injection production. We began the permitting process for the second stage of the pilot and expect to complete the pilot expansion and to begin injection during the second quarter of the next fiscal year. The following chart summarizes pertinent reserve information for our Corsicana properties at March 31, 2008 and March 31, 2007.

	Discounted Cash Flows @ 10%					Net Reserves (MBOE)
		2008		2007	% Change	2008	2007	% Change
Proved Developed	$	14,799,080	$	1,104,080	1340.4%	430	106	406.4%
Proved Undeveloped		320,710,090		169,758,910	188.9%	10,394	11,302	-8.0%
	$	335,509,170	$	170,862,990	196.4%	10,823	11,408	-5.1%

The average price per barrel of oil during the fiscal year was $80.48 compared with $52.10 for the twelve months ended December 31, 2006. The average price realized per thousand cubic feet (MCF) of gas produced during the fiscal year was $6.25 compared with $6.19 for the twelve months ended December 31, 2006.

Oil and gas production for the year increased 36% to a total of 92,193 BOE compared with 67,821 for the twelve months ended December 31, 2006. Oil and gas revenue for the year increased 70% to a total of $4.9 million compared to $2.9 million for the twelve months ended December 31, 2006. Net income for the fiscal year was $796,000 compared to $193,000 for the twelve months ended December 31, 2006.

During fiscal year ended March 31, 2008, our cash provided from operations was $300 thousand, and we invested $11 million on capital expenditures. Financing activities provided net cash of $4.7 million. The offering closed on April 30, 2007. The Company raised a total of $10.3 million in net proceeds from the private placement, of which $6.9 million was raised during the fiscal year ended March 31, 2008.

On March 31, 2008, we had $592,000 in cash and total assets of $21.3 million. Debt consisted of payables to non-related parties of $2.7 million, of which $1.65 million were long-term note payables. We also had accounts and notes payables to related parties of $5.7 million.

Cash is required to fund capital expenditures necessary to offset inherent declines in production and reserves, which is typical in the oil and gas industry. Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. We are in the process of securing a credit facility, and we believe that the proceeds from such a credit facility and the net cash generated from operating activities will be adequate to satisfy financial obligations and liquidity needs over the next 12-18 months.

However, 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 remain profitable. We operate in an environment with

numerous financial and operating risks, including, but not limited to, the inherent risks of the search for, development and production of oil and gas, the ability to buy properties and sell production at prices which provide an attractive return and the highly competitive nature of the industry. Our ability to expand our reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, bank borrowings or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain capital expenditures that we believe are necessary to efficiently develop our properties and offset inherent declines in production and proved reserves.

Cash Flow

Our principal sources of cash are net cash generated by oil and gas operations, the sale of a portion of the working interest in our Barnett Shale 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 2009 capital program is expected to be funded with internal cash flow and a planned credit facility.

Capital Requirements

Our primary needs for cash are for exploration and development of our Barnett Shale properties, establishing the enhanced oil recovery projects 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 year ended December 31, 2006, a predecessor company, REO Energy, Ltd. expended approximately $24 million on Barnett drilling projects. During the three months ended March 31, 2007, $4.5 million of capital was expended on Barnett Shale drilling projects, and during the fiscal year ended March 31, 2008, $18.2 million of capital was expended on Barnett Shale drilling projects. For fiscal year 2008, $12.2 million of the capital program was funded via the sale of working interests on a turnkey basis. The balance of the Barnett Shale capital program was funded by cash flow from operations and the proceeds of the private placement.

We repurchased working interests in several of our Barnett properties during fiscal year 2008 for a total cost of $1.4 million. The resulting increase in undiscounted cash flow on our March 31, 2008 reserve report was approximately $4.8 million.

Our capital expenditure budget for fiscal year 2009 is $25 million. Of this, $20.5 million is budgeted for drilling in the Barnett Shale, $1 million is budget for up-hole re-completions in our Barnett wells, and $3.5 million is budgeted for the Corsicana surfactant polymer project expansion. Our capital expenditure budget will be funded by a planned credit facility and cash flow from the properties.

Cautionary Statement: There can be no assurance that we will be successful in raising capital through a credit facility or otherwise. 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 current shareholders and us. Additional equity financing could 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.

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, 2008, we do not have any capital leases nor have we entered into any material long-term contracts for equipment, nor do we have any off-balance sheet debt or other such unrecorded obligations.

The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at March 31, 2008. In addition to the contractual obligations listed on the table below,

our balance sheet at March 31, 2008 reflects accrued interest payable on our debt of $109,000 which is payable throughout the rest of 2008.

	Fiscal Year Ending March 31
	2009	2010	2011
Office Lease -	150,000	160,000	131,525
Mineral Lease loans	72,000	-	-
Related Party Notes	325,000	3,195,000	-
Construction Loan	15,000	16,000	16,000

Off-Balance Sheet Arrangements

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

Inflation and Changes in Prices

Our revenues, the value of our assets and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in oil and gas prices and the costs to produce our reserves. Oil and gas prices are subject to significant fluctuations that are beyond our ability to control or predict. Although certain of our costs and expenses are affected by general inflation, inflation does not normally have a significant effect on our business. In a trend that began in 2004 and accelerated during 2007 and 2008, commodity prices for oil and gas increased significantly. The higher prices have led to increased activity in the industry and, consequently, rising costs. These costs trends have put pressure not only on our operating costs but also on our capital costs.

Management's Discussion of Critical Accounting Estimates

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

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

Oil and Gas Properties

To ensure the reliability of our reserve estimates, we engage independent petroleum consultants to prepare an estimate of proved reserves. Proved the SEC defines reserves as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Although our engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, the estimation of reserves requires engineers to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually and consider recent production levels and other technical information. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price and

cost changes and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in the depletion rates utilized by us. We cannot predict what reserve revisions may be required in future periods.

We monitor our long-lived assets recorded in property, plant and equipment in our consolidated balance sheet to ensure they are fairly presented. We must evaluate our properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable oil and gas reserves that will be produced from a field, the timing of future production, future production costs, future abandonment costs, and future inflation. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or gas, unfavorable adjustment to reserves, physical damage to production equipment and facilities, a change in costs, or other changes to contracts, environmental regulations or tax laws. All of these factors must be considered when testing a property's carrying value for impairment. We cannot predict whether impairment charges may be required in the future. We are required to develop estimates of fair value to allocate purchase prices paid to acquire businesses to the assets acquired and liabilities assumed under the purchase method of accounting. The purchase price paid to acquire a business is allocated to its assets and liabilities based on the estimated fair values of the assets acquired and liabilities assumed as of the date of acquisition. We use all available information to make these fair value determinations. See Note 3 to the consolidated financial statements for information on these acquisitions.

Deferred Taxes

We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed many months after the close of a calendar year, tax returns are subject to audit, which can take, years to complete and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carry forwards and other deductible differences. We routinely evaluate deferred tax assets to determine the likelihood of realization. A valuation allowance is recognized on deferred tax assets when we believe that certain of these assets 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 2008, deferred tax liabilities exceeded deferred tax assets by $2.2 million. We may be challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in our various income tax returns. Although we believe that we have adequately provided for all taxes, gains or losses could occur in the future due to changes in estimates or resolution of outstanding tax matters.

Contingent Liabilities

A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of costs can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other 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 7. FINANCIAL STATEMENTS

INDEX TO FINANCIAL STATEMENTS

	Page

Report of Independent Registered Public Accounting Firm	F-2

Balance Sheet, March 31, 2008 and 2007	F-3

Statements of Operations, Three Months Ended March 31, 2008 and 2007 and Years Ended March 31, 2008 and December 31, 2006	F-4

Statements of Stockholders' Equity (Deficit), Three Months Ended March 31, 2008 and 2007 and Years Ended March 31, 2008 and December 31, 2006	F-5

Statements of Cash Flows, Three Months Ended March 31, 2008 and 2007 and Years Ended March 31, 2008 and December 31, 2006	F-6

Notes to Financial Statements	F-8

F-1

Killman, Murrell & Company, P.C.
Certified Public Accountants

1931 E. 37th Street, Suite 7
Odessa, Texas 79762
(432) 363-0067
Fax (432) 363-0376

2626 Royal Circle
Kingwood, Texas 77339
(281) 359-7224
Fax (281) 359-7112

3300 N. A Street, Bldg. 4, Suite 200
Midland, Texas 79705
(432) 686-9381
Fax (432) 684-6722

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders
ReoStar Energy Corporation
(Formerly Goldrange Resources, Inc.)
Fort Worth, Texas 76107

We have audited the accompanying consolidated balance sheets of ReoStar Energy Corporation as of March 31, 2008 and 2007, and the related consolidated statements of operations, stockholders' equity (deficit), and cash flows for the years ended March 31, 2008 and December 31, 2006 and for the three month period ended March 31,2007. 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 audit 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, 2008 and 2007, and the results of its operations and its cash flows for the years ended March 31, 2008 and December 31, 2006 and for the three month period ended March 31, 2007 in conformity with accounting principles generally accepted in the United States of America.

/s/ Killman. Murrell & Company. P. C.
Killman, Murrell & Company, P.C.
Odessa, Texas
June 2, 2008

F-2

ReoStar Energy Corporation
(formerly Goldrange Resources, Inc.)
Consolidated Balance Sheets

	March 31, 2008			March 31, 2007
ASSETS
Current Assets:
Cash	$	592,665		$	212,254
Accounts Receivable:
Oil & Gas - Related Party		868,406			495,200
Other		-			63,389
Inventory		4,748			-
Hedging Account		13,062			-
Discontinued Operations - Assets Net of Liabilities		-			4,005,567
Total Current Assets		1,478,881			4,776,410

Note Receivable		1,355,228			1,614,218

Oil and Gas Properties - successful efforts method		17,832,931			11,712,673
Less Accumulated Depletion and Depreciation		(4,139,337	)		(2,740,044	)
Oil & Gas Properties (net)		13,693,594			8,972,629

Other Depreciable Assets:		1,641,806			-
Less Accumulated Depreciation		(121,113	)		-
Other Depreciable Assets (net)		1,520,693			-

Other Related Party Receivable		80,395			70,395
Leasehold Held for Sale		1,680,813			-
Investment in Equity Method Investment		142,395			-
Total Assets	$	19,951,999		$	15,433,652

LIABILITIES
Current Liabilities:
Accounts Payable	$	103,479		$	509,540
Notes Payable to Related Parties		324,330			324,330
Payable to Related Parties		1,547,136			3,379,069
Royalties Payable		57,485			-
Accrued Expenses		857,887			889,857
Accrued Expenses - Related Parties		171,788			23,646
Current Portion of Long-Term Debt		14,960			5,093,864
Total Current Liabilities		3,077,065			10,220,306

Notes Payable		1,647,769			3,605,937
Notes Payable - Related Parties		3,194,594			3,294,594
Other Related Party Payables		490,840			880,261
Less Current Portion of Notes Payable		(14,960	)		(5,093,864	)
Total Long-Term Debt		5,318,243			2,686,928

Deferred Tax Liability		2,163,183			1,734,563
Total Liabilities		10,558,491			14,641,797

Commitments & Contingencies:
Contingent Stock Based Compensation		214,976			-

Stockholders' Equity
Common Stock, $.001 par,200,000,000 shares authorized and 80,181,310 and 71,954,262 shares outstanding on March 31, 2008 and 2007, respectively		80,181			71,954

Additional Paid-In-Capital		9,553,346			1,970,795
Retained Deficit		(454,995	)		(1,250,894	)
Total Stockholders' Equity		9,178,532			791,855
Total Liabilities & Stockholders' Equity	$	19,951,999		$	15,433,652

See Accompanying Notes to Consolidated Financial Statements
F-3

ReoStar Energy Corporation
(formerly Goldrange Resources, Inc.)
Consolidated Statements of Operations

	Three Months Ended						Fiscal Year Ended			Twelve Months Ended
	March 31, 2008 (unaudited)			March 31, 2007			Mar. 31, 2008			Dec. 31, 2006
Revenues
Oil & Gas Sales	$	1,471,908		$	814,400		$	4,902,072		$	2,874,291
Sale of Leases		-			19,431			307,028			400,378
Other Income		113,919			95,388			281,231			45,771
		1,585,827			929,219			5,490,331			3,320,440

Costs and Expenses
Oil & Gas Lease Operating Expenses		655,208			168,346			2,125,261			1,131,502
Workover Expenses		317,349			-			356,342			-
Severance & Ad Valorem Taxes		116,524			40,962			318,785			163,523
Geologic & Geophysical		-			-			8,993			-
Delay Rentals		-			-			52,186			-
Plugging Costs & Expired Leases		290,959			-			290,959			-
Depletion & Depreciation		647,309			468,540			1,520,406			1,940,354
General & Administrative:		-			135,947			-			281,727
Salaries & Benefits		308,052			-			1,104,785			-
Legal & Professional		86,196			-			584,765			-
Other General & Administrative		101,489			-			332,009			-
Interest, net of capitalized interest of $120,208 and $113,706 for the three months ended March 31, 2008, and March 31, 2007, respectively and $488,299 and $420,230 for the years ended March 31, 2008 and December 31, 2006, respectively		-			63,321			-			13,660
		2,523,086			877,116			6,694,491			3,530,766

Interest Income		54,959			55,811			210,938			-
Hedging Loss		(10,047	)		-			(16,938	)		-
Loss on Equity Method Investments		(32,605	)		-			(32,605	)		-

Income (Loss) from continuing operations before income taxes and discontinued operations		(924,952	)		107,914			(1,042,765	)		(210,326	)

Income Tax Provision		323,695			(1,363,244	)		364,930			-

Income from discontinued operations, net of income taxes:
Pipeline Income		-			107,536			22,930			403,082
Gain on Sale of Pipeline		-			-			1,450,805			-
Income from discontinued operations		-			107,536			1,473,735			403,082
Net Income (Loss)	$	(601,257	)	$	(1,147,794	)	$	795,900		$	192,756

Basic & Diluted Loss per Common Share	$	(0.01	)	$	(0.02	)	$	0.01
Weighted Average Common Shares Outstanding		79,831,310			69,616,786			78,800,618

Pro-Forma Earnings Per Share
Net Income										$	192,756
Proforma Income Tax Expense at Statutory Rate (35%)											(67,465	)
Proforma Net Income										$	125,291

Proforma Weighted Average Shares Outstanding											68,129,310
Proforma Basic & Diluted Earnings Per Share										$	0.00

See Accompanying Notes to Consolidated Financial Statements
F-4

ReoStar Energy Corporation
(Formerly Goldrange Resources, Inc.)
Consolidated Statements of Stockholders' Equity (Deficit)

Common Stock

Number of
Shares

Amount

Paid-In
Capital

Retained
Deficit

Total

Combined Equities of Merged Companies December 31, 2005	68,129,310	$	68,129	$	(921,301	)	$	(829,935	)	$	(1,683,107	)

Net Income 2006	-		-		-			192,756			192,756

Balance, December 31, 2006	68,129,310		68,129		(921,301	)		(637,179	)		(1,490,351	)

Sale of Common Stock	3,824,952		3,825		3,426,175			-			3,430,000

Change in Tax Status of Two Merged Companies	-		-		(534,079	)		534,079			-

Net Loss 2007	-		-		-			(1,147,794	)		(1,147,794	)

Balance, March 31, 2007	71,954,262		71,954		1,970,795			(1,250,894	)		791,855

Sale of Common Stock	7,637,048		7,637		6,877,717			-			6,885,354

Common Stock Issued for Wilson Energy Acquisition	240,000		240		298,560			-			298,800

Common Stock Issued for Employee Compensation	350,000		350		406,274			-			406,624

Net Income 2008	-		-		-			795,900			795,900

Balance, March 31, 2008	80,181,310	$	80,181	$	9,553,346		$	(454,994	)	$	9,178,533

See Accompanying Notes to Consolidated Financial Statements
F-5

ReoStar Energy Corporation
(formerly Goldrange Resources, Inc.)
Consolidated Statements of Cash Flows

	Three Months Ended						Fiscal Year Ended			Year Ended
Operating Activities:	Mar. 31, 2008 (unaudited)			Mar. 31, 2007			Mar. 31, 2008			Dec 31, 2006
Net Income	$	(601,257	)	$	(1,147,794	)	$	795,900		$	192,756
Adjustments to reconcile net income to cash from operating activities:
Deferred Income Tax Expense		(323,695	)		1,421,148			428,620			-
Depletion, Depreciation, & Amortization		647,308			468,540			1,520,406			1,940,355
Expired Leases		280,400			-			280,400			-
Note Accretion		-			41,487			-			128,334
Stock based compensation		156,614			-			621,600			-
Loss on Equity Method Investment		32,605			-			32,605			-
Joint Venture Partner Expense		-			106,276			3,084,789			332,413
Gain on Sale of Pipeline		-			-			(5,789,382	)		-
Cost of Leases Sold		-			-			105,885			-
Changes in Operating Assets and Liabilities
Cash Overdraft		-			-			-			186,912
Changes in Other Assets		-			13,454			-			(13,455	)
Changes in Accrued Liabilities		(182,153	)		-			(55,616	)		86,667
Change in Inventory		(4,748	)		-			(4,748	)		-
Change in Related Party Receivables/Payables		366,237			(516,714	)		37,343			(543,483	)
Changes in Other Receivables		-			(63,389	)		63,389			2,324
Changes in Hedging Account		10,047			-			(13,062	)		-
Changes in Royalties Payable		9,140			-			57,485			-
Change in Revenue Receivables		145,723			(495,201	)		(373,206	)		86,762
Changes in Accounts Payable		(80,597	)		704,151			(492,906	)		-
Net Cash provided (used) from operating activities		455,624			531,958			299,502			2,399,585
Net Cash provided (used) from discontinued operations		-			(1,682,199	)		6,202,067			(2,173,479	)
Net Cash provided (used) by operating activities and discontinued operations		455,624			(1,150,241	)		6,501,569			226,106

Investing Activities:
Oil & Gas Drilling, Completing and Leasehold Acquisition Costs		(219,665	)		(2,091,787	)		(5,269,960	)		(6,371,739	)
Change in Drilling Reimbursements in Excess of Costs		-			(1,962,407	)		-			492,160
Change in Capitalized Note Accretion		35,000			-			140,000			-
Change in Related Party Payable related to drilling		-			-			(4,120,568	)		2,220,498
Deposits		-			-			-			200,000
Investment in Other Depreciable Assets		(166,370	)		-			(1,641,805	)		-
Investment in Equity Method Investment		-			-			(175,000	)		-
Note Receivable Collections		50,085			987,022			258,990			-
Net Cash used in investing activities		(300,950	)		(3,067,172	)		(10,808,343	)		(3,459,081	)

Financing Activities
Notes Payable (Payments) Advances		6,910			999,667			(2,098,168	)		704,466
Changes in Notes Payable Related Party		-			-			(100,000	)		1,264,957
Net cash received from common stock subscriptions		-			3,430,000			6,885,353			-
Net Cash provided (used) from financing activities.		6,910			4,429,667			4,687,185			1,969,423
Net Increase (Decrease) in cash		161,584			212,254			380,411			(1,263,552	)
Cash - Beginning of the period		431,081			-			212,254			1,263,552
Cash - End of the period	$	592,665		$	212,254		$	592,665		$	-

See Accompanying Notes to Consolidated Financial Statements
F-6

ReoStar Energy Corporation
(formerly Goldrange Resources, Inc.)
Consolidated Statements of Cash Flows
(Continued)

	Three Months Ended					Fiscal Year Ended		Year Ended
	Mar. 31, 2008 (unaudited)		Mar. 31, 2007			Mar. 31, 2008		Dec 31, 2006
Supplemental Disclosure of Cash Flow Information
Cash paid during period for:
Interest	$	81,482	$	73,234		$	204,217	$	185,284

Income Taxes	$	-	$	-		$	-	$	-

Non Cash Investing and Financing Activities

Stock Based Property Acquisition	$	-	$	-		$	298,800	$	-

Contribution of Note Receivable	$	-	$	2,601,240		$	-	$	-

Contribution of Note Payable	$	-	$	(1,950,000	)	$	-	$	-

Conversion of Note Payable to Minority Interest	$	-	$	(1,490,000	)	$	-	$	-

Contribution of Related Party Receivable/Payable	$	-	$	651,240		$	-	$	-

Vested Stock Based Compensation	$	406,624	$	-		$	406,624	$	-

See Accompanying Notes to Consolidated Financial Statements
F-7

REOSTAR ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(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 the Southwestern region of the United States. We seek to increase our reserves and production primarily through drilling, complementary acquisitions, and the development of enhanced oil recovery prospects.

Effective February 1, 2007 three entities under common control contributed certain assets and liabilities to Goldrange Resources, Inc. ("Goldrange") in exchange for stock. The contribution was accounted for as a reverse merger. Goldrange had a fiscal year end of March 31, while the contributing entities had calendar year ends. The merged company elected to retain the March 31 fiscal year end. In order to provide a full twelve month period for comparability, the accompanying financial statements reflect results from operations and cash flows for the twelve month periods ended March 31, 2008 and December 31, 2006. For the year ended December 31, 2006, the statements of operations and cash flows include combined amounts applicable to the three entities for the respective years. There were no material intercompany transactions between these entities. See Footnote 3 for more details.

On February 12, 2007 Goldrange changed its name to ReoStar Energy Corporation. ReoStar is a Nevada corporation whose common stock is listed and traded over the counter on the bulletin board.

(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 financial statements.

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

Use of Estimates
The preparation of financial statements in accordance with generally accepted accounting principles 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. All common stock shares and per share amounts in the accompanying financial statements have been adjusted for the four for one stock split effected on November 30, 2006.

Business Segment Information
The Financial Accounting Standards Board ("FASB"), Statement of Financial Accounting Standards ("SFAS") No. 131, "Disclosure About Segments of an Enterprise and Related Information," establishes standards for reporting information about operating segments. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and this information is regularly evaluated by the chief decision maker for the purpose of allocating resources and assessing performance.

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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.

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, 2008, we had no accounts receivable balances over the 120 day threshold, therefore, no allowance for doubtful accounts has been accrued.

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.

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.

The estimated costs of dismantlement and abandonment of depleted wells, net of estimated salvage values, is considered to be immaterial in amount and therefore, no accrual for such costs are included in these financial statements.

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. Such costs are reduced to the extent they exceed the future net revenues of the related proved developed oil and gas reserves. Oil and gas reserve information and other required disclosures related to oil and gas operations has been omitted, due to the limited revenues derived from such activity

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.

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 is amortized on a straight-line basis over a ten year period.

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

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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.

Comprehensive Income
Statement of Financial Accounting Standards (SFAS) No. 130, "Reporting Comprehensive Income," establishes standards for reporting and display 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, SFAS No. 130 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 SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, 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 of more future events occur or fail to occur. The Company's management and its 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 t he 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

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of March 31, 2008. The carrying amount of long-term debt approximates market value due to the use of market interest rates.

Asset Retirement Obligation
Our financial statements reflect the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 provides that, if the fair value for an asset retirement obligation can be reasonably estimated, the liability should be recognized upon acquiring or drilling a well. Under the method prescribed by SFAS No. 143, the 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 balance sheet. Periodic accretion of the discount of the estimated liability is recorded as an expense in the statement of operations. At March 31, 2008, management's estimate of the retirement obligation was immaterial.

Recent Accounting Pronouncements
Statement No. 158, "Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans"-an amendment of FASB Statements No. 87, 88, 106, and 123R. This Statement improves financial reporting by requiring an employer to recognize the over funded or under funded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity or changes in unrestricted net assets of a not-for-profit organization.

Statement No. 157, "Fair Value Measurements". This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements.

Statement No. 156, "Accounting for Servicing of Financial Assets"-an amendment of FASB Statement No. 140. This Statement amends FASB Statement No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, with respect to the accounting for separately recognized servicing assets and servicing liabilities.

Statement No. 155, Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statement No. 133 and 140. This Statement amends FASB Statements No. 133, Accounting for Derivative Instruments and Hedging Activities, and No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.

In the opinion of management, these Statements will have no material effect on the financial statements of the Company.

(3) ACQUISITIONS AND DISPOSITIONS

Reverse Merger
On February 1, 2007, REO Energy Ltd. contributed substantially all of it assets and liabilities to ReoStar in exchange for stock. REO's assets consisted of:

•	Approximately 8,800 acres of proven producing, proven undeveloped, and unproven reserves located in the "oil window" of the Barnett Shale in North Central Texas;
•	Approximately 6,000 acres of undeveloped leasehold in the Fayetteville shale prospect in central Arkansas; and
•	A note and option receivable. The outstanding principal of the note receivable was $2,614,246. The note was secured by a drilling rig. The face value of the option receivable was $300,000 and the carrying value was $0.

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On February 1, 2007, Benco Operating Inc. contributed substantially all of its assets and liabilities to ReoStar in exchange for stock. Benco's assets and deferred tax liabilities consisted of:

•	An undivided 44.44% interest in a joint venture that owned 30% of the Tri-County Gas Gathering System, a pipeline servicing the section of the Barnett Shale where REO's leasehold is located and a 100% working interest in one lease located in the oil window of the Barnett Shale.
•	Deferred tax liabilities of $313,414.

On February 1, 2007, JMT Resources Ltd. contributed substantially all of the assets and liabilities to ReoStar in exchange for stock. JMT's assets consisted of:

•

95% working interest in approximately 4,000 acres in leasehold in East Central Texas. The majority of the property was classified as proven undeveloped and is the subject of an ASP flood pilot. JMT's cost basis in the leasehold was zero due to an impairment write-down taken on the property several years ago.

ReoStar assumed liabilities from the above acquisitions aggregating approximately $14,150,000.

The contributing companies were under common control for more than one year prior to the transaction. Immediately after the transaction, the contributing companies owned more than 80% of ReoStar's issued and outstanding stock. The transaction qualified as a reverse merger and all of the assets and liabilities of the contributing companies were included on ReoStar's balance sheet at historical values.

Wilson Energy Transaction
Effective August 1, 2007, ReoStar purchased substantially all of the assets of Vern Wilson Energy, Inc. The assets consisted of 4 oil and gas leases located in Texas and Louisiana, a service rig, and an operating shop to assist in maintenance of field equipment. Consideration for the purchase consisted of $159,000 cash and 240,000 shares of ReoStar stock with a market value of $298,800 for a total purchase price of $457,800.

(4) DEFERRED TAX LIABILITY
Our income tax (expense) benefit from operations was $364,930 and ($1,421,148) for the year ended March 31, 2008 and the short year ended March 31, 2007, respectively. Because two of the predecessor companies were partnerships (non-tax paying entities), the cumulative deferred tax liability related to their assets was recorded as an expense on the contribution date. A reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows:

	March 31 2008	March 31 2007
Federal Statutory Tax Rate	34%	34%
State	1%	1%
Consolidated Effective Tax Rate	35%	35%

The income tax provision differs from the amount computed at the statutory rate of 35% as follows:

		March 31 2008			March 31 2007
Expected Tax Benefit from Continuing Operations		(364,930	)	$	74,966
Expected Tax Expense from Discontinued Operations		793,550		$	57,904
Tax Expense related to change in tax status					1,288,278
Income Tax Provision	$	428,620		$	1,421,148

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

		March 31 2008		March 31 2007
Deferred Tax Assets:
Net Operating Loss Carryforward	$	1,208,164	$	952,916
Stock Based Compensation		31,221		-
Other Deferred Tax Assets		2,032		-
Total Deferred Tax Assets		1,241,417		952,916

Deferred Tax Liabilities
Oil & Gas Properties Basis		3,375,513		1,956,886
Other Deferred Tax Liabilities		29,087		730,593
Total Deferred Liabilites		3,404,600		2,687,479
Net Deferred Tax Liability	$	2,163,183	$	1,734,563

(5) EARNINGS PER COMMON SHARE

There were no material dilutive common stock equivalents as of March 31, 2008. The following table sets forth the computation of basic earnings per common share.

		March 31 2008		March 31 2007
Numerator
Net Income (Loss)	$	795,900	$	(1,147,794	)

Denominator
Weighted Average Shares Outstanding - Basic		78,800,618		69,616,786

Basic - Net Income	$	0.01	$	(0.02	)

(6) INDEBTEDNESS

The following debt was outstanding as of March 31, 2008 and March 31, 2007, respectively:

	3/31/2008	3/31/2007
Frost National Bank Line of Credit. On January 24, 2008, ReoStar opened a line of credit with Frost National Bank. The line of credit is secured by the workover rig, service rig, swab rig and other equipment. The credit line is $550,000, bears interest at prime rate, and matures January 15, 2009. As of March 31, 2008, the line of credit balance was $0.	$ -	$ -
Construction Loan. On October 2, 2007, ReoStar secured a $245,000 construction loan from Texas Capital Bank to partially finance the construction of a field office on a 10 acre parcel in Corsicana, Texas. The terms of the loan provide for 6 months of interest payments beginning November 1, 2007. Beginning May 1, 2008, the loan provides for 60 months payments equal to $1,360 plus interest. The loan provides for interest equal to the Wall Street Journal Prime Rate. A balloon payment of $164,455 plus interest will be due May 1, 2013. As of March 31, 2008, the outstanding principal balance of the note was $59,335.	59,335	-

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Note Payable to Frost National Bank. On March 31, 2007, the note had a principal balance of $1,950,000, carried an annual interest rate of 5.65% and matured on April 11, 2007. As of March 31, 2007, interest totaling $63,091 was accrued. The note was paid in full on April 10, 2007.	-	1,950,000
Note Payable to 1st State Bank of Texas. The note had a principal balance of $79,603 on March 31, 2007. The note was originated on March 24, 2004, carried a variable interest rate equal to Wall Street Journal prime plus 1%, and matured on August 1, 2008. The note was paid in full in July 2007.	-	79,603
Lease Notes Payable. ReoStar has several notes payables to various private investors that were used by a predecessor company for leasehold acquisitions.
The first originated December 1, 2005 and bears interest of 20% on the principal balance outstanding on the anniversary date. Principal balance of $100,000 was outstanding on March 31, 2007. The note was paid in full in October, 2007.	-	100,000
The second note, originated April 30, 2004, and the third note, originated December 12, 2005, are due to the same individual. Both notes were in the amount of $100,000. The notes provide a ½% carried working interest on each well drilled on certain Arkansas acreage and as certain Arkansas acreage is drilled, the original proceeds shall be repaid at the rate of $2 for each $1 invested on a per acre basis. The Arkansas leasehold has a five year term. In order to make a provision for the $2 for $1 repayment, we accrete interest at a 20% rate. None of the acreage has been drilled, and the balance of the notes was $278,334 and $238,334 on March 31, 2008 and March 31, 2007, respectively.	278,334	238,334
The fourth note originated on December 19, 2005 in the amount of $500,000. The note provides a ½% carried working interest on each well drilled on certain Arkansas acreage and as certain Arkansas acreage is drilled, the original proceeds shall be repaid at the rate of $2 for each $1 invested on a per acre basis. The leasehold has a five year term. In order to make a provision for the $2 for $1 repayment, we accrete interest at a 20% rate. None of the acreage has been drilled, and the balance of the note was $725,000 and $625,000 on March 31, 2008 and March 31, 2007, respectively.	725,000	625,000
The fifth note in the amount of $100,000 originated on May 15, 2006 and bears interest of 10% due annually. The note matures June 1, 2008. The balance of the note was $72,100 and $100,000 on March 31, 2008 and March 31, 2007, respectively.	72,100	100,000
The last note originated May 3, 2006 in the amount of $513,000. The note provides that as certain Arkansas acreage is drilled, the original proceeds shall be repaid at the rate of $257 for each $385 invested on a per acre basis. Additionally, the note provides for the conveyance of a .6666% working interest carried to the tanks on 1,333 of certain Arkansas acreage. The note provides the lender the option to return any interest assigned to ReoStar in exchange for payment of $513,000 plus 10% interest per annum. The option is valid only from May 3, 2007 through November 3, 2007. ReoStar will accrue interest at 10%. The note had a balance of $513,000 at March 31, 2008 and March 31, 2007.	513,000	513,000

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Notes Payable to Shareholder. ReoStar has notes payable totaling $324,330 to ReoStar's President and CEO. The note matures on September 30, 2008 and bears interest of 8%.	324,330	324,330
ReoStar has notes payables to a limited partnership owned by the Chairman of the Board. On March 31, 2008, the notes totaled $3,194,594. The note matures on December 31, 2009 and provides for an interest rate of 7.6%. On March 31, 2007, the note totaled $3,294,594, matured on 12/31/2007, and carried an interest rate of 7.6%.	3,194,594	3,294,594
Total	$5,166,693	$7,224,861

There are no debt covenants associated with the notes payable.

The following table summarizes our note payable repayment obligations.

	Fiscal Years Ending March 31,
		2009		2010		2011		2012		Thereafter		Total
Construction Loan	$	14,960	$	16,320	$	16,320	$	11,735	$	-	$	59,335
Note Payable - Shareholder		324,330		-		-		-		-		324,330
Note Payable - Shareholder		-		3,194,594		-		-		-		3,194,594
Lease Notes Payable		-		-		-		-		1,588,434		1,588,434
	$	339,290	$	3,210,914	$	16,320	$	11,735	$	1,588,434	$	5,166,693

Payable 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, 2008 and 2007 was $1,547,136 and $3,379,069, respectively.

Additionally, ReoStar had other outstanding non-current payables to related parties of $490,840 and $880,261 at March 31, 2008 and 2007, respectively. Subsequent to March 31, 2008, $250,750 of the related party payable was converted to a note maturing June 30, 2011. The note carries interest of 8%.

Accrued Expenses:
Accrued expenses consist of working interest owner payout guarantees totaling $748,963 and $761,302 and accrued interest expense totaling $108,924 and $128,555 at March 31, 2008 and 2007, respectively.

Accrued interest payable to related parties consisted of $171,788 and $23,646 on March 31, 2008 and 2007, respectively.

(7) 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 December 31, 2006.

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	Shares Outstanding
Shares Outstanding December 31, 2006	13,379,310
Shares issued in connection with reverse merger	54,750,000
Private Placement shares issued	3,824,952
Balance at March 31, 2007	71,954,262
Private Placement shares issued	7,637,048
Shares issued for Vern Wilson Energy acquisition	240,000
Shares issued for employment compensation	350,000
Balance at March 31, 2008	80,181,310

Shares issued via the private placement offering totaled 11,462,000 at $1.00 per share. The proceeds from the sale reported in the statement of stockholder's equity is net of offering expenses of $1,146,647. Each share had one warrant attached with a strike price of $1.50 per share. The warrants are scheduled to expire 2 years from the date the stock certificates are issued.

There were unvested restricted stock grants of 350,000 shares outstanding at year end. The unvested stock grants are related to employment compensation for certain of the ReoStar officers.

There were stock option grants issued to members of ReoStar's Board of Directors of 100,000 shares outstanding at year end. 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, one-third will vest on March 31, 2009, and the balance will vest on March 31, 2010.

(8) COMMITMENTS AND CONTINGENCIES

Office Lease
We signed a long-term sublease agreement in February, 2007. The sublease began in late June, 2007. The terms of the lease provide for a monthly base rent of $12,315. The base rent is scheduled to increase to $12,807 beginning July, 2008. The lease is scheduled to expire on January 31, 2010. We sublease approximately forty percent of the office space to a related party.

The following table summarizes the minimum base rent until the lease expires. The minimum base rent excludes any potential reduction in net rent due to subleasing arrangements.

	Fiscal Year Ending March 31,
		2009		2010
Minimum Base Rent	$	152,210	$	131,525

Plugging
The Corsicana oil and gas leases have been producing for more than one hundred year and there are approximately three hundred abandoned wells scattered throughout the leases. In order for the surfactant-polymer flood to be successful, we will need to cement in the wells. Since the wells are relatively shallow, we are able to completely plug each well for less than $500 and the costs will be capitalized as part of the project. No contingency has been recorded as management believes the plugging costs to be immaterial.

No provision for plugging and abandonment for the Barnett oil and gas leases has been accrued as management believes the proceeds from equipment salvage exceeds the cost of plugging the leases.

(9) NOTE RECEIVABLE
ReoStar has a note receivable from our drilling contractor. The note is secured by the rig that is dedicated to our Barnett Shale acreage. The outstanding principal balance on March 31, 2008 and 2007 was $1,355,228 and $1,614,218, respectively.

(10) 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,

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credit quality and service. For the year ended March 31, 2008, three customers, Cimarron Gathering, LP, 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.

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

(12) DISCONTINUED OPERATIONS
Effective May 1, 2007, ReoStar sold its entire interest in the Tri-County Gas Gathering System.

The March 31, 2007 balance sheet reflects ReoStar's historical cost of the investment in the Tri-County Gas Gathering System net of all related liabilities.

The following summarizes the proceeds and gain from the sale of the Tri-County Gas Gathering System:

Total Proceeds	$	15,000,000
Closing adjustment for unpaid capital calls		(900,000	)
Net Proceeds		14,100,000
Basis in the pipeline		(8,827,299	)
Total Gain on sale		5,272,701
Less Allocations to Minority Interest		(3,040,693	)
Less Income Tax on Gain		(781,203	)
Net Gain on Sale of Pipeline	$	1,450,805

The following summarizes the income and expenses of the Tri-County Gas Gathering System:

	Year Ended March 31, 2008			Three Months Ended March 31, 2007			Year Ended December 31, 2006
Pipeline Revenue	$	125,801		$	424,257		$	1,162,790
Pipeline Operating Expenses		(46,428	)		(152,541	)		(427,295	)
Minority Interest Expense		(44,096	)		(106,276	)		(332,413	)
Income Tax Expense		(12,347	)		(57,904	)		-
Net Income from Discontinued Operations	$	22,930		$	107,536		$	403,082

(13) SUBSEQUENT EVENTS
None.

(14) 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 Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities," ("SFAS No. 69"). Our natural gas and oil producing activities are conducted onshore within the continental United States.

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.

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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 reports utilize a base oil price of $101.54 per barrel (Bbl) and a base gas price of $9.86 per thousand cubic feet (Mcf). The base prices equate to average realized prices at April 1, 2008 of $99.26 per barrel for oil and condensate in the Barnett project, $93.33 per barrel for oil produced in the Corsicana project, $101.54 for oil produced in the East Texas project, $9.35 per mcf for gas produced in the Barnett project, and $9.86 per mcf for gas produced in the East Texas project.

The following table reflects total reserves as of April 1, 2008.

	Crude Oil (MBBL)	Natural Gas (MMCF)	Crude Oil Equivalents (MBOE)
Proved Developed Producing	602	3,447	1,177
Proved Developed Non-Producing	199	3,051	708
Proved Undeveloped	10,984	12,311	13,036
Total Proved Reserves at April 1, 2008	11,785	18,809	14,920

The following table reflects total reserves by project at April 1, 2008:

	Barnett Shale Project			Corsicana Project	East Texas Project
	Crude Oil (MBBL)	Natural Gas (MMCF)	Crude Oil Equivalents (MBOE)	Crude Oil (MBBL)	Crude Oil Equivalents (MBOE)
Proved Developed Producing	164	3,446	738	430	8
Proved Developed Non-Producing	190	3,050	699	-	9
Proved Undeveloped	590	12,311	2,642	10,393	-
Total Proved Reserves at April 1, 2008	944	18,807	4,079	10,823	17

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 SFAS No. 69, is an attempt to present the information in a manner comparable with industry peers.

The information is based on estimates of proved reserves attributable to our interest in natural gas and oil properties as of April 1, 2008. These estimates were prepared by Forest Garb and Associates. 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.

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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 current year-end prices of natural gas and oil relating to our proved reserves to the quantities of those reserves produced in each future 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 is as follows:

		Total			Barnett Project			Corsicana Project			East Texas Project
		April 1, 2008			April 1, 2008			April 1, 2008			April 1, 2008
Future Cash Inflows	$	1,279,219,650		$	267,363,340		$	1,010,096,790		$	1,759,520
Future Costs
Production		(228,721,060	)		(68,018,690	)		(159,792,920	)		(909,450	)
Development		(120,450,920	)		(24,167,390	)		(96,102,280	)		(181,250	)
Total Undiscounted Future Net Cash Flow		930,047,670			175,177,260			754,201,590			668,820
Income Taxes		(325,516,685	)		(61,312,041	)		(263,970,557	)		(234,087	)
10% Annual Discount		(334,992,861	)		(56,176,657	)		(278,681,893	)		(134,311	)
Standardized Measure of Discounted Future Net Cash Flow	$	269,538,124		$	57,688,562		$	211,549,140		$	300,422

F-19

The following reconciles the change in the standardized measure of discounted future net cash flow during the fiscal year ended March 31, 2008.

Beginning of Year	$	117,629,370
Effect of Price Change		374,771,413
Sales of oil & gas produced net of production costs		(2,458,026	)
Extensions, Discovery, and Improved Recovery, less related costs		98,476,109
Development costs incurred during the year which were previously estimated		(2,187,500	)
Net Change in Estimated Future Development Costs		(9,480,060	)
Revisions of Previous Quantity Estimates		(5,525,882	)
Net Change from Purchase of Minerals in Place		4,771,716
Accretion of discount		(146,030,331	)
Net Change in Income Taxes		(160,428,685	)

End of Year	$	269,538,124

Capitalized Costs Relating to Oil and Gas Producing Activities at March 31, 2008:

		Successful Efforts
Unproved oil and gas properties	$	2,445,556
Proved oil and gas properties		16,137,780
Support Equipment and facilities		0
Capitalized Interest		930,408
Less Unproved oil and gas properties held for sale		(1,680,813	)
Total Capitalized Cost of Oil and Gas Properties		17,832,931
Less accumulated depletion, depreciation, and amortization		(4,139,337	)
Net Capitalized Costs	$	13,693,594

F-20

Costs incurred in Oil and Gas Producing Activities for the Fiscal Year Ended March 31, 2008, Three Months Ended March 31, 2007 and the Year Ended December 31, 2006

		Fiscal Year Ended 3/31/2008		Three Months Ended 3/31/2007		Year Ended 12/31/2006
Property Acquisition Costs
Proved	$	1,814,718	$	-	$	-
Unproved		271,151		97,251		2,203,837
Exploration Costs		4,933,277		1,886,247		4,167,902
Development Costs		696,594

Amortization rate per equivalent barrel of production		14.42		22.52		32.46

Key Production Statistics:

The following reflects the oil and gas production by the predecessor companies for the prior three years and ReoStar's production for the three months ended March 31, 2007 and fiscal year ended March 31, 2008.

		Oil & Gas Production
			Oil (Bbl)	Gas (Mcf)	Total BOE
Year Ended	12/31/2004		1,721	13,587	3,986
	12/31/2005		8,965	94,358	24,691
	12/31/2006		34,607	199,282	67,821
Three Months Ended	3/31/2007		7,023	55,562	16,283
Fiscal Year Ended	3/31/2008		33,602	351,538	92,192

Results of Operations for Oil and Gas Producing Activities for the fiscal year ended March 31, 2008, the three months ended March 31, 2007 and the years ended December 31, 2006, 2005, and 2004.

The following reflects results of operations by the predecessor companies for the prior three years and ReoStar's production for the three months ended March 31, 2007 and fiscal year ended March 31, 2008.

		Fiscal Year			Three Months		Years Ended December 31,
		Ended 3/31/2008			Ended 3/31/2007			2006			2005		2004
Oil & Gas Revenue	$	4,902,072		$	814,400		$	2,874,291		$	1,109,199	$	144,514
Gain on Sale of Oil & Gas Leases		307,028			-			-			-		26,474
Production Costs		2,800,388			209,308			1,295,025			623,662		15,268
Exploration Costs		61,179			-			-			-		800,000
Expired Leases and Plugging Costs		290,959			-			-			-		-
Depreciation, Depletion, & Amortization		1,399,293			409,376			1,869,683			394,217		96,951
		657,281			195,716			(290,417	)		91,320		(741,231	)
Income Taxes		(230,048	)		(68,501	)		-			-		-
Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs)	$	427,233		$	127,215		$	(290,417	)	$	91,320	$	(741,231	)

F-21

ITEM 8. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 8A(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, 2008.

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.

ITEM 8B. OTHER INFORMATION

None.

PART III

ITEM 9. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY

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, 2008.

ITEM 10. 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, 2008.

ITEM 11. 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, 2008

ITEM 12. 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, 2008.

ITEM 13. EXHIBITS INDEX

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.)

10.1		Purchase and Sale Agreement by and between the registrant and United Texas Petroleum, Inc. dated December 4, 2007. (Incorporated by reference from the registrant's current report on Form 8-K filed on December 7, 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.)

10.3		Private Placement Subscription Agreement. (Incorporated by reference from the registrant's registration statement on Form SB-2 filed on August 1, 2007.)

10.4		Common Stock Purchase Warrant. (Incorporated by reference from the registrant's registration statement on Form SB-2 filed on August 1, 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.)

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		Purchase and Sale Agreement by and between Cimmarron Gathering, LP. and the registrant dated June 6, 2007. (Incorporated by reference from the registrant's current report on Form 8-K filed on June 7, 2007.)

10.11		Purchase and Sale Agreement by and between the registrant and Vern Wilson Energy, Inc. dated September 28, 2007. (Incorporated by reference from the registrant's current report on Form 8-K filed on October 4, 2007.)

10.12		Purchase and Sale Agreement by and between the registrant and United Texas Petroleum, Inc. dated December 4, 2007. (Incorporated by reference from the registrant's Form 8-K filed on December 7, 2007.)

21.1		List of Subsidiaries of the Registrant.

23.1		Consent of Killman, Murrell & Company, P.C.

23.2		Consent of Forest Garb & Associates.

24.1		Power of Attorney. (Incorporated by reference to the signature page of this Annual Report on Form 10-KSB).

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.

99.1		Estimated Reserves and Future Net Revenue Report prepared by Forrest A. Garb & Associates, Inc.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this Item is incorporated by reference from the information under the caption entitled "Audit Committee Report" in our definitive proxy statement to be filed with the SEC within 120 days after the end of the fiscal year ended March 31, 2008.

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: July 22, 2008	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-KSB 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	July 22, 2008
Mark S. Zouvas	(Principal Executive Officer)

/s/ Scott Allen	Chief Financial Officer and Director	July 22, 2008
Scott Allen	(Principal Financial Officer)

/s/ M. O. Rife III	Chairman of the Board of Directors	July 22, 2008
M. O. Rife III

/s/ Jean-Baptiste Heinzer	Director	July 22, 2008
Jean-Baptiste Heinzer

/s/ Alan Rae	Director	July 22, 2008
Alan Rae