October 8, 2009


Via EDGAR

United States Securities and Exchange Commission
Division of Corporation Finance
100 F. Street, N.E.
Washington, D.C. 20549-7010

Attention: Mr. H. Roger Schwall, Assistant Director
Mr. James Giugliano, Staff Accountant

Re: ReoStar Energy Corporation
Form 10-KSB/A for the Fiscal Year Ended March 31, 2008
Filed July 23, 2008
Form 10-Q for Fiscal Quarter ended December 31, 2008
Filed February 13, 2009
Response Letter Dated April 21, 2009
Response Letter Date June 4, 2009
Response Letter Dated July 24, 2009
File No. 000-52316

Dear Mr. Schwall:

                   We have reviewed your comment letter dated September 15, 2009 in respect of the above-referenced filings. This letter sets forth our responses to your comment. We will file a responsive Amendment No. 2 to the 2008 Form 10-KSB/A and a responsive Amendment No. 1 to the 2009 Form 10-K upon confirmation that our response adequately address your comments.

Engineering Comments on Form 10-KSB for the Fiscal Year Ended March 31, 2008

We have reviewed your responses to our prior comment one of our letter dated July 8, 2009. We do not believe that a relatively small pilot alkalai-surfactant polymer injection project that recovered an estimated 35,000 barrels of incremental oil is sufficient to demonstrate reasonable certainty and support classification as proved reserves for over 10 million barrels of undeveloped reserves on an offsetting lease. Among other conerns, we note that the injection project you are operating is not an alkali-surfactant flood as the pilot projects were. Please revise your 2008 and 2009 10-K reports to remove the proved undeveloped reserves for the Corsicana field polymer injection project from the proved category.

We respectfully disagree with your opinion that we have not demonstrated the level of reasonable certainty for the attribution of proved reserves for the following reasons:

The staff's primary concern noted above was based upon the conclusion that the J. O. Burke pilot project was an alkali-surfactant flood, and was therefore different from the surfactant polymer injection project we have begun implementing. We believe the staff has not considered all of the relevant facts in its comment letter. The pilot project was a surfactant polymer project - no alkali was included in the mix. Therefore, the pilot project and our surfactant polymer project are substantially similar, and our engineers were justified in using the offset pilot as a baseline for the reserve study.

Further, the staff's opinion does not take into consideration the fact that ReoStar began polymer injection in the first stage of our project in June 2007 and that the oil recovery response observed through the evaluation date was within the expected range of response indicated by the J.O. Burke pilot project. This response not only validates the J.O. Burke pilot, it also validates the recoverable volumes shown in the reserve report - they are achievable.

If the staff disagrees with our response and is requiring us to amend our filings to remove the reserves associated with the surfactant-polymer project from the proven category, we propose the following amendments to our 2008 and 2009 10-K reports accordingly.


Changes to the 2008 10-KSB:

We propose Footnote 15 - Supplemental info on oil and gas exploration, development and production activities from the 2008 10-K be amended to the following:

(15) 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.

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	610	12,311	2,662
Total Proved Reserves at April 1, 2008	1,411	18,809	4,546

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	698	-	9
Proved Undeveloped	590	12,311	2,642	20	-
Total Proved Reserves at April 1, 2008	944	18,807	4,079	450	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.

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
In thousands		April 1, 2008			April 1, 2008			April 1, 2008			April 1, 2008
Future Cash Inflows	$	311,067		$	267,363		$	41,944		$	1,760
Future Production and Development Costs		(107,196	)		(92,186	)		(13,919	)		(1,091	)
Income Taxes		(71,355	)		(61,312	)		(9,809	)		(234	)
Future Net Cash Flows		132,516			113,865			18,216			435
10% Annual Discount		(64,215	)		(55,724	)		(8,374	)		(117	)
Standardized Measure of Discounted   Future Net Cash Flow	$	8,301		$	58,141		$	9,842		$	318

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

In Thousands
Balance at beginning of year	$	117,629
Net change in prices and production costs		19,348
Net changes in future development costs		(14,805	)
Sales of oil & gas produced net of production costs		(2,458	)
Extensions and discoveries		98,476
Previously estimated development costs incurred		2,188
Revisions of previous quantity estimates		(372,372	)
Purchases of reserves		1,815
Net change in income taxes		93,733
Accretion of discount		124,747
End of Year	$	68,301

The last sentence in the Corsicana Field section of Item 2 found on page 14 will be amended to the following:


As of March 31, 2008, total proved developed reserves were 430 MBOE and proved undeveloped reserves totaled 20 MBOE.

The reserve table on page 15 will be amended to the following:

Reserves		Barnett Shale	Corsicana Field	E. Texas Field	Total
Proved Developed (MBOE)		1,437	430	9	1,876
Proved Undeveloped (MBOE)		2,642	20	9	2,671
Total Proven Reserves at March 31, 2008		4,079	450	18	4,547
Benchmark Pricing
Natural Gas per mcf	$	9.86
Crude Oil per barrel	$	101.54

The second paragraph of the Results and Analysis of Financial Condition, Cash Flows, and Liquidity section on page 20 will be revised to the following:

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. Based upon an engineering review, the proven undeveloped reserves originally attributed to the polymer flood project have been reclassified to probable. The following chart summarizes pertinent reserve information for our Corsicana properties at March 31, 2008 and March 31, 2007.

	Net Reserves (MBOE)
	2008	2007	% Change
Proved Developed	430	106	406.4%
Proved Undeveloped	20	11,302	-99.8%
	450	11,408	-96.1%

Changes to the 2009 Form 10-K:

We propose that Footnote 17, Supplemental info on oil and gas exploration, development, and production activities from the 2009 10-K be amended to the following:

(17) SUPPLEMENTAL INFO ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED).

The following information concerning our natural gas and oil operations has been provided pursuant to Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities," ("SFAS No. 69"). All of our natural gas and oil producing activities are located in Texas.



Capitalized Costs Relating to Oil and Gas Producing Activities

	Fiscal Year Ended March 31,
		2009			2008
Unproved oil and gas properties	$	484,198		$	2,445,556
Proved oil and gas properties		23,920,960			14,456,967
Support Equipment and facilities		-			-
Capitalized Interest		999,620			930,408
Total Capitalized Cost of Oil and Gas Properties		25,404,778			17,832,931
Less accumulated depletion, depreciation, and amortization		(6,206,558	)		(4,139,337	)
Net Capitalized Costs	$	19,198,220		$	13,693,594

Costs incurred in Oil and Gas Producing Activities

	Fiscal Year Ended March 31,
		2009		2008
Property Acquisition Costs
Proved	$	427,676	$	1,814,718
Unproved		15,472		271,151
Exploration Costs		267,212		4,933,277
Development Costs		7,393,929		696,594
Asset retirement costs recognized according to SFAS No. 143		344,079		-
Total Costs Incurred	$	8,448,368	$	7,715,740

Key Production Statistics:

The following reflects the oil and gas production for the fiscal years ended March 31, 2008 and 2009:

		Oil & Gas Production
			Oil (Bbl)	Gas (Mcf)	Total BOE
Fiscal Year Ended	3/31/2008		33,602	351,538	92,192
Fiscal Year Ended	3/31/2009		45,105	479,180	124,968

Results of Operations for Producing Activities:

The following reflects results of operations for the fiscal years ended March 31, 2009 and 2008:

	Fiscal Years Ended March 31,
		2009			2008
Oil & Gas Revenue	$	6,558,069		$	4,902,072
Gain on Sale of Oil & Gas Leases		18,005			307,028
Production Costs		3,140,198			2,800,388
Exploration Costs		2,975			61,179
Expired Leases and Plugging Costs		433,969			290,959
Depreciation, Depletion, & Amortization		4,591,131			1,399,293
		(1,592,199	)		657,281
Income Taxes		557,270			(230,048	)
Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs)		(1,034,929	)		427,233

Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)

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

The SEC defines proved reserves as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those proved reserves which can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered as a result of additional investments for drilling new wells to offset productive units, recompleting existing wells, and/or installing facilities to collect and transport production.

Changes in estimates of proved reserves significantly impact the depletion expense we record each year. When proved reserves increase, our depletion rate decreases, resulting in a lower depletion expense and higher net income. Conversely, when proved reserves decrease, our depletion rate increases, resulting in a higher depletion expense and lower net income. Changes in estimates of proved reserves are frequently the result of changes in commodity prices, changes in operating costs, and reservoir performance history.

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

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

The reports utilize the base crude oil and natural gas prices in effect at March 31, 2009 and 2008, respectively. For the reserves at March 31, 2009, the base crude oil and natural gas prices were $49.65 per barrel ("Bbl") and $3.58 per million British thermal units ("MMbtu"), respectively. For the reserves at March 31, 2008, the base crude oil and natural gas prices were $101.54 per bbl and $9.86 MMbtu, respectively. The base prices for both crude oil and natural gas are adjusted by the normal price differential between the prices we historically have received for our products and the spot price quoted on the relevant market exchange.



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

	Oil (MBBL)		Gas (MMCF)
Reserves at March 31, 2007	11,677		3,392
Revisions of previous estimates	(10,970	)	(133	)
Improved recovery	124		4,786
Purchases of minerals in place	24		525
Extensions and discoveries	590		10,591
Production	(34	)	(351	)
Sales of minerals in place	-		-
Reserves at March 31, 2008	1,411		18,809
Revisions of previous estimates	(739	)	(11,269	)
Improved recovery	-		-
Purchases of minerals in place	1		25
Extensions and discoveries	397		4,725
Production	(45	)	(479	)
Sales of minerals in place	-		-
Reserves at March 31, 2009	1,025		11,811

Revisions of previous estimates: The table above identifies a downward revision of a previous estimate of oil reserves for the year ended March 31, 2008 of 10,970 MBBLS. The revision primarily relates to a reclassification of reserves from proven undeveloped to probable reserves in the Corsicana polymer flood as a result of initial response rates from Phase I of the project. The table also identifies downward revisions in both oil and gas reserves for the year ended March 31, 2009. The downward revision is primarily a function of price. The base oil price at March 31, 2009 was more than 51% lower than the base price included in the previous reserve report. The base natural gas price at March 31, 2009 was down by more than 60%. Consequently, as the properties experience their expected declines, the properties are expected to become non-economic earlier, resulting in significantly less projected economically recoverable reserves.

Improved recovery: During the fiscal year ended March 31, 2008, the Company implemented changes to the completion techniques on its Barnett Shale properties that resulted in increased recoverable reserves. Consequently, estimates of recoverable reserves for properties shown as proved undeveloped reserves on the March 31, 2007 were increased to reflect the increase in estimated reserves from the new techniques.

Purchases of minerals in place: The Company began a working interest repurchase program in its Barnett Shale properties in December 2007. On December 4, 2007, the Company agreed to repurchase working interests in 27 wells and has subsequently from time to time, repurchased smaller working interests.

Extensions and discoveries: The Company successfully drilled 8 and 18 of the Barnett shale locations that were classified as proven undeveloped properties for the years ending March 31, 2009 and 2008, respectively. The successful drilling of the wells resulted in additional proven undeveloped reserves in offset locations.



The following table reflects total reserves by project at April 1, 2009:

	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	94	2,812	563	100	11
Proved Developed Non-Producing	43	494	125	87	2
Proved Undeveloped	655	8,505	2,073	33	-
Total Proved Reserves at April 1, 2009	792	11,811	2,761	220	13

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, 2009. These estimates were prepared by an independent petroleum engineering firm, Forest Garb and Associates, Inc. Proved reserves are estimated quantities of natural gas and crude oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:

• Estimates are made of quantities of proved reserves and future amounts expected to be produced based on current year-end economic conditions.

• Estimated future cash inflows are calculated by applying 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 as of March 31, 2009 and 2008 is as follows:

	As of March 31,
In thousands		2009			2008
Future Cash Inflows	$	90,391		$	311,067
Future Production and Development Costs		(55,865	)		(107,195	)
Income Taxes		(12,084	)		(71,355	)
Future Net Cash Flows		22,442			132,517
10% Annual Discount		(12,120	)		(64,216	)
Standardized Measure of Discounted Future Net Cash Flow	$	10,322		$	68,301

The following reconciles the change in the standardized measure of discounted future net cash flow during the fiscal years ended March 31, 2009 and 2008:

	Year Ended March 31,
In Thousands		2009			2008
Balance at beginning of year	$	68,301		$	117,629
Net change in prices and production costs		(194,933	)		19,348
Net changes in future development costs		6,807			(14,805	)
Sales of oil & gas produced net of production costs		(3,533	)		(2,458	)
Extensions and discoveries		23,664			98,476
Previously estimated development costs incurred		8,243			2,188
Revisions of previous quantity estimates		(10,020	)		(372,372	)
Purchases of reserves		427			1,815
Net change in income taxes		59,271			93,733
Accretion of discount		52,095			124,747
End of Year	$	10,322		$	68,301

The following shows the standardized measure of discounted future net cash flow by project as of March 31, 2009:

		Total			Barnett Project			Corsicana Project			East Texas Project
In thousands		April 1, 2009			April 1, 2009			April 1, 2009			April 1, 2009
Future Cash Inflows	$	90,391		$	79,631		$	10,095		$	665
Future Production and Development Costs		(55,865	)		(48,034	)		(7,588	)		(243	)
Income Taxes		(12,084	)		(11,059	)		(878	)		(147	)
Future Net Cash Flows		22,442			20,538			1,629			275
10% Annual Discount		(12,120	)		(11,366	)		(668	)		(86	)
Standardized Measure of Discounted   Future Net Cash Flow	$	10,322		$	9,172		$	961		$	189

The last sentence in Item 2 Description of Properties; Corsicana Field (page 15) will be adjusted to the following:

As of March 31, 2009, total proved developed reserves were 187 MBOE and proved undeveloped reserves totaled 33 MBOE.

The table disclosing estimated proved reserves on page 16 will be adjusted to the following:

Estimated Proved Reserves		Barnett Shale	Corsicana Field	E. Texas Field	Total
Proved Developed (MBOE)		688	187	13	888
Proved Undeveloped (MBOE)		2,073	33	-	2,106
Total Proven Reserves at March 31, 2009		2,761	220	13	2,994
Benchmark Pricing
Natural Gas per mmbtu	$	3.58
Crude Oil per barrel	$	49.65

*****

                 We have endeavored to fully respond to the Staff's comments set forth in its September 15, 2009 letter. On behalf of ReoStar Energy, please be advised that we acknowledge that:

• The company is responsible for the adequacy and accuracy of the disclosure in the filings;

• Staff comments or changes to disclosure in response to staff comments do not prevent the Commission from taking any action with respect to the filings; and

• The company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

Thank you in advance for your review. Please contact the undersigned at (817) 989-7367 if you have any questions.

Very truly yours,

/s/ Scott D. Allen
Scott D. Allen
Chief Financial Officer

cc:  Greenberg Traurig, LLP