CORRESP 1 filename1.htm
January 23, 2006
Mr. H. Roger Schwall
Assistant Director
Division of Corporate Finance
United States Securities and Exchange Commission
Mail Stop 7010
Washington, DC 20549

| RE: | Natural Gas Systems, Inc.

Registration Statement on Form SB-2
Filed June 6, 2005 and amended October 19, 2005
File No. 333-125564
Dear Mr. Schwall:
On behalf of Natural Gas Systems, Inc., a Nevada corporation (the “Company”), we have enclosed for filing under the Securities Act of 1933 Amendment No. 2 to the Registration Statement on Form SB-2, Registration No. 333-125564 (the “Registration Statement”), including the exhibits thereto, that was initially filed with the Securities and Exchange Commission (the “Commission”) on June 6, 2005, and amended by Amendment No. 1 thereto as filed with the Commission on October 19, 2005. We have supplementally also enclosed a copy of Amendment No. 2 that has been marked to show the changes that have been made to Amendment No. 1. Amendment No. 2 to the Registration Statement includes an amended prospectus (the “Prospectus”).
By its letter dated November 18, 2005, the staff of the Commission (the “Staff”) provided the Company with comments on Amendment No.1. We have set forth below the responses of the Company to the Staff’s comments. The numbers of the responses set forth below correspond to the numbered comments in the November 18 letter from the Staff.:
Comment 1: Please provide justification for not naming Mr. James F. George as an underwriter.
We have amended our document to remove James F. George as a selling stockholder.
Comment 2: Please expand your response to prior comment 5 regarding Item 310 of Regulation SB and accounting for the “reverse merger”.

| a. | With respect to the financial statements we filed relating to the May, 2004 merger of Old NGS with a subsidiary of Reality Interactive, Inc. (the former name of our company), we have revised our note on page F-7, and deleted references to SAB 2:A.

As to the appropriateness of our accounting for our transaction with Reality Interactive and the financial statements we filed with the SEC, please be advised that Reality Interactive represented that it had no operating assets from 1999 through the time of the merger. Additional information regarding the parties, structure and shares exchanged follows:
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On May 26, 2004, Reality Acquisition Corp. (“Reality Sub”), a newly formed wholly owned subsidiary of Reality Interactive, Inc., a Nevada corporation ("Reality Interactive"), merged with and into Natural Gas Systems, Inc., a Delaware corporation ("Old NGS"). As a result of this merger (the "Merger"), Old NGS became a wholly owned subsidiary of Reality Interactive. The Merger occurred pursuant to an Agreement and Plan of Reorganization dated as of April 12, 2004 (the "Merger Agreement") among Reality Interactive, Reality Sub, Global Marketing Associates, Inc., Dean H. Becker and Old NGS. On April 27, 2004, Reality Interactive filed a copy of the Merger Agreement with the Commission on a Report on Form 8-K/A.
Reality Sub merged with and into Old NGS upon the terms and conditions set forth in the Merger Agreement and in accordance with the provisions of the Delaware General Corporation Law. It was the intention of the parties that the transaction qualify as a tax-free reorganization under Section 368(a)(2)(E) of the Internal Revenue Code of 1986, as amended. Old NGS was the surviving corporation and the separate existence of Reality Sub ceased when the Merger became effective. Each share of Old NGS Common Stock issued and outstanding immediately prior to the Merger was converted into one (1) share of Reality Interactive Common Stock. All such shares of Old NGS Common Stock that were outstanding were automatically canceled and ceased to exist. All 1,000 shares of the Common Stock of Reality Sub (representing all issued and outstanding shares) were converted into one (1) share of Common Stock of Old NGS, which is owned by Reality Interactive.
Immediately prior to the Merger, Reality Interactive had 7,946,255 outstanding shares of common stock and no outstanding shares of preferred stock. Pursuant to the Merger, (i) 7,000,000 of the 7,010,000 shares of Reality Interactive common stock held by Dean H. Becker, Reality Interactive's President and Chief Executive Officer, were cancelled, and (ii) 21,750,001 shares of Reality Interactive common stock were issued to the stockholders of Old NGS in exchange for 100% of the outstanding shares of common stock of Old NGS. The share exchange ratio in the Merger was determined through arms'-length negotiations between Reality Interactive and Old NGS. Prior to the Merger, Mr. Becker owned approximately 88% of Reality Interactive's outstanding shares.
Each outstanding option or warrant to purchase shares of Old NGS common stock, whether or not then exercisable, was converted into an option or a warrant to purchase an identical number of shares of Reality Interactive common stock at a price equal to the exercise price of the option or warrant in effect immediately prior to the Merger.
As a result of the Merger, (i) 22,696,256 shares of Reality Interactive common stock were outstanding, 95.8% of which were owned by the former stockholders of Old NGS, (ii) control of Reality Interactive was assumed by the former stockholders of Old NGS, (iii) the executive officers of Old NGS became the executive officers of Reality Interactive, (iv) the Board of Directors of Old NGS became the Board of Directors of Reality Interactive and (v) Reality Interactive’s name was changed to Natural Gas Systems, Inc, a Nevada corporation.
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Based on these facts and circumstances, especially those described in the immediately preceding paragraph above, we concluded that the merger transaction represented, in effect, a recapitalization of Old NGS. Accordingly, we accounted for the transaction as a “reverse merger”, wherein Old NGS was treated as the accounting acquiror and filed financial statements with the SEC reflecting the historical financial condition and operating results of Old NGS. No goodwill arose from the transaction and all transaction costs were expensed as incurred.
In accordance with Rule 310 (c) of Regulation S-B we provided on Form 8-K/A the following financial information:

| i. | Audited revenue and direct operating expenses for an 18 month period, consisting of the nine months ended December 31, 2002 and the nine months ended September, 2003 (date of the acquisition). Revenue and direct operating expense statements accorded purchasers of “oil and gas businesses” were presented in accordance with additional guidance provided by the Division of Corporate Finance at Item IIIC - Financial Statements for Acquired Oil and Gas Producing Properties, since full financial statements were not available or reasonably attainable from the seller.

| ii. | Audited financial statements of Old NGS from September 23, 2003 (inception), through its old fiscal year ended December 31, 2003.

| b. | With respect to our acquisitions of two groups of producing leasehold interests in the Tullos Field Area in September 2004 from Atkins Production, and February 2005 from Chadco, we followed Regulation S-B 310 c., Financial Statements of Businesses Acquired or to be Acquired, as follows, to ascertain whether financial information for these properties was required to be filed on Form 8-K in accordance with Rule 310 of Regulation S-B:

| i. | For the tests at 310-2. i & ii:

| 1. | Our assets at June 30, 2004 were $4,011,065.

| 2. | Our investments in and the total assets we acquired in the Tullos Field Area acquisition from Atkins in September 2004 was $705,790, or 17.6% of our total assets at June 30, 2004 (or 16.3% after additional adjustments to the purchase price described in #4 below).

| 3. | Our investments in and the total assets we acquired in the Tullos Field Area acquisition from Chadco in February 2005 was $798,907, or 19.9% of our total assets at June 30, 2004 (or 16% after additional adjustments to the purchase price described in #4 below).

| 4. | Pursuant to the terms of the purchase agreements regarding the property acquisitions described in #2 and 3 above, we are the beneficiary of certain contractual downward adjustments to the purchase prices resulting from proceeds to be received from the State of Louisiana concerning eminent domain proceedings on wellbores located within a state highway expansion. The expected adjustments are:

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| a. | A $52,667.67* downward adjustment to the Atkins acquisition of September of 2004, or 1.3% of our assets at June 30, 2004.

| b. | A $158,000** downward adjustment to the Chadco acquisition of February 2005, or 3.9% of our assets at June 30, 2004.

| c. | To date, we have received notice from legal counsel that one of the Chadco well proceedings has been finalized in the amount of $39,500 to our interest or .98% of our assets at June 30, 2004, although we have not received the proceeds as of the date of this letter.

* (1/3 of 2 wells @ $79,000 each)
** (½ of 4 wells @ $79,000 each)

| ii. | For the test at 310-2.iii:

| 1. | Our loss for the period from September 23, 2003 (inception) to June 30, 2004 was $1,364,587.

| 2. | Revenue and direct operating expenses, including a $36,000 allocation for field supervision, for the twelve months ended June 30, 2004 for our Tullos Field Area acquisition from Atkins in September 2004, was $161,000, or 11.8% of our loss for the period from September 23, 2003 (inception) through our year ended June 30, 2004.

| 3. | By analogy, revenue and direct operating expenses, including field supervision, for the twelve months ended June 30, 2004 for our Tullos Field Area acquisition from Chadco in February 2005 was $186,277, or 13.7% of our loss for the period from September 23, 2003 (inception) through our year end June 30, 2004.

| iii. | Since none of the tests exceeded 20% individually, or 40% in the aggregate, no financial statements of the acquirees were required to be filed with the SEC on Form 8-K in accordance with Rule 310 (c) of Regulation S-B.

| c. | With respect to Securities Exchange Act of 1934reporting requirements, we have filed:

| i. | Financial statements in compliance with Rule 310(a) for the twelve months ended June 30, 2005, the six months ended June 30, 2004 and the period from September 23, 2003 (inception) to December 31, 2004, reflecting the financial results of Old NGS.

| ii. | Financial statements in compliance with Rule 310(b) for the three months ended March 31, September 30 and December 31, 2004 and for the three months ended March 31 and September 30, 2005, reflecting the financial results of Old NGS.

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| d. | With respect to Securities Act of 1933 reporting requirements for Amendment No.2 to the Registration Statement we are filing on Form SB-2, we are providing the following financial statements:

| i. | The financial statements provided in accordance with Rule 310(a) above, representing 21 months of audit coverage since inception of the oil and gas operations of Old NGS,

| ii. | The audited revenue and direct operating expense statements we filed under 310(c),

The Staff has concluded that the audited statements of revenue and direct operating expenses do not fulfill the requirements for reporting in a ’33 Act filing under 310 (a), due to a “predecessor entity” issue. Based on this conclusion, we have reviewed the missing three months of full audit coverage needed for 24 month audit coverage suggested by the Staff, and believe it is not meaningful to an investor’s understanding of our operations, especially given the dilapidated condition of the field upon our acquisition as evidenced by the audited statement of revenues and direct operating expenses of the Delhi Field acquired on September 23, 2003, included in our Form SB-2. In that report, oil and gas sales for the period from January 1, 2003 to September 30, 2003 were $148,506, resulting in net revenue after direct operating expenses of $6,652. For the preceding nine month period ended December 31, 2002, oil and gas sales were $64,491, resulting in net revenue after direct operating expenses of $9,289. Further, additional financial data was not available for the three months prior to April 1, 2002. As we understand it from our seller, the operator during that period abandoned the property to foreclosure.
Based on these facts and further discussions with the Staff, we believe the Staff has agreed that presenting 21 months of full audit coverage through June 30, 2005 would provide sufficient information for purposes of the Registration Statement on Form SB-2.
Comment 3: Please respond to the disclosure on page 8 regarding the additional payments (described as penalties) payable under the terms of the private placement agreement for failure to register the shares and obtain/maintain effectiveness of a registration statement with the SEC.
Included in this discussion are two topics, taken separately as follows:

| a. | Did the potential liability for contingent payments create “temporary equity”?

We found limited literature to guide us in this area:

| i. | EITF 05-4 "The Effect of a Liquidated Damages Clause on a Freestanding Financial Instrument Subject to EITF Issue No. 00-19, ‘Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company's Own Stock’" appears to address our specific issue, although as we understand it, the EITF has tabled this effort until the FASB provides additional guidance on the derivative nature of a registration rights agreement. We, therefore, find this guidance inadequate.

| ii. | EITF 00-19 provides guidance on “Accounting for freestanding contracts that are indexed to, and potentially settled in, a company's own stock”. To the extent that our registration rights agreement could be determined to be a freestanding derivative, we examined paragraph 16 and determined that the 8% maximum amount due the purchaser (“Rubicon”) for failure to register and maintain effectiveness of a registration statement did not exceed the difference between the fair value of registered and un-registered shares. We came to this conclusion based on knowledge that many PIPE transactions, with registration rights attached, are commonly priced at a 10-15% discount to currently registered shares. Since the 8% penalty provision of our agreement did not exceed this 10-15% market discount, it is not considered a “penalty”. As such, the provisions of EITF 00-19 are not applicable to this transaction.

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Our review of the applicable literature and historical practice of SEC registrants does not, in our view, support classification of the proceeds of the common stock as temporary equity until the shares in question have been registered. In analyzing the terms of our agreement, the maximum amount for which we could be liable under the terms of our Registration Rights Agreement is $240,000, an excerpt of which follows:
as partial relief for the damages to any holder by reason of any such delay in or reduction of its ability to sell the underlying Shares of Common Stock (which remedy shall not be exclusive of any other remedies available at law or in equity), but subject to the limitation set forth in the last sentence of this Section 2(f)………………,which states:
Notwithstanding the other provisions of this Section 2(f), in no event shall the Company be liable for damages in excess of 8% of the aggregate purchase price paid by the holders of Registrable Securities. {underline added}
We believe that the language above is both more specific and conclusive in specifying maximum penalties for damages compared to more typical registration rights agreements that are silent on remedies within the contract, at law or at equity.
Subsequent to the filing of Amendment No. 1 to the Registration Statement on Form SB-2 filed with the Commission, please be advised that we entered into an amended registration rights agreement with Rubicon dated January 13, 2006, in which we agreed to issue 160,000 shares of our common stock to eliminate any amounts that may have been or may become due with respect to the 8% penalty provision of that agreement. A Form 8-K was filed with the Commission on January 20, 2006 describing this transaction, and including as exhibits the Stock Purchase Agreement and the Amended and Restated Registration Rights Agreement.

| b. | Referring to our disclosure on page 8 regarding the penalties under the terms of our registration rights agreement, we agree with you that a SFAS 5 accrual would not have been appropriate at June 30, 2005, since it was not probable at that time that a loss would be incurred.

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Please note, however, that at June 30, 2005, we accrued expected registration costs to be incurred in connection with the common stock sold to Rubicon, which amount included $60,000 in penalties we expected to incur in connection with the underlying registrations rights agreement entered into with Rubicon. These costs were charged against the proceeds of the offering, as we viewed them as a refund of proceeds based on the probability of a contingency event not occurring. We understand the Staff does not concur with our treatment of the penalties as a reduction of the proceeds of the offering. Furthermore, we understand the Staff has questioned whether the accrual of the penalties at June 30, 2005 met the probability requirements of FASB 5 for accrual at that date. It became probable in accordance with the guidelines of FASB 5 that a penalty would be incurred during the quarter ended September 30, 2005. The event giving rise to our conclusion that the penalty became probable was our inability to file the Registration Statement on Form SB-2 in sufficient time to avoid such penalty. Given these factors, the accrual in the amount of $60,000 at June 30, 2005 was not appropriate and $30,000 of expense should have been accrued and charged to expense during the quarter ended September 30, 2005. Given that these amounts are not in our judgment material to our financial statements at either September 30, 2005 or June 30, 2005, we propose that we prospectively make these corrections in our December 31, 2005 quarter.
Comment 4: Provide all disclosures required by Rule 4-10(c)(7) of Regulation S-X:
We have included the additional disclosures required by Rule 4-10(c)(7) of Regulation S-X in Amendment No.2.
Comment 5: Please update financial statements as required by Item 310(g) of Regulation S-B.
Financial statements and consents required by Item 310(g) of Regulation S-B have been updated in our filing.

The following responses were prepared by the Company and reviewed and approved by W. D. Von Gonten & Co., the independent reservoir engineer that reported on the proved reserves of the Company as of January 1, 2004, July 1, 2004 and July 1, 2005.
Comment 7. You stated that the properties purchased in the Tullos Area were transferred without normally available well plats, geological maps and well histories, consequently your development plans were delayed. Please explain, including any technical data, how you estimated prove reserves for Tullos Area Fields without this information, particularly the proved nonproducing reserves.
The proved reserves assigned to the Tullos Field Area properties by W. D. Von Gonten & Co. were determined through analysis of historical production rates and stabilized production declines by lease, available from public records, and historical lease operating costs that we provided to W. D. Von Gonten & Co. based on our actual costs to operate the properties historically. They also obtained, independently, well logs, maps and well histories from Louisiana state records to assist in estimating future reserves. The historical decline rate was projected forward until economic limit to estimate future production. Less than 6% of proved developed reserves were assigned to the Tullos offset non-producing wells, based upon the performance of the immediate offset wells. W. D. Von Gonten & Co. used allocated lease production, based on historical test data, to generate individual well production histories to establish production trends for nonproducing wells to which were assigned proved developed nonproducing reserves.
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Current and future development activities by the Company, to develop incremental unproved production and reserves (not filed or publicly disclosed) in addition to the proved reserves assigned by W. D. Von Gonten & Co., require additional information that we had to independently generate post closing. For example, optimization of salt water collection and disposal, installation of additional salt water disposal capacity, selection of (other than proved) non-producing wells for re-completions or restoration of production, and identification of candidate wells for installation of high volume submersible pumps require exact physical location of wells, flow lines, roads and tank batteries. This information was neither necessary nor required for our independent engineer to assign the proved developed reserves in our July 1, 2005 report.
Comment 8: Please amend the SB-2 to disclose historical product prices before and after any hedging effects and historical production costs.
Page 17 has been amended to include such information.
Comment 9: Please disclose the number of producing wells at each period end.
The numbers of producing wells as of June 30 and September 30, 2005 are approximately:

|  | June 30 |  | September 30 |
Delhi |  |  | 9 |  |  | 10 |
Tullos |  |  | 133 |  |  | 143 |

Amendment No. 2 has been updated to reflect this information.
Comment 10: Please disclose detailed explanation of conditions that led to negative revisions in fiscal 2004, including but not limited to 208-1.
The proved reserves as of January 1, 2004 were based on information available immediately post closing of the purchase of the Delhi Field. Such information included limited documentation as to mechanical work and log section for the Delhi Ut. 208-1 well, which indicated that the well had been tested in the “Z” Sand Formation shortly after being drilled in 1946 at a rate of approximately 160 bopd with a high gas-oil ratio. Due to the high gas oil ratio, the “Z” Sand reservoir was bypassed at that time.
We later obtained from the seller the full well file in which we found that a previous operator had conducted some minimal efforts to re-complete the Delhi Ut. 208-1 in the “Z” Sand and found sufficient reservoir damage, or depletion, to prevent commercial flow. That operator abandoned further efforts to restore production. Therefore, we and W.D. Von Gonten & Co. believed that the probability of obtaining the expected reserves, regardless of amount of work expended, fell below the level required for proved reserves. This revision was the primary negative revision reflected in the report by W. D. Von Gonten & Co.. The registration statement has been amended to eliminate reference to any potential other-than-proved reserves. Other revisions in the July 1, 2004 report by W. D. Von Gonten & Co. were:
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Bases for revisions:
Fuel Use Installation of gas treating facility fueled by lease gas

178-1 | Well was shut-in due to high water production rates and subsequently re-completed into gas producing reservoir post 7/1/04

178-2 | Well suffered from mechanical problems at time of July 2004 report, limiting performance

183-3 | Performance. Well subsequently re-completed to add additional producing reservoir

184-1 | Performance.

197-1 | Well developed sand production problem that limits rate.

208-1 | Additional research into historical records indicated increased risk as to reservoir damage and prior depletion.

87-2 | Field study based on production test, later confirmed by re-completion as a producing well.

123-18 | Field study

184-2 | Re-completed as a gas well prior to 7/1/04

197-2 | Additional review of well data

204-2 | Re-completed as a gas well prior to 7/1/04

W. D. Von Gonten & Co. specifically notes that the Delhi Field was severely neglected by the recent previous operators and the field production decline was a result of both mechanical and reservoir causes, and subsequent operations of the Company provides useful information for more precise evaluation of remaining reserves. The initial independent reserve report, absent a full and detailed field-wide study, only touched upon the full reserves potential of the field, and assigned approximately 300,000 bbls of oil equivalent to a field with cumulative production of approximately 240 million bbls of oil equivalent. Therefore, any change in the current reserves is minuscule compared to the total reservoir. Further, the individual wells evaluated were very mature and the remaining reserves assigned were a small fraction of the ultimate reserves of the wells (please see below explanatory table by W. D. Von Gonten & Co.).
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Comment 11: Please provide technical narrative to support addition of eight proved undeveloped locations, including pertinent production information of relevant offset wells.
We engaged Robert A. Olson, a consulting geologist based in Arkansas with prior experience in the Delhi Field, to conduct a field study of portions of the Delhi Field. His work identified numerous potential drilling locations, eight of which we showed to W. D. Von Gonten & Co. for evaluation and consideration. Each location was based on structural interpretation of immediate offset wells on strike, down dip and up dip. In general, the offset wells down dip were productive in the targeted reservoirs, and the on strike and up dip wells either were tested in the reservoir, without material production, or demonstrated conclusive correlations by electric logs. Note that we have successfully drilled and completed the first three locations.
The consent of Mr. Olson has been included as an exhibit to Amendment No. 2.
Delhi Ut. 92-2 Drilled in October 2005 and completed as a gas well in the Lane Sand at a rate of approximately 700 mcfd. Location was drilled as an attic well immediately up dip from the Delhi Ut. 87-2 well that produced 1209 MBO and 963 MMCF prior to being shut in for high water production, and up dip of and offset from the Delhi Ut. 86-1 well that produced 146 MBO and 484 MMCF prior to watering out. The location is down dip from the Delhi Ut. 92-1 that logged five feet of pay sand with logged resistivity indicative of production, but was not produced following the test in 1946 due to projected (undesirable) gas production.
Delhi Ut. 70-4 Drilled in November 2005 and completed in the Murphy Sand as an oil well. Location was drilled as an attic well immediately up dip of the Delhi Ut. 70-1 (cumulative production of 863 MBO and 485 MMCF) and the Delhi Ut. 58-2 (cumulative production of 1110 MBO and 586 MMCF). Up dip control is provided by the Delhi Ut. 70-3.
Delhi Ut. 87-3 Drilled in November 2005 as a replacement well for the down dip Delhi Ut. 87-2 well (see above) that is currently completed in the Upper Barrier Sand (mechanical problems limit current production to 50 bopd). Location was also intended to develop the Lower Barrier Sand that is also present in the Ut. 87-2 (see above) and successfully flow tested circa 1946. Induction log of the 87-3 defined the oil/water contact in the Lane Sand developed in the up dip 92-2 well (see above) and defined a quality reservoir in the Lower Barrier, further confirmed by sonic log. This well has been completed in the Lower Barrier Sand.
Delhi Ut. 225-2 (Not a PUD) Drilled (spud December 1, 2005) to develop the Barrier Sand. Location is 380’ offset, and 20’ high, to the Delhi Ut. 225-1 that produced 450 MBO and 390 MMCF. Offset control is provided by the Delhi Ut. 232-2 (offset west by 900’ and 35’ up dip from the drilling location) and the Delhi Ut. 224-1 (offset east by 1100’ and 28’ up dip from the location). Both offset wells establish the reservoir boundaries as the Barrier Sand appears to be present in both, though in poor quality and subsequently not produced by the original operator in 1946 (224-1 flow tested oil at low rate, and 232-2 cored oil and flowed gas at then noncommercial rate).
Delhi Ut. 139-2 Scheduled to be drilled in December 2005 to develop the Upper Barrier Sand. Location is approximately 500’ south and ~15’ down dip of the Delhi Ut. 139-1 well that evidenced a 4-5’ portion of the Upper Barrier Sand truncated against the Monroe Gas Rock, which is the sealing cap rock for reservoir development in the field. The location is ~50’ up dip of the Delhi Ut. 123-24 that cumulatively produced 1200+ MBO and 700 MMCF. Lateral control is demonstrated by logged pay sand pinchouts in the Delhi Ut. 123-21 (cumulative production of 72 MBO) that is 1250’ to the east of the drilling location and the Delhi Ut. 147-2 (cumulative production of 5 MBO) that is 900’ to the west of the drilling location.
Delhi Ut. 28-3 Scheduled to be drilled in December 2005 to develop the Lower Lane Sand member of the Holt Bryant group of reservoirs. The location is a 250’ offset (10’ up dip) to the Delhi Ut. 28-1 that logged 15+ feet of high resistivity pay, deemed gas based on drill stem test and abandoned circa 1946. Location is 20’ up dip of the Delhi Ut. 28-2 that logged 18’ of reservoir pay and produced 88 MMCF before mechanical problems shut in well. Location is further up dip of the Delhi Ut. 34-1, 26-1 and 24-1 wells that cumulatively produced approximately 4000 MBO plus associated gas.
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Delhi Ut. 24-4 Scheduled to be drilled in calendar 2006 to develop the Upper Lane Sand member of the Holt Bryant group. Location is ~45’ updip of the Delhi Ut. 26-1 and 24-1 (see above) and Delhi Ut. 24-2 (cumulative production greater than 1000 MBO). Based on the down dip wells watering out at their highest point, the location should be ~25’ up dip of the estimated oil/water contact. Up dip control is established by the Delhi Ut. 23-1 that is ~600’ north and 25’ up dip of the drilling location.
Delhi Ut. 158-4 Scheduled to be drilled in calendar 2006 to develop the Lower Barrier as a replacement well for the Delhi Ut. 158-3, which was shut-in by a previous operator due to mechanical problems while producing in the Holt Sand (below the Lower Barrier). Location is ~35’ up dip to the 158-1, which initially produced 260+ bopd.
Comment 12: Please provide the reserves report prepared by your outside engineer.
Attached is the reserve report summary prepared by W. D. Von Gonten & Co. as of July 1, 2005, with reserve estimates and annual cash flows by reserve category. Although detailed well-by-well reserve estimates and cash flows have not been included (we would hope that the summary information provided would be sufficient for the Staff to complete its review; we also view certain of this information as confidential and would prefer not to have it made potentially publicly available), such detailed information will be provided to the Staff upon further request.
General
In addition to effecting the changes discussed above, the Company has made various other changes and has endeavored to update the information in the Registration Statement.
Please direct questions regarding the amended Registration Statement (other than questions regarding accounting and engineering matters) to the Company’s outside counsel, Lawrence Schnapp, at 310-789-1255. Questions regarding accounting and engineering matters should be addressed to the undersigned, at 713-935-0122.
Sincerely,
Sterling H. McDonald
Chief Financial Officer
Enclosures
cc: Robert S. Herlin
Lawrence P. Schnapp, Esq.
Steven D. Lee, Esq

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