HOUSTON AMERICAN ENERGY CORP.
801 TRAVIS, SUITE 1425
HOUSTON, TEXAS 77002
TELEPHONE (713) 222-6966
FACSIMILE (713) 222-6440
December 9, 2008
U.S. Securities and Exchange Commission
100 F Street, N.E.
Washington, D.C. 20549
Attn: Jennifer O’Brien
RE: | Houston American Energy Corp. Form 10-K for Fiscal Year Ended December 31, 2007, as Amended Response Letter Dated October 2, 2008 File No. 1-32955 |
Dear Ms. O’Brien:
Filed simultaneous herewith, via EDGAR, please find Amendment No. 3 to Form 10-K for the fiscal year ended December 31, 2007.
Set forth below are the Staff’s engineering comments, as set forth in the Staff’s letter dated November 25, 2008, followed by our responses, which are numbered to correspond with the numbers set forth in the Staff’s comment letter.
Business, page 3
Other Holdings, page 6
1. | The table for “Acres Leased or Under Option at December 31, 2007” includes a description (footnote 1) stating “Company Net Acres are either leased or under option in which we own an undivided interest.” With a view toward possible disclosure, please explain the differences, including your financial obligations, between these leases and options. Tell us the net acres for which you have options. |
Company Response:
Houston American Energy has an option on one its prospects, the Caddo Lake property located in Caddo Parish Louisiana. Under this option, Houston American has the right but not the obligation to Lease 4,360 gross acres or 1,188.10 net acres. If we chose to exercise the option then we would be obligated to pay the lessor approximately $218,000 for the leases, and would be required to drill 1 well every 180 days to maintain the lease. Other then this one prospect, Houston American Energy is current on all of its leases, either by them being paid in full or by them being held by production.
Footnote 1 to the referenced table has been modified and footnote 2 has been added to reflect the foregoing.
U.S. Securities and Exchange Commission
December 9, 2008
Page 2
Natural Gas and Oil Reserves, page 8
2. | Your third party engineering report states “…seismic and geological interpretations by HUPECOL in house geophysicists and geologists were used to determine the production area and bulk volumes [for Colombian proved reserves.]” Even when properly interpreted, seismic data and visualization techniques are not conclusive in determining if hydrocarbons are present in economically producible amounts. The use of volumetric parameters determined solely by seismic interpretation is not appropriate for estimation of proved reserves. |
· | Please explain to us the methodology used in estimating these proved reserves. |
· | With a view toward possible disclosure, tell us why you believe your third party engineer’s proved reserve estimates are independent in light of their statement above. |
Company Response:
In determining Houston American Energy’s proved reserves at year end 2007, Aluko & Associates, Inc. used production data from Hupecol, as well as well log and core analysis to determine net pay, average porosity and water saturation. In addition, Aluko & Associates, Inc. used production and pressure performance data from available producing wells to determine sands that where productive but behind pipe. The proved non producing reserves were attributed to: 1) recompletion of behind pipe sands in existing wellbores; 2) wells that were perforated and produced but were temporarily shut-in due to weather; 3) wells that were already drilled and logged but waiting on completion; and 4) workovers of existing producing intervals. The undeveloped reserves where attributed to drilling of updip or offset locations to existing producing wells.
Aluko and Associates was hired by Hupecol and Houston American Energy as an independent third party engineer. In preparing the engineering reports for both Hupecol and Houston American Energy, Aluko and Associates reviewed the work of Hupecol’s geophysicists and geologists specifically as it pertained to determining the estimate of productive area and bulk volumes. In our opinion this did not compromise Aluko & Associates’ independence, as third party engineers often are required to rely on information from the hiring company in determining their estimates. Hupecol’s work was reviewed by Aluko and Associates and found to be within reason and accurate. Also, as can be seen in the description above, this was only one of several methods that Aluko & Associates used in determining their estimate of proved reserves. Unfortunately Mr. Aluko passed away in August of 2008 and was not able to assist in our response to this question.
U.S. Securities and Exchange Commission
December 9, 2008
Page 3
3. | We note that, on a net equivalent reserve basis, three of your top four proved undeveloped properties and your top two proved developed non-producing properties are all scheduled for first production by June 1, 2008. Please furnish to us each property’s complete daily production history and describe, in appropriate detail, whether these production volumes support the proved reserve estimates. Address any significant cost overruns. |
Company Response:
Below is a brief description of the current status of the wells you outlined above:
PDNP
Dorotea B2 – on May 31, 2008 this well tested at 760 BOPD. This well was put on production on May 28, 2008, and at November 25, 2008 this well was producing at a current rate of 953 BOPD.
Leona A1 – on April 29, 2007 this well tested at 800 BOPD, but shortly after it was placed on production on September 24, 2007 the electric submersible pump failed and the well was shut in. A re-work of the well is planned after the Leona A2 well is completed.
PUD
Dorotea B3 – on June 17, 2008 this well tested at 2000 + BOPD and was placed on production on June 22, 2008 at 665 BOPD. At November 25, 2008 this well was producing at a current rate of 571 BOPD.
Leona A2 – This well was being completed as of November 25, 2008.
Jaguar T7 – this well and property (Caracara) was sold in June 2008 with an effective date of the sale as of January 1, 2008. The current production and outcome of this well are unknown to us.
No significant cost overruns occurred on any of these wells except for the Leona A2. The total cost accrued on this well is still not known to the Company, as the well is still being completed, but due to stuck pipe we believe that the cost of this well will come in above Aluko and Associates’ estimate. As to the economics, we believe that the wells’ performance supports the reserve estimates except for the Leona A1 well whose results remain to be seen due to mechanical failure of the pump.
U.S. Securities and Exchange Commission
December 9, 2008
Page 4
Risk Factors, page 10
A substantial percentage of our properties are undeveloped; therefore the risk associated with our success is greater than would be the case if the majority of our properties were categorized as proved developed producing, page 11
4. | Please expand this factor to disclose the portion of your proved reserves that are producing as of 2007 year-end. |
Company Response:
The referenced risk factor has been revised to indicate the producing portion at 2007 year-end.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, page 11.
5. | Please expand this factor to include the significant negative revisions to your proved reserves that occurred in the last two years. |
Company Response:
The referenced risk factor has been revised to discuss the significant negative revisions to proved reserves during 2006 and 2007.
Supplemental Information on Oil and Gas Exploration, Development and Production Activities (Unaudited), Page F-19
Reserve Information and Related Standardized Measure of Discounted Future Net Cash Flows, page F-21
6. | FAS 69, paragraph 11 requires “appropriate explanation of significant changes” to proved reserves during the year. We note significant changes to your proved reserves due to extensions and discoveries and due to revisions in 2006 and 2007. Please explain to us how you intend to comply with this requirement. |
Company Response:
The reserve information has been expanded to explain the nature of significant changes in proved reserves during 2006 and 2007.
U.S. Securities and Exchange Commission
December 9, 2008
Page 5
Standard (sic) measure of discounted future net cash flows at December 31, 2007, page F-22
7. | FAS 69, paragraph 30 requires the inclusion of estimated future development costs in the calculation of the standardized measure. It appears that you did not include the development costs - $2.5 million – presented in your third party reserve report. Please explain to us how you intend to comply with this requirement. |
Company Response:
The standardized measure of discounted future net cash flows table at December 31, 2007 mistakenly included future development costs in future income tax. The table has been revised to present future development costs as a separate line item.
Acknowledgements
The Company hereby acknowledges that:
· | the company is responsible for the adequacy and accuracy of the disclosure in the filing; |
· | staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action respect to the filing; 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 Unites States. |
Please address any comments or questions to the undersigned at the address set forth above.
Sincerely, | |
John F. Terwilliger | |
President |
cc: | James Jacobs |
Michael Sanders, Esq. | |
Nelson Haight |