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    corresp.htm

    HOUSTON
AMERICAN ENERGY CORP.

      801
TRAVIS, SUITE 1425

      HOUSTON,
TEXAS 77002

      TELEPHONE
(713) 222-6966

      FACSIMILE
(713) 222-6440

      February
2, 2009

      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 December 9, 2008

      File No.
1-32955

      Dear Ms.
O’Brien:

      Set forth
below are the Staff’s engineering comments, as set forth in the Staff’s letter
dated January 28, 2009, followed by our responses, which are numbered to
correspond with the numbers set forth in the Staff’s comment
letter.

      Business, page
3

      Natural Gas and Oil
Reserves, page 8

                1.

                In
      part, response two in your December 9, 2008 letter states, “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.”  This statement concurs with
      Aluko’s that HUPECOL’s in-house seismic interpretations were used to
      determine productive area and bulk volume per our prior comment
      2.  We do not believe that current seismic interpretation
      technology has sufficient reliability to determine proved volumes without
      the data generated by at least one well penetration of the subject
      reservoir.  Please explain to us
  whether:

                ●

                The
      productive area and bulk volume for any of your proved reserves were
      estimated solely by the use of seismic data interpretation.  If
      true, submit the affected properties and
  reserves;

                ●

                Aluko
      performed significant interpretive analysis before adopting the productive
      area and bulk volume estimates of HUPECOL. Address the efforts/methods to
      determine single well drainage
volumes.

U.S.
Securities and Exchange Commission

      February
2, 2009

      Page
2

      Company
Response:

      Our
proved reserves were NOT estimated solely by the use of seismic
interpretation.  All of our proved undeveloped reserve locations were
based on direct offsets to producing wells.   In performing his
analysis, Aluko used volumetric analysis based upon recoveries of wells in the
basin as well as evidence from producing wells in the immediate
areas.  This analysis of historical decline curves and well histories
was combined to establish decline curves and estimates of our proved
locations.

                2.

                Response
      two also states, “In our opinion this [reliance upon HUPECOL’s seismic
      interpretation] 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.”  The
      information that independent third party engineers rely on are items of
      verifiable fact such as production history or ownership figures, not items
      that require significant technical interpretation.  If Aluko
      adopted seismic interpretations of the operator without significant
      analysis, please modify your disclosure here to inform the public of that
      fact.

      Company
Response:

      While we
believe Aluko reviewed our operators’ seismic interpretations, we do not believe
that Aluko adopted these seismic interpretations without significant
analysis.  We believe that this was only one of the several methods
that he used in establishing the basis for our proved
reserves.  Accordingly, no revisions have been made to disclosure in
our Form 10-K.

                3.

                Response
      three indicates that current production rates for two wells – Dorotea B2
      (953 BOPD) and Dorotea B3 (571 BOPD) – are well below those projected in
      your third party reserve report.  Please explain the technical
      factors that caused this shortfall.

      Company
Response:

      The
Dorotea B2 was estimated to produce 427,000 barrels on an 8/8th basis
for 2008.  The actual production volumes for this well were
significantly reduced throughout the year due to transportation and weather
issues in the field.  Using our proved reserve estimates at the time
of our engineering report at year end 2007, 427,000 barrels for the year results
in an average production rate of 1,170 Boe/d.  We are currently
producing this well at a rate approximately 19% lower then this estimate due to
the well being produced on a reduced choke and slightly less then expected flow
rates which we believe were predominately due to lack of sufficient storage on
location which required the wells to be shut in periodically.

      The
Dorotea B3 was estimated to produce 309,000 barrels on an 8/8th basis
for 2008.  The actual production volumes for this well were
significantly reduced throughout the year due to transportation and weather
issues in the field.  Using our proved reserve estimates at the time
of our engineering report at year end 2007, 309,000 barrels for the year results
in an average production rate of 846 Boe/d.  We are currently
producing this well at a rate approximately 32% lower then this estimate due to
the well being produced on a reduced choke and less then expected flow rates
which we believe were predominately due to lack of sufficient storage on
location which required the wells to be shut in periodically.

      U.S.
Securities and Exchange Commission

      February
2, 2009

      Page
3

      Supplemental Information on
Oil and Gas Exploration, Development and Production Activities (Unaudited), Page
F-19

      Changes in standardized
measure, page F-23

                4.

                We
      note the absence of certain line items prescribed by FAS 69, paragraph 33,
      such as “Previously estimated development costs incurred during the
      period.”  Please amend your document to comply fully with FAS
      69.

      Company
Response:

      We agree
we have incorrectly  combined three of the line items called for by
FAS 69, paragraph 33 in the changes in standardized measure
presentation.  Specifically, we combined the impact of “Previously
estimated development costs incurred during the period” and “Changes in
estimated future development costs” into the line item “Net change in sales and
transfer price, net of production costs.”  Given that no other
revisions to Form 10-K are being made at this time and the fact that we will be
filing our 2008 Form 10-K in less than 45 days, we propose to address this
comment on a prospective basis through corrected disclosure in the 2008 Form
10-K.

      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.

U.S.
Securities and Exchange Commission

      February
2, 2009

      Page
4

      Please
address any comments or questions to the undersigned at the address set forth
above.

                  Sincerely,

                  /s/
      John F. Terwilliger

                  John
      F. Terwilliger

                  President

                cc:

                James
      Jacobs

      Michael
Sanders, Esq.

      Nelson
Haight