Edgar Filing: HOUSTON AMERICAN ENERGY CORP

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-KSB

(MARK ONE)
[X] ANNUAL REPORT UNDER SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934

For the Fiscal Year Ended December 31, 2005

[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934

For the transition period from ____________ to _____________

Commission File No. 0-33027

HOUSTON AMERICAN ENERGY CORP.
(Name of Small Business Issuer in its charter)

Delaware 76-0675953
------------------------------- ------------------------------------
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)

801 Travis Street, Suite 2020
Houston, Texas 77002
--------------------------------------------------
(Address of principal executive offices)(Zip code)

Issuer's telephone number, including area code: (713) 222-6966

Securities to be registered pursuant to Section 12(b) of the Act:

Title of each class Name of each exchange on which each is registered
------------------- -------------------------------------------------
None None

Securities to be registered pursuant to Section 12(g) of the Act:

Common Stock, $0.001 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. [ ]

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 [ ]

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 or any
amendment to this Form 10-KSB. [X]

Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act). Yes [ ] No [X]

The Issuer's revenues for the fiscal year ended December 31, 2005 were
$2,874,648.

The aggregate market value of the voting and non-voting common equity held by
non-affiliates of the registrant on March 29, 2006, based on the last sales
price on the OTC Bulletin Board as of such date, was approximately $26,799,318.

The number of shares of the registrant's common stock, $.001 par value per
share, outstanding as of March 29, 2006 was 19,970,589.

DOCUMENTS INCORPORATED BY REFERENCE

None

Transition Small Business Disclosure Format: Yes [ ] No [X]

TABLE OF CONTENTS

Page
----

PART I

ITEM 1. DESCRIPTION OF BUSINESS. . . . . . . . . . . . 3
ITEM 2. DESCRIPTION OF PROPERTY. . . . . . . . . . . . 17
ITEM 3. LEGAL PROCEEDINGS. . . . . . . . . . . . . . . 17
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF
SECURITY HOLDERS . . . . . . . . . . . . . . . 17

PART II

ITEM 5. MARKET FOR COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS. . . . . . . . . . 18
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS . . . . . 19
ITEM 7. FINANCIAL STATEMENTS . . . . . . . . . . . . . 26
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE . . . . 26
ITEM 8A. CONTROLS AND PROCEDURES. . . . . . . . . . . . 26
ITEM 8B. OTHER INFORMATION. . . . . . . . . . . . . . . 26

PART III

ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND
CONTROL PERSONS; COMPLIANCE WITH
SECTION 16(a) OF THE EXCHANGE ACT. . . . . . . 27
ITEM 10. EXECUTIVE COMPENSATION . . . . . . . . . . . . 29
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT. . . . . . . . . . . . . 30
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 31
ITEM 13. EXHIBITS AND REPORTS OF FORM 8-K . . . . . . . 31
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES . . . . 33

SIGNATURES

FORWARD-LOOKING STATEMENTS

This annual report on Form 10-KSB contains forward-looking statements within the
meaning of the federal securities laws. These forwarding-looking statements
include without limitation statements regarding our expectations and beliefs
about the market and industry, our goals, plans, and expectations regarding our
properties and drilling activities and results, our intentions and strategies
regarding future acquisitions and sales of properties, our intentions and
strategies regarding the formation of strategic relationships, our beliefs
regarding the future success of our properties, our expectations and beliefs
regarding competition, competitors, the basis of competition and our ability to
compete, our beliefs and expectations regarding our ability to hire and retain
personnel, our beliefs regarding period to period results of operations, our
expectations regarding revenues, our expectations regarding future growth and
financial performance, our beliefs and expectations regarding the adequacy of
our facilities, and our beliefs and expectations regarding our financial
position, ability to finance operations and growth and the amount of financing
necessary to support operations. These statements are subject to risks and
uncertainties that could cause actual results and events to differ materially.
We undertake no obligation to update forward-looking statements to reflect
events or circumstances occurring after the date of this annual report on Form
10-KSB.

As used in this annual report on Form 10-KSB, unless the context otherwise
requires, the terms "we," "us," "the Company," and "Houston American" refer to
Houston American Energy Corp., a Delaware corporation.

PART I

ITEM 1. DESCRIPTION OF BUSINESS

GENERAL

Houston American Energy Corp. is an oil and gas exploration and production
company. Our oil and gas exploration and production activities are focused on
properties in the U.S. onshore Gulf Coast Region, principally Texas and
Louisiana, and development of concessions in the South American country of
Colombia. We seek to utilize the contacts and experience of our sole executive
officer, John F. Terwilliger, to identify favorable drilling opportunities, to
use advanced seismic techniques to define prospects and to form partnerships and
joint ventures to spread the cost and risks to us of drilling.

EXPLORATION PROJECTS

Our exploration projects are focused on existing property interests, and future
acquisition of additional property interests, in the onshore Texas Gulf Coast
region, Colombia and Louisiana.

Each of our exploration projects differs in scope and character and consists of
one or more types of assets, such as 3-D seismic data, leasehold positions,
lease options, working interests in leases, partnership or limited liability
company interests or other mineral rights. Our percentage interest in each
exploration project ("Project Interest") represents the portion of the interest
in the exploration project we share with other project partners. Because each
exploration project consists of a bundle of assets that may or may not include a
working interest in the project, our Project Interest simply represents our
proportional ownership in the bundle of assets that constitute the exploration
project. Therefore, our Project Interest in an exploration project should not
be confused with the working interest that we will own when a given well is
drilled. Each exploration project represents a negotiated transaction between
the project partners. Our working interest may be higher or lower than our
Project Interest.

Our principal exploration projects as of December 31, 2005 consisted on the
following:

WEBSTER PARISH, LOUISIANA. In Webster Parish, Louisiana, we hold a 7.5% working
interest at an 8.3% net revenue interest carried to point of sales for the first
well in over 4,000 acres known as the South Sibley Prospect. Drilling of a
10,600-foot well, the first well, on the South Sibley Prospect, was completed in
May 2005 with multiple pay sands apparently identified. Sales from the well
commenced June 28, 2005.

We also hold a 7.5% working interest at a 6.055% net revenue interest in the
Holley #1 well and associated 640-acre unit, acquired in December 2005, in
Webster Parish, Louisiana.

We intend to evaluate additional drilling sites and the drilling of additional
wells on our Webster Parish prospects in 2006.

IBERVILLE PARISH, LOUISIANA. In Iberville Parish, Louisiana, we have agreed,
subject to final review and approval of supporting documentation, to acquire a
6% working interest and a 4.2% net revenue interest subject to a 20% back in at
payout in a 300-acre leasehold known as the Green Jacket Prospect. Subject to
completion of the acquisition of the Green Jacket Prospect, drilling of a
13,200-foot test well is expected to begin in the second half of 2006 to test
multiple sands at a location based on 3D seismic and being adjacent to a well
that produced significant oil from two of the four objective sands.

ACADIA PARISH, LOUISIANA. In Acadia Parish, Louisiana, we hold a 3% working
interest and a 2.25% net revenue interest until payout in a 620-acre leasehold
known as the Crowley Prospect. The Hoffpauer #1 (formerly the Baronet #1) was
drilled in the third quarter of 2004. Commercial production of the well
commenced in December 2004. Drilling of a 12,100-foot well, the Baronet #2
well, on the Crowley Prospect in Acadia Parish, Louisiana was completed in April
2005. The well tested the Hayes Sand and flanks a natural gas well that
produced 1.6 BCF of natural gas from the Hayes Sand. After logging 21-feet of
apparent net pay, hole conditions deteriorated before logging could be
completed. The well was completed and production began in June 2005. Assuming
the Baronet #2 performs consistently, we may drill a developmental well on the
Crowley Prospect during 2006.

VERMILLION PARISH, LOUISIANA. In Vermillion Parish, Louisiana, we hold an 8.25%
working interest with a 6.1875% net revenue interest, subject to a 25% working
interest back in at payout, in the 425 acre Sugarland Prospect. The Broussard
#1 well, a 12,900-foot test well, was drilled on the Sugarland Prospect in
December 2005, with indications of multiple pay sands, and was completed in
January 2006. Sales from the Broussard #1 are expected to begin in March 2006.
We presently have no plans with respect to drilling additional wells on the
Sugarland Prospect.

JIM HOGG COUNTY, TEXAS. In Jim Hogg County, Texas, we hold a 4.375% working
interest, subject to payment of 5.8334% of costs to the casing point in the
first well, in the 500 acre Hog Heaven Prospect. The Weil #1 well, a 6,200-foot
test well, was drilled on the Hog Heaven Prospect in November 2005. Electric
log and sidewall core analysis indicate multiple pay sands in the Weil #1 well
with the well expected to be completed as a natural gas well, with some possible
oil production. The well was completed in January 2006 and production and sales
are expected to commence in March 2006. Based on the initial indications of
multiple pay sands, we intend to evaluate the possible drilling of multiple
offset wells beginning in 2006.

VICTORIA COUNTY, TEXAS. In Victoria County, Texas, we hold a 50% working
interest at a 40% net revenue interest in the Allar #2 well. The well, acquired
in December 2005, was re-completed in January 2006 as a producing gas well. We
presently have no plans to drill additional wells in Victoria County.

WILBARGER COUNTY, TEXAS. In Wilbarger County, Texas, we hold a 15% working
interest with an 11.25% net revenue interest in the 900-acre West Fargo
Prospect. The Riggins #1 well, a 6,400-foot test well, is expected to be
drilled on the Wells Fargo Prospect in April 2006.

We also hold a 15% working interest with an 11.25% net revenue interest in the
1340 acre Obenhaus Prospect in Wilbarger County, Texas. The Obenhaus #1 well,
a 7,200-foot test well, is expected to be drilled on the Obenhaus Prospect in
March 2006.

LLANOS BASIN, COLOMBIA. In the Llanos Basin, Colombia, we hold interests in (1)
a 232,050 acre tract known as the Cara Cara concession, (2) the Tambaqui
Association Contract covering 4,400 acres in the State of Casanare, Colombia,
(3) two concessions, the Dorotea Contract and the Cabiona Contract, totaling
over 136,000 acres, (4) the Surimena concession covering approximately 69,000
acres, (5) the Las Garzas concession covering approximately 103,000 acres, (6)
the Jagueyes Technical Evaluation Agreement ("TEA") covering approximately
324,000 acres, and (7) the Simon TEA covering approximately 166,000 acres.

Our interest in the Cara Cara, Dorotea, Cabiona, Surimena and Las Garzas
concessions and the Jagueyes TEA and Simon TEA are held through an interest in
Hupecol, LLC. We hold a 12.5% working interest in each of the prospects of
Hupecol. In conjunction with our interest in Hupecol, we also acquired, and
hold, a 12.6% working interest, with an 11.31% net revenue interest, in the
Tambaqui Association Contract.

The first well drilled in the Cara Cara concession, the Jaguar #1 well, was
completed in April 2003 with initial production of 892 barrels of oil per day.
In conjunction with the efforts to develop the Cara Cara concession, Hupecol
acquired 50 square miles of 3D seismic grid surrounding the Jaguar #1 well and
other prospect areas. That data is being utilized to identify additional drill
site opportunities to develop a field around the Jaguar #1 well and in other
prospect areas within the grid.

Our working interest in the Cara Cara concession and the Tambaqui Association
Contract are subject to an escalating royalty of 8% on the first 5,000 barrels
of oil per day, increasing to 20% at 125,000 barrels of oil per day. Our
interest in the Tambaqui Association Contract is subject to reversionary
interests of Ecopetrol, the state owned Colombian oil company, that could cause
50% of the working interest to revert to Ecopetrol after we have recouped four
times our initial investment. Our working interest in the additional
concessions is subject to an escalating royalty ranging from 8% to 20% depending
upon production volumes and pricing and an additional 6% to 10% per concession
when 5,000,000 barrels of oil have been produced on that concession.

In December 2003, we exercised our right to participate in the acquisition,
through Hupecol, of over 3,000 kilometers of seismic data in Colombia covering
in excess of 20 million acres. The seismic data is being utilized to map
prospects in key areas with a view to delineating multiple drilling
opportunities. We will hold a 12.5% interest in all prospects developed by
Hupecol arising from the acquired seismic data, including the Cabiona and
Dorotea concessions acquired in the fourth quarter of 2004, the Surimena
concession acquired in the second quarter of 2005, the Las Garzas concession
acquired in November 2005, the Jagueyes TEA acquired in May 2005 and the Simon
TEA acquired in June 2005. We plan to acquire, during 2006, 3D seismic data on
the Las Garzas contract, the Jagueyes TEA and the Simon TEA in order to further
delineate drilling opportunities on those prospects.

During 2005, Hupecol drilled 9 wells on the Cara Cara concession in Colombia to
offset, and delineate, the Jaguar #1 well, with production commencing on the
Bengala #4, #5, #6, #7ST and #8 and the Jaguar #5, #T5, #T6 and #7. We hold a
1.59% working interest in each of the wells subject to a 30% reversionary
interest to Ecopetrol at payout. During 2005, seismic surveying was undertaken
on the Cara Cara concession to delineate additional drilling prospects on the
concession. Through Hupecol, we presently plan to drill an additional 10 wells
on the Cara Cara concession during 2006.

During 2005, the Tambaqui #5 was drilled and began production under the Tambaqui
Association Contract. We hold a 12.6% working interest in the well. In
December 2005, we relinquished all acreage under the Tambaqui Association
Contract with the exception of 4,403 acres around the producing wells. We
presently have no plans to drill additional wells under the Tambaqui Association
Contract during 2006.

During 2005, seismic surveying was undertaken on the Dorotea and Cabiona
concessions to establish drilling prospect locations. We are permitting 30
drilling locations on the Dorotea and Cabiona concessions and, subject to
securing an additional drilling rig, plan to drill 1 well on the Cabiona
concession and 1 well on the Dorotea concession during 2006.

Based on 2D seismic interpretation, and rig availability, we plan to begin
drilling the Surimena concession during the first half of 2006.

In addition to our principal exploration projects, we hold various interests in
producing wells in Vermillion Parish, Louisiana, Plaquemines Parish, Louisiana,
Lavaca County, Texas, Matagorda County, Texas, San Patricio County, Texas and
Ellis County, Oklahoma. We have no present plans to conduct additional drilling
activities on those prospects.

The following table sets forth certain information about each of our exploration
projects:

Acres Leased or Under Option at December 31, 2005(1)
--------------------------------------------------------
Project
Project Area Project Gross Project Net Company Net Interest
------------------------------ ------------------ ---------------- ------------------ ---------

TEXAS:
Jim Hogg County. . . . . . . . 500.00 500.0 21.88 4.38%
Wilbarger County
West Fargo Prospect. . . . . 900.00 900.00 135.00 15.00%
Obenhaus Prospect. . . . . . 1,340.00 1,340.00 201.00 15.00%
Lavaca County
Mavis Wharton. . . . . . . . 300.00 150.00 7.50 5.00%
West Hardys Creek. . . . . . 65.65 65.65 24.95 38.00%
San Patricio County. . . . . . 380.00 380.00 19.00 5.00%
Matagorda County
S.W. Pheasant Prospect . . . 779.00 779.00 27.27 3.50%
Turtle Creek Prospect. . . . 672.00 672.00 23.52 3.50%
Nacogdoches County . . . . . . 80.94 80.94 80.94 100.00%
Victoria County. . . . . . . . 58.37 58.37 29.18 50.00%
------------------ ---------------- ------------------
Texas Sub-Total. . . . . . . . 5,075.96 4,925.96 570.24
LOUISIANA:
Webster Parish . . . . . . . . 6,244.00 4,457.00 334.28 7.50%
Iberville Parish . . . . . . . 300.65 300.65 18.04 6.00%
Vermillion Parish
Sugarland Prospect . . . . . 425.00 425.00 35.06 8.25%
LaFurs F-16 Well . . . . . . 830.00 830.00 18.68 2.25%
Acadia Parish. . . . . . . . . 620.00 620.00 18.60 3.00%
Plaquemines Parish . . . . . . 300.00 300.00 5.40 1.80%
------------------ ---------------- ------------------
Louisiana Sub-Total. . . . . . 8,719.65 6,932.65 430.06
OKLAHOMA
Jenny #1-14. . . . . . . . . . 160.00 160.00 3.78 2.36%
------------------ ---------------- ------------------
Oklahoma Sub-Total . . . . . . 160.00 160.00 3.78
COLOMBIA
Cara Cara Concession . . . . 232,050.00 232,500.00 3,689.00 1.59%
Tambaqui Assoc. Contract (2) 4,403.00 4,403.00 555.00 12.6%
Dorotea Concession . . . . . 51,321.00 51,321.00 6,415.00 12.5%
Cabiona Concession . . . . . 86,066.00 86,066.00 10,758.00 12.5%
Surimena Concession. . . . . 69,189.00 69,189.00 8,649.00 12.5%
Las Garzas Concession. . . . 103,784.00 103,784.00 12,973.00 12.5%
Jagueyes TEA . . . . . . . . 324,695.00 324,695.00 40,587.00 12.5%
Simon TEA. . . . . . . . . . 166,301.00 166,301.00 20,788.00 12.5%
------------------ ---------------- ------------------
Colombia Sub-Total . . . . . . 1,037,809.00 1,037,809.00 104,414.00
------------------ ---------------- ------------------
Total. . . . . . . . . . . . . 1,051,764.61 1,049,827.61 105,418.08
================== ================ ==================

(1) Project Gross Acres refers to the number of acres within a project. Project
Net Acres refers to leaseable acreage by tract. Company Net Acres are
either leased or under option in which we own an undivided interest.
Company Net Acres were determined by multiplying the Project Net Acres
leased or under option times our working interest therein.

(2) The project interest is the working interest in the concession and not
necessarily the working interest in the well.

DRILLING ACTIVITIES

In 2005, we drilled 4 exploratory and 10 developmental wells of which all 14
were completed and none were dry holes. In 2004, 9 exploratory and 7
developmental wells were drilled of which 11 were completed and 5 were dry
holes.

The following table sets forth certain information regarding the actual drilling
results for each of the years 2004 and 2005 as to wells drilled in each such
individual year:

Exploratory Wells (1) Developmental Wells (1)
----------------------- -------------------------
Gross Net Gross Net
---------- ----------- --------- --------------

2004
----
Productive 4 0.128 7 0.220
Dry. . . . 5 0.238 0 0
2005
----
Productive 4 0.231 10 0.226
Dry. . . . 0 0 0 0

(1) Gross wells represent the total number of wells in which we owned an
interest; net wells represent the total of our net working interests owned
in the wells.

One well was in progress at December 31, 2005 on the Cara Cara prospect.

PRODUCTIVE WELL SUMMARY

The following table sets forth certain information regarding our ownership as of
December 31, 2005 of productive gas and oil wells in the areas indicated:

Gas Oil
---------------------- ----------------------
Gross Net Gross Net
---------- ---------- ---------- ----------

Texas . . . . . . . 6 0.934 0 0
Louisiana . . . . . 7 0.333 0 0
Oklahoma. . . . . . 1 0.024 0 0
Colombia. . . . . . 0 0 17 0.419
---------- ---------- ---------- ----------
Total . . . . . 14 1.291 17 0.419
========== ========== ========== ==========

VOLUME, PRICES AND PRODUCTION COSTS

The following table sets forth certain information regarding the production
volumes, average prices received (net of transportation costs) and average
production costs associated with our sales of gas and oil for the periods
indicated:

Year Ended December 31,
-------------------------
2004 2005
------------ -----------

Net Production:

Gas (Mcf):
North America . . . . . 61,519 106,449
South America . . . . . 0 0

Oil (Bbls):
North America . . . . . 886 1,396
South America . . . . . 24,040 42,789

Average sales price:

Gas ($per Mcf). . . . . . 5.43 7.83
Oil (Bbls). . . . . . . . 33.31 47.89

Average production expense and
Taxes ($per Bbls):
North America . . . . . 5.08 4.16
South America . . . . . 16.15 20.43

NATURAL GAS AND OIL RESERVES

The following table summarizes the estimates of our historical net proved
reserves as of December 31, 2004 and 2005, and the present value attributable to
these reserves at these dates. The reserve data and present values were
prepared by Pressler Petroleum Consultants, Inc., independent petroleum
engineering consultants:

At December 31,
2004 2005
---------- ----------

Net proved reserves (1):
Natural gas (Mcf). . . . . . . . . . . . 202,420 850,650
Oil (Bbls) . . . . . . . . . . . . . . . 307,290 273,421
Standardized measure of discounted future net
cash flows (2) . . . . . . . . . . . . . . . $4,005,624 $6,375,600

(1) At December 31, 2005, net proved reserves, by region, consisted of 270,621
barrels of oil in South America and 2,800 barrels of oil in North America;
all natural gas reserves were in North America.

(2) The standardized measure of discounted future net cash flows represents the
present value of future net revenues after income tax discounted at 10% per
annum and has been calculated in accordance with SFAS No. 69, "Disclosures
About Oil and Gas Producing Activities" (see Note 7 - Supplemental
Information on Oil and Gas Exploration, Development and Production
Activities (Unaudited)) and, in accordance with current SEC guidelines, and
does not include estimated future cash inflows from hedging. The
standardized measure of discounted future net cash flows attributable to
our reserves was prepared using prices in effect at the end of the
respective periods presented, discounted at 10% per annum on a pre-tax
basis.

In accordance with applicable requirements of the Securities and Exchange
Commission, we estimate our proved reserves and future net cash flows using
sales prices and costs estimated to be in effect as of the date we make the
reserve estimates. We hold the estimates constant throughout the life of the
properties, except to the extent a contract specifically provides for
escalation. Gas prices, which have fluctuated widely in recent years, affect
estimated quantities of proved reserves and future net cash flows. Any
estimates of natural gas and oil reserves and their values are inherently
uncertain, including many factors beyond our control. The reserve data
contained in this report represent only estimates. Reservoir engineering is a
subjective process of estimating underground accumulations of natural gas and
oil that cannot be measured in an exact manner. The accuracy of reserve
estimates

is a function of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates of different engineers,
including those we use, may vary. In addition, estimates of reserves may be
revised based upon actual production, results of future development and
exploration activities, prevailing natural gas and oil prices, operating costs
and other factors, which revision may be material. Accordingly, reserve
estimates may be different from the quantities of natural gas and oil that we
are ultimately able to recover and are highly dependent upon the accuracy of the
underlying assumptions. Our estimated proved reserves have not been filed with
or included in reports to any federal agency.

LEASEHOLD ACREAGE

The following table sets forth as of December 31, 2005, the gross and net acres
of proved developed and proved undeveloped and unproven gas and oil leases which
we hold or have the right to acquire:

Proved Developed Proved Undeveloped Unproven
------------------ -------------------- ------------------------
Gross Net Gross Net Gross Net
-------- -------- ---------- -------- ------------ ----------

Texas . . 1,593.02 114.90 340.00 14.88 2,992.94 440.46
Louisiana 3,145.00 164.44 310.00 9.30 3,477.65 256.32
Oklahoma. 160.00 3.78 0 0 0 0
Colombia. 2,720.00 78.48 1760.00 27.98 1,033,329.00 104,307.54
-------- -------- ---------- -------- ------------ ----------
Total 7,618.02 357.82 2410.00 52.16 1,039,799.59 105,004.32
======== ======== ========== ======== ============ ==========

During 2005, we acquired interests in (1) the 4,000+ acre South Sibley Prospect,
(2) the Holley #1 well and 640 acre unit, (3) the 300 acre Green Jacket
Prospect, (4) the 425 acre Sugarland Prospect, (5) the 500 acre Hog Heaven
Prospect, (6) the 900 acre West Fargo Prospect, (7) the 1,340 acre Obenhaus
Prospect, (8) the Allar #2 well and associated acreage, (9) the 69,189 acre
Surimena concession in Colombia, (10) the 103,784 acre Las Garzas concession in
Colombia, (11) the 324,695 acre Jagueyes TEA in Colombia, and (12) the 166,301
Simon TEA in Colombia. Also, during 2005, we relinquished (1) all acreage
(approximately 84,000 acres) in the Tambaqui Association Contract, other than
4,403 acres around the producing wells, (2) the 194 acre Donner Field lease in
Terrebone Parish, Louisiana, (3) the 726 acre Bougere Estate lease and Bougere
#1 well in St. John the Baptist Parish, Louisiana, and (4) approximately 1,668
acres of leaseholds in North Louisiana.

TITLE TO PROPERTIES

Title to properties is subject to royalty, overriding royalty, carried working,
net profits, working and other similar interests and contractual arrangements
customary in the gas and oil industry, liens for current taxes not yet due and
other encumbrances. As is customary in the industry in the case of undeveloped
properties, little investigation of record title is made at the time of
acquisition (other than preliminary review of local records).

Investigation, including a title opinion of local counsel, generally are made
before commencement of drilling operations.

MARKETING

At March 29, 2006, we had no contractual agreements to sell our gas and oil
production and all production was sold on spot markets.

RISKS RELATED TO OUR BUSINESS AND STOCK

Our business activities and the value of our securities are subject to
significant hazards and risks, including those described below. If any of such
events should occur, our business, financial condition, liquidity and/or results
of operations could be materially harmed, and holders and purchasers of our
securities could lose part or all of their investments.

A SUBSTANTIAL OR EXTENDED DECLINE IN OIL AND NATURAL GAS PRICES MAY
ADVERSELY AFFECT OUR BUSINESS, FINANCIAL CONDITION OR RESULTS OF OPERATIONS AND
OUR ABILITY TO MEET OUR CAPITAL EXPENDITURE OBLIGATIONS AND FINANCIAL
COMMITMENTS.

The price we receive for our oil and natural gas production heavily
influences our revenue, profitability, access to capital and future rate of
growth. Oil and natural gas are commodities and, therefore, their prices are
subject to wide fluctuations in response to relatively minor changes in supply
and demand. Historically, the markets for oil and natural gas have been
volatile. These markets will likely continue to be volatile in the future. The
prices we receive for our production, and the levels of our production, depend
on numerous factors beyond our control. These factors include, but are not
limited to, the following:

- changes in global supply and demand for oil and natural gas;
- the actions of the Organization of Petroleum Exporting Countries, or
OPEC;
- the price and quantity of imports of foreign oil and natural gas;
- political conditions, including embargoes, in or affecting other
oil-producing activity;
- the level of global oil and natural gas exploration and production
activity;
- the level of global oil and natural gas inventories;
- weather conditions;
- technological advances affecting energy consumption; and
- the price and availability of alternative fuels.

Lower oil and natural gas prices may not only decrease our revenues on a
per unit basis but also may reduce the amount of oil and natural gas that we can
produce economically. Lower prices will also negatively impact the value of our
proved reserves. A substantial or extended decline in oil or natural gas prices
may materially and adversely affect our future business, financial condition,
results of operations, liquidity or ability to finance planned capital
expenditures.

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.

Because a substantial percentage of our properties are unproven
(approximately 99%), or proved undeveloped, we will require significant
additional capital to prove and develop such properties before they may become
productive. Further, because of the inherent uncertainties associated with
drilling for oil and gas, some of these properties may never be developed to the
extent that they result in positive cash flow. Even if we are successful in our
development efforts, it could take several years for a significant portion of
our undeveloped properties to be converted to positive cash flow.

While our current business plan is to fund the development costs with cash
flow from our other producing properties, if such cash flow is not sufficient we
may be forced to seek alternative sources for cash, through the issuance of
additional equity or debt securities, increased borrowings or other means.

DRILLING FOR AND PRODUCING OIL AND NATURAL GAS ARE HIGH RISK ACTIVITIES
WITH MANY UNCERTAINTIES THAT COULD ADVERSELY AFFECT OUR BUSINESS, FINANCIAL
CONDITION OR RESULTS OF OPERATIONS.

Our future success will depend on the success of our exploitation,
exploration, development and production activities. Our oil and natural gas
exploration and production activities are subject to numerous risks beyond our
control, including the risk that drilling will not result in commercially viable
oil or natural gas production. Our decisions to purchase, explore, develop or
otherwise exploit prospects or properties will depend in part on the evaluation
of data obtained through geophysical and geological analyses, production data
and engineering studies, the results of which are often inconclusive or subject
to varying interpretations. Please read "-Reserve estimates depend on many
assumptions that may turn out to be inaccurate" (below) for a discussion of the
uncertainty involved in these processes. Our cost of drilling, completing and
operating wells is often uncertain before drilling commences. Overruns in
budgeted expenditures are common risks that can make a particular project
uneconomical. Further, many factors may curtail, delay or cancel drilling,
including the following:

- delays imposed by or resulting from compliance with regulatory
requirements;
- pressure or irregularities in geological formations;
- shortages of or delays in obtaining equipment and qualified personnel;
- equipment failures or accidents;
- adverse weather conditions;
- reductions in oil and natural gas prices;
- title problems; and
- limitations in the market for oil and natural gas.

IF OIL AND NATURAL GAS PRICES DECREASE, WE MAY BE REQUIRED TO TAKE WRITE-DOWNS
OF THE CARRYING VALUES OF OUR OIL AND NATURAL GAS PROPERTIES, POTENTIALLY
NEGATIVELY IMPACTING THE TRADING VALUE OF OUR SECURITIES.

Accounting rules require that we review periodically the carrying value of
our oil and natural gas properties for possible impairment. Based on specific
market factors and circumstances at the time of prospective impairment reviews,
and the continuing evaluation of development plans, production data, economics
and other factors, we may be required to write down the carrying value of our
oil and natural gas properties. A write-down could constitute a non-cash charge
to earnings. It is likely the cumulative effect of a write-down could also
negatively impact the trading price of our securities.

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.

The process of estimating oil and natural gas reserves is complex. It
requires interpretations of available technical data and many assumptions,
including assumptions relating to economic factors. Any significant inaccuracies
in these interpretations or assumptions could materially affect the estimated
quantities and present value of reserves shown in this report.

In order to prepare our estimates, we must project production rates and
timing of development expenditures. We must also analyze available geological,
geophysical, production and engineering data. The extent, quality and
reliability of this data can vary. The process also requires economic
assumptions about matters such as oil and natural gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds.
Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable oil
and natural gas reserves most likely will vary from our estimates. Any
significant variance could materially affect the estimated quantities and
present value of our reserves. In addition, we may adjust estimates of proved
reserves to reflect production history, results of exploration and development,
prevailing oil and natural gas prices and other factors, many of which are
beyond our control.

You should not assume that the present value of future net revenues from
our proved reserves, as reported from time to time, is the current market value
of our estimated oil and natural gas reserves. In accordance with SEC
requirements, we generally base the estimated discounted future net cash flows
from our proved reserves on prices and costs on the date of the estimate. Actual
future prices and costs may differ materially from those used in the present
value estimate. If future values decline or costs increase it could negatively
impact our ability to finance operations, and individual properties could cease
being commercially viable, affecting our decision to continue operations on
producing properties or to attempt to develop properties. All of these factors
would have a negative impact on earnings and net income, and most likely the
trading price of our securities.

WE ARE DEPENDENT UPON THIRD PARTY OPERATORS OF OUR OIL AND GAS PROPERTIES.

Under the terms of the Operating Agreements related to our oil and gas
properties, third parties act as the operator of our oil and gas wells and
control the drilling activities to be conducted on our properties. Therefore, we
have limited control over certain decisions related to activities on our
properties, which could affect our results of operations. Decisions over which
we have limited control include:

- the timing and amount of capital expenditures;
- the timing of initiating the drilling and recompleting of wells;
- the extent of operating costs; and
- the level of ongoing production.

PROSPECTS THAT WE DECIDE TO DRILL MAY NOT YIELD OIL OR NATURAL GAS IN
COMMERCIALLY VIABLE QUANTITIES.

Our prospects are properties on which we have identified what we believe,
based on available seismic and geological information, to be indications of oil
or natural gas. Our prospects are in various stages of evaluation, ranging from
a prospect that is ready to drill to a prospect that will require substantial
additional seismic data processing and interpretation. There is no way to
predict in advance of drilling and testing whether any particular prospect will
yield oil or natural gas in sufficient quantities to recover drilling or
completion costs or to be economically viable. This risk may be enhanced in our
situation, due to the fact that a significant percentage (99%) of our reserves
are currently unproved reserves. The use of seismic data and other technologies
and the study of producing fields in the same area will not enable us to know
conclusively prior to drilling whether oil or natural gas will be present or, if
present, whether oil or natural gas will be present in commercial quantities. We
cannot assure you that the analogies we draw from available data from other
wells, more fully explored prospects or producing fields will be applicable to
our drilling prospects.

WE MAY INCUR SUBSTANTIAL LOSSES AND BE SUBJECT TO SUBSTANTIAL LIABILITY CLAIMS
AS A RESULT OF OUR OIL AND NATURAL GAS OPERATIONS.

We are not insured against all risks. Losses and liabilities arising from
uninsured and underinsured events could materially and adversely affect our
business, financial condition or results of operations. Our oil and natural gas
exploration and production activities are subject to all of the operating risks
associated with drilling for and producing oil and natural gas, including the
possibility of:

- environmental hazards, such as uncontrollable flows of oil, natural
gas, brine, well fluids, toxic gas or other pollution into the
environment, including groundwater and shoreline contamination;
- abnormally pressured formations;
- mechanical difficulties, such as stuck oil field drilling and service
tools and casing collapse;
- fires and explosions;
- personal injuries and death; and
- natural disasters.

Any of these risks could adversely affect our ability to conduct operations
or result in substantial losses to our company. We may elect not to obtain
insurance if we believe that the cost of available insurance is excessive
relative to the risks presented. In addition, pollution and environmental risks
generally are not fully insurable. If a significant accident or other event
occurs and is not fully covered by insurance, then it could adversely affect us.

WE ARE SUBJECT TO COMPLEX LAWS THAT CAN AFFECT THE COST, MANNER OR FEASIBILITY
OF DOING BUSINESS.

Exploration, development, production and sale of oil and natural gas are
subject to extensive federal, state, local and international regulation. We may
be required to make large expenditures to comply with governmental regulations.
Matters subject to regulation include:

- discharge permits for drilling operations;
- drilling bonds;
- reports concerning operations;
- the spacing of wells;
- unitization and pooling of properties; and
- taxation.

Under these laws, we could be liable for personal injuries, property damage
and other damages. Failure to comply with these laws also may result in the
suspension or termination of our operations and subject us to administrative,
civil and criminal penalties. Moreover, these laws could change in ways that
substantially increase our costs. Any such liabilities, penalties, suspensions,
terminations or regulatory changes could materially adversely affect our
financial condition and results of operations.

OUR OPERATIONS MAY INCUR SUBSTANTIAL LIABILITIES TO COMPLY WITH THE
ENVIRONMENTAL LAWS AND REGULATIONS.

Our oil and natural gas operations are subject to stringent federal, state
and local laws and regulations relating to the release or disposal of materials
into the environment or otherwise relating to environmental protection. These
laws and regulations may require the acquisition of a permit before drilling
commences, restrict the types, quantities and concentration of substances that
can be released into the environment in connection with drilling and production
activities, limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas, and impose substantial
liabilities for pollution resulting from our operations. Failure to comply with
these laws and regulations may result in the assessment of administrative, civil
and criminal penalties, incurrence of investigatory or remedial obligations or
the imposition of injunctive relief. Changes in environmental laws and
regulations occur frequently, and any changes that result in more stringent or
costly waste handling, storage, transport, disposal or cleanup requirements
could require us to make significant expenditures to maintain compliance, and
may otherwise have a material adverse effect on our results of operations,
competitive position or financial condition as well as the industry in general.
Under these environmental laws and regulations, we could be held strictly liable
for the removal or remediation of previously released materials or property
contamination regardless of whether we were responsible for the release or if
our operations were standard in the industry at the time they were performed.

OUR OPERATIONS IN COLOMBIA ARE SUBJECT TO RISKS RELATING TO POLITICAL AND
ECONOMIC INSTABILITY.

We currently have interests in multiple oil and gas concessions in Colombia
and anticipate that operations in Colombia will constitute a substantial element
of our strategy going forward. The political climate in Colombia is unstable
and could be subject to radical change over a very short period of time. In the
event of a significant negative change in the political or economic climate in
Colombia, we may be forced to abandon or suspend our operations in Colombia.

UNLESS WE REPLACE OUR OIL AND NATURAL GAS RESERVES, OUR RESERVES AND PRODUCTION
WILL DECLINE, WHICH WOULD ADVERSELY AFFECT OUR CASH FLOWS AND INCOME.

Unless we conduct successful development, exploitation and exploration
activities or acquire properties containing proved reserves, our proved reserves
will decline as those reserves are produced. Producing oil and natural gas
reservoirs generally are characterized by declining production rates that vary
depending upon reservoir characteristics and other factors. Our future oil and
natural gas reserves and production, and, therefore our cash flow and income,
are highly dependent on our success in efficiently developing and exploiting our
current reserves and economically finding or acquiring additional recoverable
reserves. If we are unable to develop, exploit, find or acquire additional
reserves to replace our current and future production, our cash flow and income
will decline as production declines, until our existing properties would be
incapable of sustaining commercial production.

OUR SUCCESS DEPENDS ON OUR MANAGEMENT TEAM AND OTHER KEY PERSONNEL, THE LOSS OF
ANY OF WHOM COULD DISRUPT OUR BUSINESS OPERATIONS.

Our success will depend on our ability to retain John F. Terwilliger, our
sole executive officer, and to attract other experienced management and
non-management employees, including engineers, geoscientists and other technical
and professional staff. We will depend, to a large extent, on the efforts,
technical expertise and continued employment of such personnel and members of
our management team. If members of our management team should resign or we are
unable to attract the necessary personnel, our business operations could be
adversely affected.

THE UNAVAILABILITY OR HIGH COST OF DRILLING RIGS, EQUIPMENT, SUPPLIES, PERSONNEL
AND OIL FIELD SERVICES COULD ADVERSELY AFFECT OUR ABILITY TO EXECUTE ON A TIMELY
BASIS OUR EXPLORATION AND DEVELOPMENT PLANS WITHIN OUR BUDGET.

Shortages or the high cost of drilling rigs, equipment, supplies or
personnel could delay or adversely affect our development and exploration
operations. As the price of oil and natural gas increases, the demand for
production equipment and personnel will likely also increase, potentially
resulting, at least in the near-term, in shortages of equipment and personnel.
In addition, larger producers may be more likely to secure access to such
equipment by virtue of offering drilling companies more lucrative terms. If we
are unable to acquire access to such resources, or can obtain access only at
higher prices, not only would this potentially delay our ability to convert our
reserves into cash flow, but could also significantly increase the cost of
producing those reserves, thereby negatively impacting anticipated net income.

IF OUR ACCESS TO MARKETS IS RESTRICTED, IT COULD NEGATIVELY IMPACT OUR
PRODUCTION, OUR INCOME AND ULTIMATELY OUR ABILITY TO RETAIN OUR LEASES.

Market conditions or the unavailability of satisfactory oil and natural gas
transportation arrangements may hinder our access to oil and natural gas markets
or delay our production. The availability of a ready market for our oil and
natural gas production depends on a number of factors, including the demand for
and supply of oil and natural gas and the proximity of reserves to pipelines and
terminal facilities. Our ability to market our production depends in substantial
part on the availability and capacity of gathering systems, pipelines and
processing facilities owned and operated by third parties. Our failure to obtain
such services on acceptable terms could materially harm our business.

We may operate in areas with limited or no access to pipelines, thereby
necessitating delivery by other means, such as trucking, or requiring
compression facilities. Such restrictions on our ability to sell our oil or
natural gas have several adverse affects, including higher transportation costs,
fewer potential purchasers (thereby potentially resulting in a lower selling
price) or, in the event we were unable to market and sustain production from a
particular lease for an extended time, possibly causing us to lose a lease due
to lack of production.

WE MAY NEED ADDITIONAL FINANCING TO SUPPORT OPERATIONS AND FUTURE CAPITAL
COMMITMENTS.

While we presently believe that our operating cash flows and funds on hand
will support our ongoing operations and anticipated future capital requirements,
a number of factors could result in our needing additional financing, including
reductions in oil and natural gas prices, declines in production, unexpected
developments in operations that could decrease our revenues, increase our costs
or require additional capital contributions and commitments to new acquisition
or drilling programs. We have no commitments to provide any additional
financing, if needed, and may be limited in our ability to obtain the capital
necessary to support operations, complete development, exploitation and
exploration programs or carry out new acquisition or drilling programs. We have
not thoroughly investigated whether this capital would be available, who would
provide it, and on what terms. If we are unable, on acceptable terms, to raise
the required capital, our business may be seriously harmed or even terminated.

COMPETITION IN THE OIL AND NATURAL GAS INDUSTRY IS INTENSE, WHICH MAY ADVERSELY
AFFECT OUR ABILITY TO COMPETE.

We operate in a highly competitive environment for acquiring properties,
marketing oil and natural gas and securing trained personnel. Many of our
competitors possess and employ financial, technical and personnel resources
substantially greater than ours, which can be particularly important in the
areas in which we operate. Those companies may be able to pay more for
productive oil and natural gas properties and exploratory prospects and to
evaluate, bid for and purchase a greater number of properties and prospects than
our financial or personnel resources permit. Our ability to acquire additional
prospects and to find and develop reserves in the future will depend on our
ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. Also, there is substantial
competition for capital available for investment in the oil and natural gas
industry. We may not be able to compete successfully in the future in acquiring
prospective reserves, developing reserves, marketing hydrocarbons, attracting
and retaining quality personnel and raising additional capital.

THE PRICE OF OUR COMMON STOCK MAY FLUCTUATE SIGNIFICANTLY, AND THIS MAY MAKE IT
DIFFICULT FOR YOU TO RESELL COMMON STOCK WHEN YOU WANT OR AT PRICES YOU FIND
ATTRACTIVE.

The price of our common stock quoted on the OTCBB constantly changes. We
expect that the market price of our common stock will continue to fluctuate.

Our stock price may fluctuate as a result of a variety of factors, many of
which are beyond our control. These factors include:

- quarterly variations in our operating results;
- operating results that vary from the expectations of management,
securities analysts and investors;
- changes in expectations as to our future financial performance;
- announcements by us, our partners or our competitors of leasing and
drilling activities;
- the operating and securities price performance of other companies that
investors believe are comparable to us;
- future sales of our equity or equity-related securities;
- changes in general conditions in our industry and in the economy, the
financial markets and the domestic or international political
situation;
- fluctuations in oil and gas prices;
- departures of key personnel; and
- regulatory considerations.

In addition, in recent years, the stock market in general has experienced
extreme price and volume fluctuations. This volatility has had a significant
effect on the market price of securities issued by many companies for reasons
often unrelated to their operating performance. These broad market fluctuations
may adversely affect our stock price, regardless of our operating results.

SHARES OF OUR COMMON STOCK MAY BE "PENNY STOCKS".

If the market price per share of our common stock is less than $5.00, the
shares of our common stock will be "penny stocks" as defined in the Exchange
Act. As a result, an investor may find it more difficult to dispose of or obtain
accurate quotations as to the price of the shares of our common stock. In
addition, the "penny stock" rules adopted by the SEC under the Exchange Act
subject the sale of shares of our common stock to regulations which impose sales
practice requirements on broker-dealers. For example, broker-dealers selling
penny stocks must, prior to effecting the transaction, provide their customers
with a document that discloses the risks of investing in penny stocks.

Furthermore, if the person purchasing the securities is someone other than
an accredited investor or an established customer of the broker-dealer, the
broker-dealer must also approve the potential customer's account by obtaining
information concerning the customer's financial situation, investment experience
and investment objectives. The broker-dealer must also make a determination
whether the transaction is suitable for the customer and whether the customer
has sufficient knowledge and experience in financial matters to be reasonably
expected to be capable of evaluating the risk of transactions in penny stocks.
Accordingly, the SEC's rules may limit the number of potential purchasers of
shares of our common stock. Moreover, various state securities laws impose
restrictions on transferring "penny stocks," and, as a result, investors in our
common stock may have their ability to sell their shares impaired.

THE SALE OF A SUBSTANTIAL NUMBER OF SHARES OF OUR COMMON STOCK MAY AFFECT OUR
STOCK PRICE.

Future sales of substantial amounts of our common stock or equity-related
securities in the public market or privately, or the perception that such sales
could occur, could adversely affect prevailing trading prices of our common
stock and could impair our ability to raise capital through future offerings of
equity or equity-related securities. No prediction can be made as to the
effect, if any, that future sales of shares of common stock or the availability
of shares of common stock for future sale, will have on the trading price of our
common stock.

OUR CHARTER AND BYLAWS, AS WELL AS PROVISIONS OF DELAWARE LAW, COULD MAKE IT
DIFFICULT FOR A THIRD PARTY TO ACQUIRE OUR COMPANY AND ALSO COULD LIMIT THE
PRICE THAT INVESTORS ARE WILLING TO PAY IN THE FUTURE FOR SHARES OF OUR COMMON
STOCK.

Delaware corporate law and our charter and bylaws contain provisions that
could delay, deter or prevent a change in control of our company or our
management. These provisions could also discourage proxy contests and make it
more difficult for our stockholders to elect directors and take other corporate
actions without the concurrence of our management or board of directors. These
provisions:

- authorize our board of directors to issue "blank check" preferred
stock, which is preferred stock that can be created and issued by our
board of directors, without stockholder approval, with rights senior
to those of our common stock;
- provide for a staggered board of directors and three-year terms for
directors, so that no more than one-third of our directors could be
replaced at any annual meeting;
- provide that directors may be removed only for cause; and
- establish advance notice requirements for submitting nominations for
election to the board of directors and for proposing matters that can
be acted upon by stockholders at a meeting.

We are also subject to anti-takeover provisions under Delaware law, which
could also delay or prevent a change of control. Taken together, these
provisions of our charter and bylaws, Delaware law may discourage transactions
that otherwise could provide for the payment of a premium over prevailing market
prices of our common stock and also could limit the price that investors are
willing to pay in the future for shares of our common stock.

OUR MANAGEMENT OWNS A SIGNIFICANT AMOUNT OF OUR COMMON STOCK, GIVING THEM
INFLUENCE OR CONTROL IN CORPORATE TRANSACTIONS AND OTHER MATTERS, AND THEIR
INTERESTS COULD DIFFER FROM THOSE OF OTHER SHAREHOLDERS.

At March 29, 2006, our directors and executive officer, owned approximately
64.2 percent of our outstanding common stock. As a result, our current
directors and executive officer are in a position to significantly influence or
control the outcome of matters requiring a shareholder vote, including the
election of directors, the adoption of any amendment to our certificate of
incorporation or bylaws, and the approval of mergers and other significant
corporate transactions. Such level of control of the company may delay or
prevent a change of control on terms favorable to the other shareholders and may
adversely affect the voting and other rights of other shareholders.

EMPLOYEES

As of March 29, 2006, we had 1 full-time employee and no part time employees.
The employee is not covered by a collective bargaining agreement, and we do not
anticipate that any of our future employees will be covered by such agreement.
If our operations continue to grow as expected, we anticipate hiring as many as
2 additional employees by the end of 2006.

ITEM 2. DESCRIPTION OF PROPERTY

We currently lease approximately 2,000 square feet of office space in Houston,
Texas as our executive offices. Management anticipates that our space will be
sufficient for the foreseeable future. The monthly rental under the lease,
which expires on November 30, 2006, is $3,302.59.

A description of our interests in oil and gas properties is included in "Item 1.
Description of Business."

ITEM 3. LEGAL PROCEEDINGS

During the fourth quarter of 2005, our settlement agreement with the bankruptcy
estate of Moose Oil and Gas Company became final. Pursuant to the settlement,
we paid $25,000 to the estate in full and final settlement of all claims
asserted against us.

We may from time to time be a party to lawsuits incidental to our business. As
of March 29, 2006, we were not aware of any current, pending, or threatened
litigation or proceedings that could have a material adverse effect on our
results of operations, cash flows or financial condition.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None

PART II

ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Our Common Stock is listed on the over-the-counter electronic bulletin board
("OTCBB") under the symbol "HUSA". The following table sets forth the range of
high and low bid prices for each quarter during the past two fiscal years.

High Low
------- -------

Calendar Year 2005

Fourth Quarter . . $ 3.50 $ 2.65
Third Quarter. . . 2.75 1.00
Second Quarter . . 1.25 0.76
First Quarter. . . 1.00 0.78

Calendar Year 2004

Fourth Quarter . . $ 1.05 $ 0.83
Third Quarter. . . 1.10 0.83
Second Quarter . . 1.35 0.60
First Quarter. . . 1.00 0.65

The quotations reflect inter-dealer prices without retail mark-up, mark-down or
commission and may not represent actual transactions.

At March 29, 2006, the closing bid price of the Common Stock was $3.70.

As of March 29, 2006, there were approximately 900 record holders of our Common
Stock.

We have not paid any cash dividends since inception and presently anticipate
that all earnings, if any, will be retained for development of our business and
that no dividends on our common stock will be declared in the foreseeable
future. Any future dividends will be subject to the discretion of our Board of
Directors and will depend upon, among other things, future earnings, operating
and financial condition, capital requirements, general business conditions and
other pertinent facts. Therefore, there can be no assurance that any dividends
on our common stock will be paid in the future.

The following table provides information as of December 31, 2005 with respect to
the shares of our common stock that may be issued under our existing equity
compensation plans.

NUMBER OF SECURITIES
REMAINING AVAILABLE FOR
WEIGHTED-AVERAGE FUTURE ISSUANCE UNDER
NUMBER OF SECURITIES TO EXERCISE PRICE OF EQUITY COMPENSATION
BE ISSUED UPON EXERCISE OUTSTANDING PLANS (EXCLUDING
OF OUTSTANDING OPTIONS, OPTIONS, WARRANTS SECURITIES REFLECTED IN
PLAN CATEGORY WARRANTS AND RIGHTS (A) AND RIGHTS (B) COLUMN (A))
-------------------------------- ------------------------ ------------------- ------------------------

Equity compensation plans
approved by security holders (1) 89,000 $ 2.42 411,000
Equity compensation plans not
approved by security holders - NA -
------------------------ ------------------- ------------------------
Total 89,000 $ 2.42 411,000
======================== =================== ========================

(1) Consists of shares reserved for issuance under the Houston American Energy
Corp. 2005 Stock Option Plan pursuant to which 500,000 shares were
reserved. The plan was adopted by the board of directors in August 2005 and
approved by shareholders in January 2006.

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

GENERAL

Houston American Energy was incorporated in April 2001, for the purposes of
seeking oil and gas exploration and development prospects. Since inception, we
have sought out prospects utilizing the expertise and business contacts of John
F. Terwilliger, our sole executive officer. Through the third quarter of 2002,
the acquisition targets were in the Gulf Coast region of Texas and Louisiana,
where Mr. Terwilliger has been involved in oil and gas exploration for many
years. In the fourth quarter 2002, we initiated international efforts through a
Colombian joint venture more fully described below. Domestically and
internationally, the strategy is to be a non-operating partner with exploration
and production companies that have much larger resources and operations.

OVERVIEW OF OPERATIONS

Our operations are exclusively devoted to natural gas and oil exploration and
production.

Our focus, to date and for the foreseeable future, is the identification of oil
and gas drilling prospects and participation in the drilling and production of
prospects. We typically identify prospects and assemble various drilling
partners to participate in, and fund, drilling activities. We may retain an
interest in a prospect for our services in identifying and assembling prospects
without any contribution on our part to drilling and completion costs or we may
contribute to drilling and completion costs based on our proportionate interest
in a prospect.

We derive our revenues from our interests in oil and gas production sold from
prospects in which we own an interest, whether through royalty interests,
working interest or other arrangements. Our revenues vary directly based on a
combination of production volumes from wells in which we own an interest, market
prices of oil and natural gas sold and our percentage interest in each prospect.

Our well operating expenses vary depending upon the nature of our interest in
each prospect. We may bear no interest or a proportionate interest in the costs
of drilling, completing and operating prospects on which we own an interest.
Other than well drilling, completion and operating expenses, our principal
operating expenses relate to our efforts to identify and secure prospects,
comply with our various reporting obligations as a publicly held company and
general overhead expenses.

BUSINESS DEVELOPMENTS DURING 2005

Drilling Activities

During 2005, we drilled 4 successful on-shore domestic wells as follows:

- In May 2005, a well was drilled on the South Sibley Prospect in Webster
Parish, Louisiana with multiple pay sands apparently identified. Sales from
the well commenced June 28, 2005. We have a 7.5% working interest at an
8.3% net revenue interest carried to point of sales for the well.

- In April 2005, the Baronet #2 well was drilled on the Crowley Prospect in
Acadia Parish, Louisiana. The well tested the Hayes Sand and flanks a
natural gas well that produced 1.6 BCF of natural gas from the Hayes Sand.
After logging 21-feet of apparent net pay, hole conditions deteriorated
before logging could be completed. The well was completed and production
began in June 2005. We have a 3% working interest and 2.25% net revenue
interest until payout for the well.

- In December 2005, the Broussard #1 well was drilled on the Sugarland
Prospect in Vermillion Parish, Louisiana with multiple pay sands apparently
indicated. The well was completed in January 2006 and production sales are
expected to begin in March 2006. We have an 8.25% working interest with a
6.1875% net revenue interest, subject to a 25% working interest back-in at
payout.

- In November 2005, the Weil #1 well was drilled on the Hog Heaven Prospect
in Jim Hogg County, Texas with multiple pay sands indicated. The well was
completed in January 2006 and production sales are expected to begin in
March 2006. We have a 4.375% working interest, subject to payment of
5.8334% of costs to the casing point in the first well.

We had no dry holes drilled during 2005.

At December 31, 2005, we had no domestic wells being drilled but had planned
drilling operations during the first quarter of 2006 on one prospect in
Louisiana and two prospects in Texas.

During 2005, we drilled 10 international wells in South America as follows:

- Drilling of 9 offset wells on the Cara Cara concession in Colombia was
completed with production commencing on the Bengala #4, #5, #6, #7ST and #8
and the Jaguar #5, #T5, #T6 and #T7. We hold a 1.59% working interest in
each of the wells subject to a 30% reversionary interest to Ecopetrol at
payout.

- An oil well, the Tambaqui #5, was drilled and successfully completed under
the Tambaqui Association Contract in Columbia and began production in May
2005. We hold a 12.6% working interest and an 11.59% net revenue interest
in the well.

At December 31, 2005, we had one well being drilled in South America and we
presently plan to drill during 2006, with our partners, up to 15 additional
wells on the Cara Cara concession, up to 5 wells under the Cabiona concession, 1
well under the Dorotea concession, and 1 well under the Surimena concession.

Leasehold Activities

During 2005, we invested approximately $ 506,837 for the acquisition of oil and
gas properties, consisting of (1) acquisition, by Hupecol, of the Surimena
concession covering approximately 108 square miles, (2) acquisition of a 8.25%
interest in the Sugarland Prospect, (3) acquisition of a 4.375% interest in the
Hog Heaven Prospect, (4) acquisition of a 15% interest in the West Fargo
Prospect, and (5) acquisition of a 15% interest in the Obenhaus Prospect.

Other Developments

Seismic surveying began on our Cara Cara concession in Colombia as part of our
planned delineation of additional drilling prospects on the concession. Seismic
surveying was completed on our Dorotea and Cabiona concessions to establish
drilling prospect locations.

In May 2005, we sold $2,125,000 of 8% Subordinated Convertible Notes Due 2010 to
multiple investors to provide funding to support our lease acquisition and
drilling activities in the U.S. and Colombia. In connection with the placement
of the convertible notes, we issued to the placement agent in the transaction a
three year warrant to purchase 191,250 shares of our common stock at $1.00 per
share and paid commissions totaling $127,500. Pursuant to the terms of the
placement of the convertible notes, we entered into a Registration Rights
Agreement with the purchasers of the notes and, pursuant to the Registration
Rights Agreement, filed a registration statement with the Securities and
Exchange Commission covering the resale of the shares of common stock underlying
the convertible notes as well as the shares issuable upon exercise of the
placement agent warrant.

In August 2005, we appointed three additional directors, adopted a stock option
plan and fixed the compensation of our non-employee directors.

CRITICAL ACCOUNTING POLICIES

The following describes the critical accounting policies used in reporting our
financial condition and results of operations. In some cases, accounting
standards allow more than one alternative accounting method for reporting, such
is the case with accounting for oil and gas activities described below. In
those cases, our reported results of operations would be different should we
employ an alternative accounting method.

Full Cost Method of Accounting for Oil and Gas Activities. The Securities and
Exchange Commission ("SEC") prescribes in Regulation S-X the financial
accounting and reporting standards for companies engaged in oil and gas
producing activities. Two methods are prescribed: the successful efforts method
and the full cost method. We follow the full cost method of accounting for oil
and gas property acquisition, exploration and development activities. Under
this method, all productive and nonproductive costs incurred in connection with
the exploration for and development of oil and gas reserves are capitalized.
Capitalized costs include lease acquisition, geological and geophysical work,
delay rentals, costs of drilling, completing and equipping successful and
unsuccessful oil and gas wells and related internal costs that can be directly
identified with acquisition, exploration and development activities, but does
not include any cost related to production, general corporate overhead or
similar activities. Gain or loss on the sale or other disposition of oil and
gas properties is not recognized unless significant amounts of oil and gas
reserves are involved. No corporate overhead has been capitalized as of
December 31, 2005. The capitalized costs of oil and gas properties, plus
estimated future development costs relating to proved reserves are amortized on
a units-of-production method over the estimated productive life of the reserves.
Unevaluated oil and gas properties are excluded from this calculation. The
capitalized oil and gas property costs, less accumulated amortization, are
limited to an amount (the ceiling limitation) equal to the sum of: (a) the
present value of estimated future net revenues from the projected production of
proved oil and gas reserves, calculated at prices in effect as of the balance
sheet date (with consideration of price changes only to the extent provided by
contractual arrangements) and a discount factor of 10%; (b) the cost of unproved
and unevaluated properties excluded from the costs being amortized; (c) the
lower of cost or estimated fair value of unproved properties included in the
costs being amortized; and (d) related income tax effects. Excess costs are
charged to proved properties impairment expense.

Unevaluated Oil and Gas Properties. Unevaluated oil and gas properties consist
principally of our cost of acquiring and evaluating undeveloped leases, net of
an allowance for impairment and transfers to depletable oil and gas properties.
When leases are developed, expire or are abandoned, the related costs are
transferred from unevaluated oil and gas properties to depletable oil and gas
properties. Additionally, we review the carrying costs of unevaluated oil and
gas properties for the purpose of determining probable future lease expirations
and abandonments, and prospective discounted future economic benefit
attributable to the leases. We record an allowance for impairment based on a
review of present value of future cash flows. Any resulting charge is made to
operations and reflected as a reduction of the carrying value of the recorded
asset. Unevaluated oil and gas properties not subject to amortization include
the following at December 31, 2005 and 2004:

At December 31, 2005 At December 31, 2004
--------------------- ---------------------

Acquisition costs $ 44,548 $ 48,636
Evaluation costs 151,346 12,159
--------------------- ---------------------
Total $ 195,894 $ 60,795
===================== =====================

The carrying value of unevaluated oil and gas prospects include $151,039 and
$12,519 expended for properties in South America at December 31, 2005 and
December 31, 2004, respectively. We are maintaining our interest in these
properties and development has or is anticipated to commence within the next
twelve months.

Subordinated Convertible Notes and Warrants - Derivative Financial Instruments.
The Subordinated Convertible Notes and Warrants issued during 2005 have been
accounted for in accordance with SFAS 133 and EITF No. 00-19, "Accounting for
Derivative Financial Instruments Indexed to, and Potentially Settled in, a
Company's Own Stock."

The Company has identified the following instruments and derivatives requiring
evaluation and accounting under the relevant guidance applicable to financial
derivatives:

- Subordinated Convertible Notes
- Conversion feature
- Conversion price reset feature
- Company's optional redemption right
- Warrants
- Warrants exercise price reset feature

The Company has identified the conversion feature; the conversion price reset
feature and the Company's optional early redemption right within the Convertible
Notes to represent embedded derivatives. These embedded derivatives have been
bifurcated from their respective host debt contracts and accounted for as
derivative liabilities in accordance with EITF 00-19. The conversion feature,
the conversion price reset feature and the Company's optional early redemption
right within the Convertible Notes have been bundled together as a single hybrid
compound instrument in accordance with SFAS No. 133 Derivatives Implementation
Group Implementation Issue No. B-15, "Embedded Derivatives: Separate Accounting
for Multiple Derivative Features Embedded in a Single Hybrid Instrument."

The Company has identified the common stock warrant to be a detachable
derivative. The warrant exercise price reset provision is an embedded
derivative within the common stock warrant. The common stock warrant and the
embedded warrant exercise price reset provision have been accounted for as a
separate single hybrid compound instrument.

The single compound embedded derivatives within Subordinated Convertible Notes
and the derivative liability for Warrants have been recorded at fair value at
the date of issuance (May 4, 2005); and are marked-to-market each quarter with
changes in fair value recorded to the Company's income statement as "Net change
in fair value of derivative liabilities." The Company has utilized a third party
valuation firm to fair value the single compound embedded derivatives under the
following methods: a layered discounted probability-weighted cash flow approach
for the single compound embedded derivatives within Subordinated Convertible
Notes; and the Black-Scholes model for the derivative liability for Warrants
based on a probability weighted exercise price".

The fair value of the derivative liabilities are subject to the changes in the
trading value of the Company's common stock. As a result, the Company's
financial statements may fluctuate from quarter-to-quarter based on factors,
such as the price of the Company's stock at the balance sheet date, the amount
of shares converted by note holders and/or exercised by warrant holders.
Consequently, our financial position and results of operations may vary from
quarter-to-quarter based on conditions other than our operating revenues and
expenses.

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2005 COMPARED TO YEAR ENDED DECEMBER 31, 2004

Oil and Gas Revenues. Total oil and gas revenues increased $1,598,394, or
135.2%, to $2,780,457 in fiscal 2005 compared to $1,182,063 in fiscal 2004. The
increase in revenue is due to (1) increased production resulting from the
development of the Colombian fields and the new domestic wells that have come on
line during 2004 and 2005 and (2) increases in oil prices. We had interests in
17 producing wells in Colombia and 14 producing wells in North America during
2005 as compared to 8 producing wells in Colombia and 8 producing wells in North
America during 2004. Average prices from sales were $47.89 per barrel of oil and
$7.83 per mcf of gas during 2005 as compared to $33.31 per barrel of oil and
$5.43 per mcf of gas during 2004. Following is a summary comparison, by region,
of oil and gas sales for the periods.

Colombia North America Total
----------- -------------- ----------

Year ended 2005
Oil sales $ 2,041,072 $ 75,115 $2,116,187
Gas sales 0 664,270 664,270
Year ended 2004
Oil sales $ 808,472 $ 39,376 $ 847,848
Gas sales 0 334,215 334,215

Other Revenues. Other revenues, consisting of commission income and interest
income, increased by $88,133 to $94,191 in fiscal 2005 as compared to $6,058 in
fiscal 2004. The increase in other revenues was attributable to an increase in
interest income earned as a result of higher balances held following the 2005
placement of Subordinated Convertible Notes and the receipt during 2005 of a
one-time commission of $60,000.

Lease Operating Expenses. Lease operating expenses, excluding joint venture
expenses relating to our Colombia operations discussed below, increased 130.5%
to $953,624 in 2005 from $413,723 in 2004. The increase in lease operating
expenses was attributable to the increase in the number of wells operated during
2005. Following is a summary comparison of lease operating expenses for the
years ended December 31, 2005 and 2004.

Colombia North America Total
--------- -------------- --------

Year ended 2005 $ 874,082 $ 79,542 $953,624
Year ended 2004 354,448 59,275 413,723

Joint Venture Expenses. Joint venture expenses totaled $61,500 in 2005 compared
to $41,944 in 2004. The joint venture expenses represent our allocable share of
the indirect field operating and region administrative expenses billed by the
operator of the Colombian concessions. The increase in joint venture expenses
was attributable to increased activities associated with acquiring new
concessions in Colombia.

Depreciation and Depletion Expense. Depreciation and depletion expense
increased by 71.5% to $363,196 in fiscal 2005 when compared to $211,759 in 2004.
The increase in depreciation and depletion expense was primarily attributable to
the increased production from new wells coming on line during 2004 and 2005.

General and Administrative Expenses. General and administrative expense
increased by 150.7% to $835,829 in 2005 from the $333,412 in 2004. The increase
in general and administrative expense was primarily attributable to an increase
in payroll expense (up $143,298 from $48,742) as a result of the Company's
payment of a salary to its principal officer beginning in the fourth quarter of
2004 and increases in professional fees (up $354,139, or 235.1%) relating
primarily to legal fees associated with the Moose Oil litigation commenced
during 2004 and settled in 2005.

Interest Expense. Interest expense increased 155.4% to $183,920 in 2005
compared to $72,000 in 2004. Included in interest expense was $72,000 of
interest paid to the Company's principal shareholder in both 2004 and 2005. The
increase in interest expense was attributable to the issuance, in May 2005, of
$2,125,000 of subordinated convertible notes.

Derivative Related Expenses. In connection with the Company's issuance during
2005 of the subordinated convertible notes and related warrants, the Company,
during 2005, reported derivative related expenses arising in connection with
derivative features included in the subordinated convertible notes and the
warrants, consisting of derivative interest expense of $319,714 and a charge in
the amount of the net change in fair value of derivative liabilities of
$402,628. The Company incurred no similar expenses during fiscal 2004.

Derivative interest expense consisted of (1) the excess of the value of the
derivatives embedded in the subordinated convertible notes at closing over the
face amount of the notes ($243,485), plus (2) the value of the derivatives
embedded in the warrants ($42,063), plus (3) amortization of the recorded
discount on the convertible notes ($34,167) over a five year period under the
effective interest method.

The expense attributable to the net change in fair value of derivative
liabilities consisted of the increase in the recorded derivative liability
attributable to derivatives embedded in the subordinated convertible notes from
the date of issuance to December 31, 2005 ($15,561) using mark-to-market
accounting and the increase in the recorded derivative liability attributable to
derivatives embedded in the warrants from the date of issuance to December 31,
2005 ($387,067). The Company will evaluate the fair value of the derivative
liabilities on a quarter-to-quarter basis until the subordinated convertible
notes and warrants are no longer outstanding and changes in the fair value of
the derivative liability will result in charges or accretions to earnings based
on various factors affecting fair value including the price of the Company's
stock and the amounts of notes converted and warrants exercised.

Income Tax Expense. Income tax expense increased to $239,201 in fiscal 2005
from $0 in fiscal 2004. The increase in income tax expense during 2005 is
attributable to the Company's estimated allocable share of Colombian income tax
relating to its interest in its Colombian venture. The Company recorded no U.S.
income tax liability in 2005 or 2004 and at December 31, 2005 had net operating
losses of approximately $1,173,000 and foreign tax credits of approximately
$239,000.

Operating and Net Income (Loss). Operating income for fiscal 2005 totaled
$660,499 as compared to $187,283 in fiscal 2004. Net loss totaled $501,780 in
fiscal 2005 as compared to net income of $115,283 in fiscal 2004. The adverse
change in net income (loss) in 2005 was attributable, primarily, to the non-cash
non-operating charges arising from accounting for derivative features included
in the subordinated convertible note financing undertaken in 2005, and, to a
lesser extent, to increased fees and interest expense associated with the
financing and the incurrence of income tax expense from operations in Colombia.

FINANCIAL CONDITION

Liquidity and Capital Resources. At December 31, 2005, we had a cash balance of
$1,724,100 and working capital of $1,771,722, excluding derivative liabilities
in the amount of $2,813,175, compared to a cash balance of $721,613 and working
capital of $771,392 at December 31, 2004. The increase in cash and working
capital during the year was primarily attributable to the sale, during 2005, of
$2,125,000 of Subordinated Convertible Notes partially offset by investing
activities relating to oil and gas properties and prepayment of $100,000 of
notes payable to our principal shareholder.

Derivative liabilities of $2,813,175 are recorded as current liabilities at
December 31, 2005 but are not considered in computing working capital. The
derivative liabilities represent the deemed fair value of the embedded
derivatives included in the subordinated convertible notes and accompanying
warrants that were issued during 2005 as measured at December 31, 2005.
Included within the derivative liabilities at December 31, 2005 was $2,090,833
attributable to the derivative features in the subordinated convertible notes
which amount is reflected as a discount in the amount of the subordinated
convertible note on the balance sheet.

Cash Flows. Operating cash flows for 2005 totaled $694,581 as compared to
$297,995 during 2004. The improvement in operating cash flow was primarily
attributable to improved profitability from operations, driven by increases in
production volume and higher prices of both oil and natural gas, and increases
in depreciation and depletion, partially offset by changes in operating assets
and liabilities.

Investing activities used $1,589,594 during 2005 as compared to $590,247 used
during 2004. The increase in funds used in investing activities during the
current period was primarily attributable to the payment of the Company's
portion of seismic survey costs on Colombian prospects totaling $453,198 and
increased leasing and drilling activities in 2005.

Financing activities provided $1,897,500 during 2005 attributable to the sale of
subordinated convertible notes and a partial payment on the outstanding
shareholder loan and $350,443 during 2004 attributable to the issue of common
stock.

Notes Payable. At December 31, 2005, our long-term debt was $975,416 as
compared to $1,000,000 at December 31, 2004. The change in long-term debt was
attributable to the issuance during 2005 of $2,125,000 of Subordinated
Convertible Notes, recording a discount in the amount of $2,090,833 at December
31, 2005 relating to the fair value of the embedded derivatives included in the
Subordinated Convertible Notes, a partial payment of $100,000 on a shareholder
loan and recording a reserve for plugging costs of $41,249.

Notes payable at December 31, 2005 included loans from our principal
shareholder, in the amount of $900,000, bearing interest at 7.2% and maturing
January 1, 2007.

Notes payable also included $2,125,000 in principal amount of convertible notes.
The convertible notes bear interest at 8%, provide for semi-annual interest
payments and mature May 1, 2010. The convertible notes are convertible, at the
option of the holders, into common stock at a price of $1.00 per share, subject
to standard anti-dilution provisions relating to splits, reverse splits and
other transactions, including issuances of common stock at prices below the
conversion price. The convertible notes are subject to automatic conversion in
the event we conduct an underwritten public offering of common stock from which
we receive at least $5 million and the public offering price is at least 150% of
the then applicable conversion price. We have the right to cause the convertible
notes to be converted into common stock after May 1, 2006 if the price of our
common stock exceeds 200% of the then applicable conversion price on the date of
conversion and for at least 20 trading days over the preceding 30 trading days.
We have the right to repurchase the convertible notes after May 1, 2007 at 103%
of the face amount during 2007, 102% of the face amount during 2008, 101% of the
face amount during 2009 and 100% of the face amount thereafter. The convertible
notes are unsecured general obligations and are subordinated to all other
indebtedness unless the other indebtedness is expressly made subordinate to the
convertible notes.

Capital and Exploration Expenditures and Commitments. Our principal capital and
exploration expenditures relate to our ongoing efforts to acquire, drill and
complete prospects. With the receipt of equity financing in 2003 and 2004 and
the May 2005 sale of convertible notes, and the increase in our revenues,
profitability and operating cash flows, we expect that future capital and
exploration expenditures will be funded principally through funds on hand and
funds generated from operations.

During 2005, we invested approximately $1,589,594 for the acquisition and
development of oil and gas properties, consisting of (1) seismic surveying in
Colombia ($453,198), (2) drilling 4 domestic wells, and (3) drilling 10 wells in
Colombia.

At December 31, 2005, our only material contractual obligations requiring
determinable future payments on our part were notes payable to our principal
shareholder and holders of subordinated convertible notes and our lease relating
to our executive offices.

The following table details our contractual obligations as of December 31, 2005:

Payments due by period
------------------------------------------------------------
Total 2006 2007 - 2008 2009 - 2010 Thereafter
---------- ------- ------------ ------------ -----------

Long-term debt (1) $3,025,000 $ 0 $ 900,000 $ 2,125,000 $ 0
Operating lease
commitments 33,026 33,026 0 0 0
---------- ------- ------------ ------------ -----------
Total $3,058,026 $33,026 $ 900,000 $ 2,125,000 $ 0
========== ======= ============ ============ ===========

(1) Long-term debt consists of $2,125,000 in face amount of subordinated
convertible notes and $900,000 of shareholder loans. Long-term debt does
not give effect to discounts recorded with respect to the derivative
features of the subordinated convertible notes.

In addition to the contractual obligations requiring that we make fixed
payments, in conjunction with our efforts to secure oil and gas prospects,
financing and services, we have, from time to time, granted overriding royalty
interests (ORRI) in various properties, and may grant ORRIs in the future,
pursuant to which we will be obligated to pay a portion of our interest in
revenues from various prospects to third parties.

At December 31, 2005, we had 17 revenue producing wells in Colombia, 6
revenue producing wells in Texas, 7 revenue producing well in Louisiana and 1
producing well in Oklahoma.

At December 31, 2005, our acquisition and drilling budget for the balance of
2006 totaled approximately $1,615,000, consisting of (1) $1,115,000 for drilling
of 13 wells in Colombia on the Cara Cara and Cabiona concessions, (2) $200,000
to drill 2 domestic wells on the Obenhaus Prospect, and the West Fargo Prospect
and (3) $300,000 for seismic in Colombia. Our acquisition and drilling budget
has historically been subject to substantial fluctuation over the course of a
year based upon successes and failures in drilling and completion of prospects
and the identification of additional prospects during the course of a year.

Management anticipates that our current financial resources combined with our
increases in revenues over the past year will meet our anticipated objectives
and business operations, including our planned property acquisitions and
drilling activities, for at least the next 12 months without the need for
additional capital. Management continues to evaluate producing property
acquisitions as well as a number of drilling prospects. It is possible,
although not anticipated, that the Company may require and seek additional
financing if additional drilling prospects are pursued beyond those presently
under consideration.

OFF-BALANCE SHEET ARRANGEMENTS

We had no off-balance sheet arrangements or guarantees of third party
obligations at December 31, 2005.

INFLATION

We believe that inflation has not had a significant impact on our operations
since inception.

ITEM 7. FINANCIAL STATEMENTS

Our financial statements, together with the independent accountants report
thereon of Thomas Leger & Co., L.L.P., appears immediately after the signature
page of this report. See "Index to Financial Statements" on page 35 of this
report.

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

None

ITEM 8A. CONTROLS AND PROCEDURES

As of the end of the period covered by this report, we have evaluated the
effectiveness of the design and operation of our disclosure controls and
procedures under the supervision and with the participation of our chief
executive officer ("CEO") who also serves as chief financial officer.

In connection with the audit of our financial statements for the fiscal year
ended December 31, 2005, our independent registered public accounting firm
informed us that we had significant deficiencies constituting material
weaknesses as defined by the standards of the Public Company Accounting
Oversight Board, some of which had previously been identified in connection with
the audit of our financial statements for the fiscal year ended December 31,
2004 and continued to exist at December 31, 2005.

The weaknesses in question were detected during the audit of our financial
statements for the fiscal year ended December 31, 2004, which audit occurred in
February/March 2005, and during the audit of our financial statements for the
fiscal year ended December 31, 2005, which audit occurred in March 2006.

The weaknesses were detected in the routine course of the audit review of
accounting for certain non-routine transactions.

The specific problems identified by the auditor were (1) lack of segregation of
duties necessary to maintain proper checks and balances between functions, (2)
failure of internal personnel to adequately communicate the scope and nature of
non-routine transactions, and (3) application of improper accounting principles
to financial derivatives. The absence of qualified full time accounting
personnel was a contributing factor to the problems identified by the auditor.
The specific circumstances giving rise to the weaknesses include our President
serving as both Chief Executive Officer and as Chief Financial Officer and our
utilizing the services of contract accountants on a part time basis in the
absence of internal accounting personnel. As a result of the absence of full
time in-house accounting personnel and the failure of in-house personnel to
adequately communicate information to the outside contract accountants, certain
journal entries required during 2004 and 2005 were not made until the time of
the audit when the need for such entries was identified by the auditor.

As a result of our review of the items identified by our auditors, we have
concluded that our previous derivative accounting policies were incorrect. We
also concluded that a failure of communications resulted in a failure to
properly account for certain stock option grants.

In light of the above items, we have determined to restate our financial
statements for the quarterly and year-to-date periods ended June 30, 2005 and
September 30, 2005 to correct our accounting for derivatives.

Further, based on the material weaknesses described herein, we concluded that
our disclosure controls and procedures were not effective at the reasonable
assurance level at December 31, 2005. More specifically, our failure to
maintain effective controls over the selection, application and monitoring of
our accounting policies to assure that certain transactions were accounted for
in conformity with generally accepted accounting principles resulted in:

a. A failure during the second and third quarters of 2005 to record an
appropriate derivative liability, deemed interest expense associated with the
derivative liability and related charges associated with changes in the value of
embedded derivatives, all arising from the issuance during the second quarter of
convertible notes and warrants that included embedded derivatives; and

b. A failure during the last quarter of 2005 to record compensation expense
pursuant to SFAS 123 in connection with the grant of stock options to certain
non-employees.

Because we lack the financial resources to support in-house accounting personnel
at this time, no formal steps have as yet been taken to resolve the weaknesses
identified by the auditor. We are, however, emphasizing improvement in
communications with outside accounting personnel to assure that non-routine
transactions are accounted for in a timely manner. Further, with respect to the
specific accounting principles that were subject of the weaknesses identified -
derivatives accounting and compensation accounting - we intend to place an
emphasis on reviewing the application of such principles in connection with all
future accounting periods.

During the quarter ended December 31, 2005, there were no changes in our
internal controls over financial reporting that materially affected, or are
reasonably likely to materially affect, internal controls over financial
reporting.

ITEM 8B. OTHER INFORMATION

PART III

ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS;
COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT

DIRECTORS AND EXECUTIVE OFFICERS

The following table sets forth the names, ages and offices of our present
executive officers and directors. The periods during which such persons have
served in such capacities are indicated in the description of business
experience of such persons below.

Name Age Position
---- --- --------

John Terwilliger 58 President, Treasurer and Director
Orrie Lee Tawes III 58 Director
Edwin Broun III 53 Director
Stephen Hartzell 52 Director

The following is a biographical summary of the business experience of the
present directors and executive officers of the Company:

John F. Terwilliger has served as our president, secretary and treasurer since
our inception in April 2001. From 1988 to April 2002, Mr. Terwilliger served as
the chairman of the board and president of Moose Oil & Gas Company, and its
wholly-owned subsidiary, Moose Operating Co., Inc., both Houston, Texas based
companies. Prior to 1988, Mr. Terwilliger was the chairman of the board and
president of Cambridge Oil Company, a Houston, Texas based oil exploration and
production company. Mr. Terwilliger served in the United States Army, receiving
his honorable discharge in 1969. On April 9, 2002, Moose Oil & Gas Company and
its wholly-owned subsidiary, Moose Operating Co., Inc., filed a bankruptcy
petition under Chapter 7 of the United States Bankruptcy Code in Cause No.
02-33891-H507: 02-22892, in the United States District Court for the Southern
District of Texas, Houston Division. At the time of the filing of the
bankruptcy petition, Mr. Terwilliger was the chairman of the board and president
of both Moose Oil & Gas Company and Moose Operating Co., Inc. Mr. Terwilliger
resigned those positions on April 9, 2002.

O. Lee Tawes III has served as a director since August 2005. Mr. Tawes is
Executive Vice President and Head of Investment Banking, and a Director at
Northeast Securities Inc. From 2000-2001 he was Managing Director of Research
for C.E. Unterberg, Towbin, an investment and merchant banking firm specializing
in high growth technology companies. Mr. Tawes spent 20 years at Oppenheimer &
Co. Inc. and CIBC World Markets, where he was Director of Equity Research from
1991 to 1999. He was also Chairman of the Stock Selection Committee at CIBC, a
member of the firm's Executive Committee, and Commitment Committee. From 1972
to 1990, Mr. Tawes was an analyst covering the food and diversified industries
at Goldman Sachs & Co. from 1972 to 1979, and Oppenheimer from 1979 to 1990. As
food analyst, he was named to the Institutional Investor All America Research
Team five times from 1979 through 1989. Mr. Tawes has served as a Director of
Baywood International, Inc. since 2001. Mr. Tawes is a graduate of Princeton
University and received his MBA from Darden School at the University of
Virginia.

Edwin Broun III has served as a director since August 2005. Mr. Broun, is the
owner/operator of Broun Energy, LLC, an oil and gas exploration and production
company. He co-founded, and from 1994 to 2003 was Vice President and Managing
Partner of, Sierra Mineral Development, L.C., an oil and gas exploration and
production company where he was responsible for reserve and economic evaluation
of acquisitions, drill site selection and workover design. From 1992 to 1994 he
was a partner and consultant in Tierra Mineral Develoment, L.C., where he
evaluated, negotiated and structured acquisitions, workovers and divestitures of
oil and gas holdings. From 1975 to 1992, Mr. Broun served in various petroleum
engineering capacities, beginning as a petroleum engineer with Atlantic
Richfield Company from 1975 to 1979 and Tenneco Oil Company from 1979 to 1982
and rising to serving in various management capacities as Acquisitions Manager
from 1982 to 1986 and Vice President, Engineering from 1986 to 1987 at ITR
Petroleum, Inc.; Vice President, Acquisitions from 1987 to 1988 and Vice
President, Houston District from 1988 to 1990 at General Atlantic Resources,
Inc.; and Vice President, Engineering and Acquisitions from 1990 to 1992 at West
Hall Associates, Inc. Mr. Broun received his B.S. in Petroleum Engineering from
the University of Texas and an M.S. in Engineering Management from the
University of Alaska.

Stephen Hartzell has served as a director since August 2005. Mr. Hartzell, has
over 27 years of experience as a petroleum geologist. Since 2003, Mr. Hartzell
has been an owner operator of Southern Star Exploration, LLC, an independent oil
and gas company. From 1986 to 2003, Mr. Hartzell served as an independent
consulting geologist. From 1978 to 1986, Mr. Hartzell served as a petroleum
geologist, division geologist and senior geologist with Amoco Production
Company, Tesoro Petroleum Corporation, Moore McCormack Energy and American
Hunter Exploration. Mr. Hartzell received his B.S. in Geology from Western
Illinois University and an M.S. in Geology from Northern Illinois University.

Our board of directors is divided into three classes, each elected for staggered
three-year terms. Messrs. Tawes, Broun and Hartzell are Class A directors with
terms expiring on the first annual meeting following their appointment. Mr.
Terwilliger is a Class C director. His term is scheduled to expire at the third
annual meeting following his appointment.

Our executive officers are elected by our board of directors and serve terms of
one year or until their death, resignation or removal by the board of directors.

COMMITTEES OF THE BOARD

We do not presently maintain an audit committee or any other committee of our
board of directors. We are presently evaluating the appointment of additional
independent directors and the establishment of committees. Because we do not
presently maintain an audit committee, we have no audit committee financial
expert.

CODES OF ETHICS

The Board of Directors has adopted a Code of Business Ethics covering all of our
officers, directors and employees. We require all employees to adhere to the
Code of Business Ethics in addressing legal and ethical issues encountered in
conducting their work. The Code of Business Ethics requires that our employees
avoid conflicts of interest, comply with all laws and other legal requirements,
conduct business in an honest and ethical manner and otherwise act with
integrity and in the company's best interest.

The Board of Directors has also adopted a separate Code of Business Ethics for
the CEO and Senior Financial Officers. This Code of Ethics supplements our
general Code of Business Ethics and is intended to promote honest and ethical
conduct, full and accurate reporting, and compliance with laws as well as other
matters.

The Code of Business Ethics for the CEO and Senior Financial Officers is filed
as an exhibit to our Annual Report on Form 10-KSB for the year ended December
31, 2004 and is available for review at the SEC's web site at www.sec.gov.
-----------

COMPLIANCE WITH SECTION 16(A) OF EXCHANGE ACT

Under the securities laws of the United States, our directors, executive
officers, and any person holding more than ten percent of our common stock are
required to report their initial ownership of our common stock and any
subsequent changes in that ownership to the Securities and Exchange Commission.
Specific due dates for these reports have been established and we are required
to disclose any failure to file by these dates during fiscal year 2005. To our
knowledge, all of the filing requirements were satisfied on a timely basis in
fiscal year 2005. In making these disclosures, we have relied solely on written
statements of our directors, executive officers and shareholders and copies of
the reports that they filed with the Commission.

ITEM 10. EXECUTIVE COMPENSATION

EXECUTIVE COMPENSATION

The following table sets forth information concerning cash and non-cash
compensation paid or accrued for services in all capacities during the year
ended December 31, 2005 of each person who served as our Chief Executive Officer
during fiscal 2005 and the next four most highly paid executive officers (the
"Named Officers").

Annual Compensation
Name and -------------------------------------------
Principal Position Year Salary($) Bonus($) Other ($)
------------------------- ---- ---------- -------- ---------------

John Terwilliger 2005 192,000 -0- -0- (1)(2)
President and 2004 45,000 -0- -0- (1)(2)
Chief Executive Officer 2003 -0- -0- -0- (1)(2)

________________
(1) Mr. Terwilliger receives no other compensation or benefits other than
vacation benefits, expense reimbursements and participation in medical,
retirement and other benefit plans which are generally available to our
executives.

(2) Mr. Terwilliger received overriding royalty interests in three properties
identified by Mr. Terwilliger. No value was assigned to those overriding
royalty interests for purposes of this table. Payments received by Mr.
Terwilliger pursuant to those overriding royalty interests totaled $38,109,
$21,170, and $3,600 in 2005, 2004 and 2003, respectively.

We have no employment agreements with any of our officers or employees.

DIRECTOR COMPENSATION

Non-employee directors are paid $1,000 per meeting attended, or $500 per
telephonic meeting, and are reimbursed all expenses associated with attendance
of, or participation in, meetings. Each non-employee director is also granted
an option to purchase 20,000 shares of common stock upon their initial
appointment as a director and annually thereafter so long as they continue to
serve as directors. The options granted to non-employee directors are
exercisable at fair market value on the date of grant and have a term of ten
years.

ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS

The following table sets forth information as of March 29, 2006, based on
information obtained from the persons named below, with respect to the
beneficial ownership of shares of our common stock held by (i) each person known
by us to be the owner of more than 5% of the outstanding shares of our common
stock, (ii) each director, (iii) each named executive officer, and (iv) all
executive officers and directors as a group:

Name and Address Number of Shares Percentage
of Beneficial Owner (1) Beneficially Owned of Class (2)
--------------------------- ------------------- ------------

John F. Terwilliger 8,574,486 42.9%
801 Travis, Suite 2020
Houston, Texas 77002

Orrie Lee Tawes 3,307,044 (3) 16.4%
100 Wall Street
New York, New York 10005

Edwin Broun III 1,030,000 (4) 5.1%
6025 Riverview Way
Houston, Texas 77056

Stephen Hartzell 76,000 (5) *

All directors and officers
as a group (four persons) 12,987,530 (6) 64.2%

__________
* Less than 1%.

(1) Unless otherwise indicated, each beneficial owner has both sole voting and
sole investment power with respect to the shares beneficially owned by such
person, entity or group. The number of shares shown as beneficially owned
include all options, warrants and convertible securities held by such
person, entity or group that are exercisable or convertible within 60 days
of March 29, 2006.

(2) The percentages of beneficial ownership as to each person, entity or group
assume the exercise or conversion of all options, warrants and convertible
securities held by such person, entity or group which are exercisable or
convertible within 60 days, but not the exercise or conversion of options,
warrants and convertible securities held by others shown in the table.

(3) Shares shown as beneficially owned by Orrie Lee Tawes include 20,000 shares
issuable upon exercise of options held by Mr. Tawes and 119,034 held by his
wife, Marsha Russell. Excludes shares underlying warrants held by Northeast
Securities, Inc. as to which shares Mr. Tawes disclaims beneficial
ownership.

(4) Includes 200,000 issuable upon conversion of notes held by Mr. Broun,
20,000 shares issuable upon exercise of options held by Mr. Broun and
10,000 shares held by his wife.

(5) Includes 20,000 shares issuable upon exercise of options held by Mr.
Hartzell.

(6) Includes 260,000 shares issuable upon exercise of outstanding options and
conversion of notes.

ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

In December 2003, Mr. Terwilliger converted $441,516.29 of loans into 1,103,791
shares of our common stock and modified the repayment terms with respect to the
balance of the loans to us, totaling $1 million, to reduce the interest rate on
the loans to 7.2% and provide for a fixed maturity date of January 1, 2007.
Also, in December 2003, O. Lee Tawes, a principal shareholder, converted the
entire principal and accrued interest on his loans to us, in the amount of
$186,016.83, into 465,042 shares of common stock. As of December 31, 2005, we
owed $904,400 to Mr. Terwilliger, including accrued interest.

In conjunction with our efforts to secure oil and gas prospects, financing and
services, we have, from time to time, granted overriding royalty interests in
various mineral properties to Mr. Tawes. During 2005, approximately $25,000 was
paid to Mr. Tawes from these royalty interests.

In May 2005, Northeast Securities, Inc. acted as placement agent in connection
with our offer and sale of $2,125,000 of Subordinated Convertible Notes for
which Northeast Securities received commissions totaling $127,500 and a warrant
to purchase 191,250 shares of common stock at $1.00 per share. Mr. Tawes is
Executive Vice President, head of Investment Banking and a Director of Northeast
Securities.

ITEM 13. EXHIBITS

Exhibit
Number Description of Exhibit
-------- -----------------------------------------------------------------------------------

3.1 Certificate of Incorporation of Houston American Energy Corp. filed April 2,
2001 (incorporated by reference to Exhibit 3.1 to the Registration Statement on
Form SB-2, registration number 333-66638 (the "2001 Registration Statement"),
filed with the SEC on August 3, 2001).

3.2 Bylaws of Houston American Energy Corp. adopted April 2, 2001 (incorporated
by reference to Exhibit 3.3 to the 2001 Registration Statement filed with the SEC
on August 3, 2001).

3.3 Certificate of Amendment to the Certificate of Incorporation of Houston
American Energy Corp. filed September 25, 2001 (incorporated by reference to
Exhibit 3.4 to Amendment No. 1 to the 2001 Registration Statement filed with
the SEC on October 1, 2001).

4.1 Text of Common Stock Certificate of Houston American Energy Corp.
(incorporated by reference to Exhibit 4.1 to the 2001 Registration Statement filed
with the SEC on August 3, 2001).

10.1 Promissory Note of Houston American Energy Corp. in the amount of $390,000
dated July 2, 2001, payable to John F. Terwilliger (incorporated by reference to
Exhibit 10.11 to Amendment No. 4 to the 2001 Registration Statement filed with
the SEC on November 21, 2001).

10.2 Promissory Note of Houston American Energy Corp. in the amount of $285,000
dated July 30, 2001, payable to John F. Terwilliger (incorporated by reference to
Exhibit 10.12 to Amendment No. 4 to the 2001 Registration Statement filed with
the SEC on November 21, 2001).

10.3 Registration Rights Agreement dated July 14, 2003, between Houston American
Energy Corp. and LibertyView Funds, LP (incorporated by reference to Exhibit
10.19 to the 2001 Form 10-QSB for the quarter ended June 30, 2003 (the "June
2003 Form 10-QSB")).

10.4 Registration Rights Agreement dated July 14, 2003, between Houston
American Energy Corp. and LibertyView Special Opportunities Fund, LP
(incorporated by reference to Exhibit 10.20 to the June 2003 Form 10-QSB).

10.5 Registration Rights Agreement dated July 21, 2003, between Houston
American Energy Corp. and William D. Forster (incorporated by reference to
Exhibit 10.21 to the June 2003 Form 10-QSB).

10.6 Registration Rights Agreement dated July 21, 2003, between Houston
American Energy Corp. and James V. Pizzo & Ellen London-Pizzo
(incorporated by reference to Exhibit 10.22 to the June 2003 Form 10-QSB).

10.7 Registration Rights Agreement dated July 21, 2003, between Houston
American Energy Corp. and Sensus LLC (incorporated by reference to Exhibit
10.23 to the June 2003 Form 10-QSB).

10.8 Registration Rights Agreement dated July 14, 2003, between Houston
American Energy Corp. and Stephen P. Hartzell (incorporated by reference to
Exhibit 10.24 to the June 2003 Form 10-QSB).

10.9 Registration Rights Agreement dated July 18, 2003, between Houston
American Energy Corp. and Peter S. Rawlings (incorporated by reference to
Exhibit 10.25 to the June 2003 Form 10-QSB).

10.10 Registration Rights Agreement dated July 14, 2003, between Houston
American Energy Corp. and Lior Bregman (incorporated by reference to
Exhibit 10.26 to the June 2003 Form 10-QSB).

10.11 Form of Subscription Agreement relating to December 2003 placement of
shares (incorporated by reference to Exhibit 10.23 to the Registration Statement
on Form SB-2, registration number 333-111826 (the "2004 Registration
Statement"), filed with the SEC on January 9, 2004).

10.12 Form of Registration Rights Agreement relating to December 2003 placement
of shares (incorporated by reference to Exhibit 10.24 to the 2004 Registration
Statement).

10.13 Promissory Note, dated December 10, 2003, payable to John Terwilliger in the
amount of $724,658.67 (incorporated by reference to Exhibit 10.25 to the 2004
Registration Statement).

10.14 Promissory Note, dated December 10, 2003, payable to John Terwilliger in the
amount of $275,341.33 (incorporated by reference to Exhibit 10.26 to the 2004
Registration Statement).

10.15 Form of Purchase Agreement, dated May 4, 2005 relating to the sale of 8%
Subordinated Convertible Notes due 2010 (incorporated by reference to Exhibit
10.1 to the Current Report on Form 8-K dated May 4, 2005 (the "May 2005
Form 8-K"), filed with the SEC on May 10, 2005).

10.16 Form of 8% Subordinated Convertible Note due 2010, dated May 4, 2005
(incorporated by reference to Exhibit 4.1 to the May 2005 Form 8-K).

10.17 Form of Placement Agent Warrant, dated May 4, 2005 (incorporated by
reference to Exhibit 4.2 to the May 2005 Form 8-K).

10.18 Form of Registration Rights Agreement, dated May 4, 2005 (incorporated by
reference to Exhibit 4.3 to the May 2005 Form 8-K).

10.19 Houston American Energy Corp. 2005 Stock Option Plan (incorporated by
reference to Exhibit 10.1 to the Current Report on Form 8-K dated August
12,2005 (the "August 2005 Form 8-K"), filed with the SEC on August
16,2005).

10.20 Form of Director Stock Option Agreement (incorporated by reference to
Exhibit 10.2 to the August 2005 Form 8-K).

14.1 Code of Ethics for CEO and Senior Financial Officers (incorporated by
reference to Exhibit 14.1 to the 2003 Form 10-KSB)

23.1* Consent of Thomas Leger & Co. L.L.P.

31.1* Section 302 Certifications

32.1* Section 906 Certifications

* Filed herewith.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

FEES PAID TO INDEPENDENT PUBLIC ACCOUNTANTS

The following table presents fees paid or accrued for professional audit
services rendered by Thomas Leger & Co., L.L.P. for the audit of our annual
financial statements for the years ended December 31, 2005 and December 31, 2004
and fees billed for other services rendered by Thomas Leger & Co., L.L.P. during
those periods.

FISCAL 2005 FISCAL 2004
-------------- ------------

Audit fees (1) $ 36,555 $ 31,750
Audit related fees - -
Tax fees - -
All other fees - -
-------------- ------------
Total $ 36,555 $ 31,750
============== ============

(1) Audit Fees consist of fees billed for professional services rendered for
the audit of our consolidated annual financial statements and review of the
interim consolidated financial statements included in quarterly reports and
services that are normally provided by Thomas Leger & Co., L.L.P. in
connection with statutory and regulatory filings or engagements.

POLICY ON PRE-APPROVAL OF AUDIT AND NON-AUDIT SERVICES OF INDEPENDENT AUDITOR

At such time, if ever, as we form an audit committee, we intend that the audit
committee will establish a specific policy relating to pre-approval of all audit
and non-audit services provided by our independent auditors. As we do not
presently maintain an audit committee, no such policy has been adopted to date.

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant
caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.

HOUSTON AMERICAN ENERGY CORP.
Dated: March 31, 2006

By: /s/ John F. Terwilliger
---------------------------
John F. Terwilliger
President

Pursuant to the requirements of the Securities Exchange Act of 1934, 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/ John F. Terwilliger Chairman, Chief Executive Officer, March 31, 2006
------------------------- President, Treasurer and Director
John F. Terwilliger (Principal Executive Officer and
Principal Accounting Officer)

/s/ O. Lee Tawes III Director March 31, 2006
-------------------------
O. Lee Tawes III

/s/ Edwin Broun III Director March 31, 2006
-------------------------
Edwin Broun III

/s/ Stephen Hartzell Director March 31, 2006
-------------------------
Stephen Hartzell

HOUSTON AMERICAN ENERGY CORP.

INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . F-1

Balance Sheet as of December 31, 2005 . . . . . . . . . . . . . . . . . . . . . . F-2

Statements of Operations For the Years ended December 31, 2005 and 2004 . . . . . F-3

Statements of Shareholders' Equity for the Years ended December 31, 2005 and 2004 F-4

Statements of Cash Flows For the Years Ended December 31, 2005 and 2004 . . . . . F-5

Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . F-6 to F-22

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Houston American Energy Corp.
Houston, Texas

We have audited the accompanying balance sheet of Houston American Energy Corp.
as of December 31, 2005 and the related statements of operations, shareholders'
equity, and cash flows for the years ended December 31, 2005 and 2004. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit.

We conducted our audit 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. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the over-all financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects the financial position of Houston American Energy Corp. as
of December 31, 2005, and the results of its operations and its cash flows for
the years ended December 31, 2005 and 2004 in conformity with accounting
principles generally accepted in the United States of America.

Thomas Leger & Co., L.L.P.

March 7, 2006
Houston, Texas

F-1

HOUSTON AMERICAN ENERGY CORP.
BALANCE SHEET
DECEMBER 31, 2005
--------------------------------------------------------------------------------

ASSETS
------

CURRENT ASSETS
Cash $ 1,724,100
Accounts receivable 573,322
Prepaid expenses 9,965
------------

TOTAL CURRENT ASSETS 2,307,387
------------

PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties, full cost method
Costs subject to amortization 3,797,025
Costs not being amortized 195,894
Office equipment 10,878
------------
Total properties 4,003,797

Accumulated depreciation and depletion oil and gas properties (1,372,552)
------------

PROPERTY, PLANT AND EQUIPMENT, NET 2,631,245
------------

OTHER ASSETS 113,851
------------

TOTAL ASSETS $ 5,052,483
============

LIABILITIES AND SHAREHOLDERS' EQUITY
------------------------------------

CURRENT LIABILITIES
Accounts payable $ 252,872
Accrued expenses 278,393
Derivative Liability 2,813,175
Accrued interest on shareholder loans 4,400
------------

TOTAL CURRENT LIABILITIES 3,348,840
------------

LONG-TERM DEBT
Subordinated convertible notes-net of discount 34,167
Notes payable to principal shareholder 900,000
Reserve for plugging costs 41,249
------------

TOTAL LONG-TERM DEBT 975,416
------------

SHAREHOLDERS' EQUITY
Common stock, par value $.001;
100,000,000 shares authorized, 19,970,589 shares outstanding 19,971
Additional paid-in capital 2,851,920
Treasury stock, at cost; 100,000 shares (85,834)
Accumulated deficit (2,057,830)
------------

TOTAL SHAREHOLDERS' EQUITY 728,227
------------

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 5,052,483
============

The accompanying notes are an integral part of these financial statements.

F-2

HOUSTON AMERICAN ENERGY CORP.
STATEMENT OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004
--------------------------------------------------------------------------------

2005 2004
------------ ------------

REVENUE:
Oil and gas $ 2,780,457 $ 1,182,063
Commission income 60,000 -
Interest 34,191 6,058
------------ ------------

TOTAL REVENUE 2,874,648 1,188,121

OPERATING EXPENSES
Lease operating and production tax 953,624 413,723
Joint venture expense 61,500 41,944
Depreciation and depletion 363,196 211,759
General and administrative expense
Professional fees 504,742 150,603
Payroll expense 192,040 48,742
Rent 41,014 39,772
Shareholder relations 14,019 29,363
Travel and meals 21,650 16,046
Dues and subscriptions 10,618 11,141
Miscellaneous 51,746 37,745
------------ ------------
Total expenses 2,214,149 1,000,838
------------ ------------

OPERATING INCOME 660,499 187,283

OTHER EXPENSE
Interest expense-Derivative (319,714) -
Net change in fair value of derivative liabilities (402,628) -
Interest expense (111,920) -
Interest expense on shareholder debt (72,000) (72,000)
Financing fees (16,816) -
------------ ------------
Total other expense (923,078) (72,000)
------------ ------------

(LOSS) INCOME BEFORE INCOME TAX (262,579) 115,283

PROVISION FOR INCOME TAX
Current 239,201 -
Deferred - -
------------ ------------
TOTAL INCOME TAX PROVISION 239,201 -
------------ ------------

NET (LOSS) INCOME $ (501,780) $ 115,283
============ ============

BASIC AND DILUTED INCOME PER SHARE $ (0.03) $ 0.01
============ ============

BASIC AND DILUTED WEIGHTED AVERAGE SHARES 19,970,553 19,619,084
============ ============

The accompanying notes are an integral part of these financial statements.

F-3

HOUSTON AMERICAN ENERGY CORP.
STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004
----------------------------------------------------------------------------------------------------------------

Common Stock Treasury Stock Accumulated
------------------------------- ---------------------
Paid - in Equity
Shares Amount Capital Shares Amount (Deficit) Total
---------- ------- ---------- ---------- --------- ------------ -----------

Balance at December 31, 2003 19,285,106 $19,285 $2,299,767 $ - $ - $(1,671,334) $ 647,718

Stock issued for -
Cash 532,983 533 349,910 350,443
Services 150,000 150 150,350 150,500
Purchase of treasury stock (100,000) (85,834) (85,834)

Net income - - - - - 115,283 115,283
---------- ------- ---------- ---------- --------- ------------ -----------

Balance at December 31, 2004 19,968,089 $19,968 $2,800,027 (100,000) $(85,834) $(1,556,051) $1,178,110

Stock issued for -
Services 2,500 3 2,447 - - - 2,450
Stock options issued - - 49,447 - - - 49,447
Net income - - - - - (501,780) (501,780)
---------- ------- ---------- ---------- --------- ------------ -----------

Balance at December 31, 2005 19,970,589 $19,971 $2,851,921 (100,000) $(85,834) $(2,057,831) $ 728,227
========== ======= ========== ========== ========= ============ ===========

The accompanying notes are an integral part of these financial statements.

F-4

HOUSTON AMERICAN ENERGY CORP.
STATEMENT OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2005 AND 2004
------------------------------------------------------------------------

2005 2004
------------ ----------

CASH FLOW FROM OPERATING ACTIVITIES
Income (loss) from operations $ (501,780) $ 115,283

ADJUSTMENTS TO RECONCILE NET INCOME (LOSS)
TO NET CASH FROM OPERATIONS
Depreciation and depletion 363,196 211,759
Non-cash expenses 51,895 17,166
Derivative expense 722,342
(Increase) in accounts receivable (333,180) (174,138)
(Increase) decrease in prepaid expense 79,983 (84,009)
(Increase) decrease in other assets 16,816 36,864
Increase in accounts payable
and accrued expenses 295,309 175,070
------------ ----------

Net cash provided by operations 694,581 297,995
------------ ----------

CASH FLOW FROM INVESTING ACTIVITIES
Acquisition of properties and assets (1,589,594) (611,897)
Funds in excess of prospect costs - 21,650
------------ ----------

Net cash used in investing activities (1,589,594) (590,247)
------------ ----------

CASH FLOW FROM FINANCING ACTIVITIES
Sale of common stock - net of costs - 350,443
Issuance of debt, net of costs 1,997,500 -
Payment on loans from principal shareholder (100,000) -
------------ ----------

Net cash provided by financing 1,897,500 350,443
------------ ----------

INCREASE IN CASH 1,002,487 58,191
Cash, beginning of period 721,613 663,422
------------ ----------

Cash, end of period $ 1,724,100 $ 721,613
============ ==========

SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid $ 150,865 $ 67,600
Taxes paid $ - $ -

SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING
AND FINANCING ACTIVITIES
Stock issued for oil and gas activity $ - $ 47,500

The accompanying notes are an integral part of these financial statements.

F-5

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2005
----------------------------------

NOTE 1. - NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

GENERAL -Houston American Energy Corp. (a Delaware Corporation) ("the Company"
-------
or "HUSA") was incorporated on April 2, 2001. The Company is engaged, as a
non-operating joint owner, in the exploration, development, and production of
natural gas, crude oil, and condensate from properties located principally in
the Gulf Coast area of the United States and international locations with proven
production, which to date has focused on Columbia, South America.

GENERAL PRINCIPLES AND USE OF ESTIMATES - The financial statements have been
--------------------------------------------
prepared in conformity with accounting principles generally accepted in the
United States of America. In preparing financial statements, Management makes
informed judgments and estimates that affect the reported amounts of assets and
liabilities as of the date of the financial statements and affect the reported
amounts of revenues and expenses during the reporting period. On an ongoing
basis, Management reviews its estimates, including those related to such
potential matters as litigation, environmental liabilities, income taxes and
determination of proved reserves. Changes in facts and circumstances may result
in revised estimates and actual results may differ from these estimates.

Certain amounts for prior periods have been reclassified to conform to the
current presentation.

OIL AND GAS REVENUES - The Company recognizes sales revenues based on the amount
--------------------
of gas, oil and condensate sold to purchasers when delivery to the purchaser has
occurred and title has transferred. This occurs when production has been
delivered to a pipeline. Currently, the Company does not anticipate that the
oil and gas sold will be significantly different from the Company's production
entitlement.

OIL AND GAS PROPERTIES AND EQUIPMENT - The Company uses the full cost method of
-------------------------------------
accounting for exploration and development activities as defined by the SEC.
Under this method of accounting, the costs for unsuccessful, as well as
successful, exploration and development activities are capitalized as oil and
gas properties. Capitalized costs include lease acquisition, geological and
geophysical work, delay rentals, costs of drilling, completing and equipping the
wells and any internal costs that are directly related to acquisition,
exploration and development activities but does not include any costs related to
production, general corporate overhead or similar activities. Gain or loss on
the sale or other disposition of oil and gas properties is not recognized,
unless the gain or loss would significantly alter the relationship between
capitalized costs and proved reserves of oil and natural gas attributable to a
country.

The Company categorizes its full costs pools as costs subject to amortization
and costs not being amortized. The sum of net capitalized costs subject to
amortization, including estimated future development and abandonment costs, are
amortized using the unit-of-production method.

Office equipment is stated at original cost and is depreciated on the
straight-line basis over the useful life of the assets, which ranges from three
to five years. Oil and gas properties and office equipment carrying values do
not purport to represent replacement or market values.

Depreciation expense for office equipment was $2,175 and $2,175 at December 31,
2005 and 2004, respectively and accumulated reserved for depreciation was $7,633
at December 31, 2005. Depletion and amortization for oil and gas properties was
$359,521 and $206,584 at December 31, 2005 and 2004, respectively and
accumulated reserve for depletion and amortization was $1,364,918 at December
31, 2005. Repairs and maintenance are expensed as incurred.

F-6

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2005
----------------------------------

COSTS EXCLUDED - Oil and gas properties include costs that are excluded from
---------------
capitalized costs being amortized. These amounts represent costs of investments
in unproved properties. The Company excludes these costs on a country-by-country
basis until proved reserves are found or until it is determined that the costs
are impaired. All costs excluded are reviewed quarterly to determine if
impairment has occurred. The amount of any impairment is transferred to the
costs subject to amortization.

CEILING TEST - Under the full cost method of accounting, a ceiling test is
-------------
performed each quarter. The full cost ceiling test is an impairment test
prescribed by Securities and Exchange Commission (SEC") Regulation S-X. The
ceiling test determines a limit, on a country-by-country basis, on the book
value of oil and gas properties. The capitalized costs of proved oil and gas
properties, net of accumulated depreciation, depletion and amortization ("DD&A")
and the related deferred income taxes, may not exceed the estimated future net
cash flows from proved oil and gas reserves, using prices in effect at the end
of the period with consideration of price change only to the extent provided by
contractual arrangement, discounted at 10%, net of related tax effects. If
capitalized costs exceed this limit, the excess is charged to expense and
reflected as additional accumulated DD&A.

Proved oil and gas reserves, as defined by SEC Regulation S-X, are the estimated
quantities of crude oil, natural gas, and condensate which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.

Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery are included as proved developed
reserves only after testing by a pilot project or after the operation of an
installed program has confirmed through production response that increased
recovery will be achieved.

Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage are limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units are claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive formation.

The Company emphasizes that the volumes of reserves are estimates, which, by
their nature, are subject to revision. The estimates are made using all
available geological and reservoir data, as well as production performance data.

These estimates, made by an independent reservoir engineer (approximately 65% of
reserves) and a reservoir engineer that is a shareholder and director, are
reviewed and revised, either upward or downward, as warranted by additional
data. Revisions are necessary due to changes in assumptions based on, among
other things, reservoir performance, prices, economic conditions and
governmental restrictions. Decreases in prices, for example, may cause a
reduction in some proved reserves due to uneconomical conditions.

Unevaluated oil and gas properties not subject to amortization at December 31,
2005 include the following:

F-7

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2005
----------------------------------

North South
America America Total
-------- -------- --------

Acquistion costs $ 44,548 $ - $ 44,548
Geological, geophysical and screening costs 307 151,039 151,346
-------- -------- --------
Total $ 44,855 $151,039 $195,894
======== ======== ========

ASSET RETIREMENT OBLIGATIONS - The Company has adopted SFAS 143, "Accounting for
----------------------------
Asset Retirement Obligations," which addresses accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. For the company, asset retirement obligations
("ARO") represent the systematic, monthly accretion and depreciation of future
abandonment costs of tangible assets such as platforms, wells, service assets,
pipelines, and other facilities. SFAS 143 requires that the fair value of a
liability for an asset's retirement obligation be recorded in the period in
which it is incurred if a reasonable estimate of fair value can be made, and
that the corresponding cost is capitalized as part of the carrying amount of the
related long-lived asset. The liability is accreted to its then present value
each period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, an adjustment is made to the full cost pool, with no gain or loss
recognized, unless the adjustment would significantly alter the relationship
between capitalized costs and proved reserves. Under the company's previous
accounting method, the company included estimated future costs of abandonment
and dismantlement in full cost amortization base and amortized these costs as a
component of depletion expense. Subsequent to adoption of SFAS 143, the ARO
assets, which are carried on the balance sheet as part of the full cost pool,
have been included in our amortization base for the purposes of calculating
depreciation, depletion and amortization expense. For the purposes of
calculating the ceiling test, the future cash outflows associated with settling
the ARO liability have been included in the computation of the discounted
present value of estimated future net revenues.

The following table describes changes in our asset retirement liability during
each of the years ended December 31, 2005 and 2004. The ARO liability in the
table below includes amounts classified as both current and long-term at
December 31, 2005 and 2004.

Years Ended December 31,
2005 2004
------------- -------------

ARO liability at January 1, $ 39,952 $ 15,625
Accretion expense 4,504 3,000
Liabilities incurred from drilling 20,505
Liabilities incurred - assets acquired 3,501
Liabilities settled - assets abandoned (17,423)
Changes in estimates (9,790) 21,327
------------- -------------

ARO liability at December 31 $ 41,249 $ 39,952
============= =============

JOINT VENTURE EXPENSE - Joint venture expense reflects the indirect field
-----------------------
operating and regional administrative expenses billed by the operator of the
Columbian CaraCara and Tambaqui concessions.

F-8

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2005
----------------------------------

INCOME TAXES - Deferred income taxes are provided on a liability method whereby
-------------
deferred tax assets and liabilities are established for the difference between
the financial reporting and income tax basis of assets and liabilities as well
as operating loss and tax credit carry forwards. Deferred tax assets are
reduced by a valuation allowance when, in the opinion of management, it is more
likely than not that some portion or all of the deferred tax assets will not be
realized. Deferred tax assets and liabilities are adjusted for the effects of
changes in tax laws and rates on the date of enactment.

PREFERRED STOCK - The Company has authorized 10,000,000 shares of preferred
----------------
stock with a par value of $.001. The Board of Directors shall determine the
designations, rights, preferences, privileges and voting rights of the preferred
stock as well as any restrictions and qualifications thereon. No shares of
preferred stock have been issued.

STATEMENT OF CASH FLOWS - Cash equivalents consists of demand deposits and cash
------------------------
investments with initial maturity dates of less than three months.

NET LOSS PER SHARE - Basic loss per share is computed by dividing the net loss
--------------------
available to common shareholders by the weighted average of common shares
outstanding during the period. Diluted per share amounts assume the conversion,
exercise, or issuance of all potential common stock instruments unless the
effect is anti-dilutive, thereby reducing the loss or increasing the income per
share.

CONCENTRATION OF RISK - The Company is dependent upon the industry skills and
-----------------------
contacts of John F. Terwilliger, the sole director and chief executive officer,
to identify potential acquisition targets in the onshore coastal Gulf of Mexico
region of Texas and Louisiana. Further, as a non-operator oil and gas
exploration and production company and through its interest in a limited
liability company and four concessions in the South American country of
Colombia, the Company is dependent on the personnel, management and resources of
those entities to operate efficiently and effectively.

As a non-operating joint interest owner, the Company has a right of investment
refusal on specific projects and the right to examine and contest its division
of costs and revenues determined by the company operator.

The Company currently has interests in several concessions in Colombia and
expects to be active in Colombia for the foreseeable future. The political
climate in Colombia is unstable and could be subject to radical change over a
very short period of time. In the event of a significant negative change in
political and economic stability in the vicinity of the Company's Colombian
operations, the Company may be forced to abandon or suspend their efforts.
Either of such events could be harmful to the Company expected business
prospects.

At December 31, 2005, 68% of the Company's net oil and gas property investment
and 73% of its revenue was with or derived from the company managing the
Columbian properties.

The majority of the oil production for 2005 from the Company's mineral interests
were sold to an international integrated oil company (96%) The gas production is
sold to U.S. natural gas marketing company based on the highest bid. There were
no other product sales of more than 10% to a single buyer.

The Company maintains its cash in two banks in Houston, Texas. The total cash
balance is insured by the F.D.I.C. up to $100,000 per bank. The Company had
cash balances on deposit with the two banks in Houston, Texas that exceeded the
balances insured by the F.D.I.C. by $1,524,000.

Stock-Based Compensation - In December 2002, the Financial Accounting Standards
Board ("FASB") issued SFAS No. 148, "Accounting for Stock-Based Compensation -
Transition and Disclosure," which amends SFAS No. 123. SFAS No. 148 provides
alternative methods of transition for a voluntary change to the fair value based
method of accounting for stock-based compensation. In addition, SFAS No. 148
amends the disclosure requirements of SFAS No. 123 to require prominent
disclosures in both annual and interim financial statements about the method of
accounting for stock-based employee compensation and the effect of the method
used on reported results of operations. As the Company has not elected to
change to the fair value based method of accounting for stock based employee
compensation, the adoption of SFAS No. 148 did not have a material impact on the
Company's financial position or results of operations. All disclosure
requirements of SFAS No. 148 have been adopted and are reflected in these
financial statements.

The Company accounts for stock-based employee compensation arrangements in
accordance with provisions of Accounting Principles Board ("APB") Opinion No.
25, "Accounting for Stock Issued to Employees," and related interpretations, and
complies with the disclosure provisions of SFAS No. 123, "Accounting for
Stock-Based Compensation." Under APB 25, compensation expense is based on the
difference, if any, on the date of grant between the fair value of the Company's
stock and the amount an employee must pay to acquire the stock. The Company
accounts for stock and options to non-employees at fair value in accordance with
the provisions of SFAS No. 123 and the Emerging Issues Task Force Consensus on
Issue No. 96-18.

RESTATEMENT OF INTERIM QUARTERS
-------------------------------

F-9

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2005
----------------------------------

The Company has recently determined that its original accounting for the
Subordinated Convertible Notes ("Convertible Notes") and Warrants ("Warrants")
issued on May 4, 2005, were not reported in accordance with generally accepted
accounting principles. The Notes were originally recorded at their notional
amounts; and the fair value of the Warrants was included in Shareholders'
Equity. The Company subsequently determined that the Convertible Notes and
Warrants contain detachable and embedded derivatives. The Company has revised
its accounting for the Convertible Notes and Warrants in this filing, and will
concurrently file amendments to its previously filed Forms 10-QSB for the three
and six months ended June 30, 2005, and the three and nine months ended
September 30, 2005.

SUBORDINATED CONVERTIBLE NOTES AND WARRANTS- DERIVATIVE FINANCIAL INSTRUMENTS
-----------------------------------------------------------------------------

The Convertible Notes and the Warrants have been accounted for in accordance
with SFAS 133 and EITF No. 00-19, "Accounting for Derivative Financial
Instruments Indexed to, and Potentially Settled in, a Company's Own Stock."

The Company has identified the following instruments and derivatives:
Convertible Notes
Conversion feature
Conversion price reset feature
Company's optional redemption right
Warrants
Warrants exercise price reset feature

The Single Compound Embedded Derivatives within Convertible Notes and the
Derivative Liability for Warrants have been recorded at fair value at the date
of issuance (May 4, 2005); and are marked-to-market each quarter with changes in
fair value recorded to the Company's income statement as "Net change in fair
value of derivative liabilities." The Company has utilized a third party
valuation firm to fair value the single compound embedded derivatives under the
following methods: a layered discounted probability-weighted cash flow approach
for the Single Compound Embedded Derivatives within Convertible Notes; and the
Black-Scholes model for the Derivative Liability for Warrants based on a
probability weighted exercise price".

F-10

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2005
----------------------------------

RECENT ACCOUNTING DEVELOPMENTS - In April 2005, the Securities and Exchange
--------------------------------
Commission amended the effective date of Statement of Financial Accounting
Standards No. 123R, "Share Based Payment" ('SFAS 123R"), from the first interim
or annual period after June 15, 2005 to the beginning of the next fiscal year
that begins after June 15, 2005. SFAS 123R requires that the cost of all
share-based payments to employees, including grants of employee stock options,
be recognized in the financial statements based on their fair values. That cost
will be recognized as an expense over the vesting period of the award. Pro forma
disclosures previously permitted under SFAS 123 no longer will be an alternative
to financial statement recognition. In addition, the Company will be required to
determine fair value in accordance with SFAS 123R. The Company does not expect
that SFAS 123R will have a material impact on its consolidated financial
statements.

In May 2005, the Financial Accounting Standards Board ('FASB") issued
Statement of Financial Accounting Standards No. 154, "Accounting Changes and
Error Corrections-a replacement of APB Opinion No. 20 and FASB Statement No.
3"('SFAS 154"), which is effective for accounting changes and corrections of
errors made in fiscal years beginning after December 15, 2005. SFAS 154 applies
to all voluntary changes in accounting principles, and changes the accounting
and reporting requirements for a change in accounting principle. SFAS 154
requires retrospective application to prior periods' financial statements of a
voluntary change in accounting principle unless it is impracticable. APB 20
previously required that most voluntary changes in accounting principle be
recognized by including in net income of the period of the change the cumulative
effect of changing to the new accounting principle. SFAS 154 also requires that
a change in depreciation, amortization, or depletion method for long-lived, non
financial assets be accounted for as a change in accounting estimate effected by
a change in accounting principle. SFAS 154 carries forward without change the
guidance in APB 20 for reporting the correction of an error in previously issued
financial statements, a change in accounting estimate and a change in reporting
entity, as well as the provisions of SFAS 3 that govern reporting accounting
changes in interim financial statements. The Company does not expect that SFAS
154 will have a material impact on its consolidated financial statements.

In December 2004, the FASB issued Statement of Financial Accounting
Standards No. 153, "Exchanges of Nonmonetary Assets - an amendment of APB
Opinion No. 29" ("SFAS No. 153"). Previous guidance regarding the accounting
for nonmonetary assets was based on the principle that exchanges of nonmonetary
assets should be measured based on the fair value of the assets exchanged. This
previous guidance, however, included certain exceptions to that principle, SFAS
No. 153 amends APB Opinion No. 29 to eliminate the exception for nonmonetary
exchanges of similar productive assets and replaces it with a general exception
for exchanges of nonmonetary assets that do not have commercial substance. A
nonmonetary exchange has commercial substance if the future cash flows of the
entity are expected to change significantly as a result of the exchange. The
provisions of SFAS No. 153 are generally effective for nonmonetary asset

F-11

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2005
----------------------------------

exchanges occurring in fiscal periods beginning after June 15, 2005. The
Company does not expect the adoption of SFAS No. 153 will have a material impact
on its consolidated financial statements.

In March 2005, the FASB issued Interpretation No. 47, Accounting for
Conditional Asset Retirement Obligations (FIN 47). FIN 47 is an interpretation
of FAS No. 143, Asset Retirement Obligations, and relates to the timing of
liability recognition for legal obligations associated with the retirement of a
tangible long-lived asset in which the timing and (or) method of settlement are
conditional on a future event that may or may not be within the control of the
entity. The adoption of FIN 47, effective December 31, 2005, did not have an
effect on the Company's consolidated results of operations or financial
position.

NOTE 2. - NOTES PAYABLE

NOTE PAYABLE - SHAREHOLDER

A note payable at December 31, 2005, in the amount of $900,000, is owed to John
Terwilliger, Chief Executive Officer, who is also a significant shareholder. The
note is not secured, bears interest at 7.2% and is due on January 1, 2007 with
interest paid monthly, based on cash flow.

SUBORDINATED CONVERTIBLE NOTES

On May 4, 2005, the Company entered into purchase agreements with multiple
investors pursuant to which the Company sold $2,125,000 of 8% subordinated
convertible notes due 2010.

The notes bear interest at 8%, provide for semi-annual interest payments and
mature May 1, 2010. The notes are convertible, at the option of the holders,
into common stock of the Company at a price of $1.00 per share, subject to
standard anti-dilution provisions relating to splits, reverse splits and other
transactions plus a reset provision whereby the conversion price may be adjusted
downward to a lower price per share if the Company issues its common stock to
others below the stated conversion price. The notes are subject to automatic
conversion in the event the Company conducts an underwritten public offering of
its common stock from which the Company receives at least $5 million and the
public offering price is at least 150% of the then applicable conversion price.
The Company has the right to cause the notes to be converted into common stock
after May 1, 2006 if the price of the Company's common stock exceeds 200% of the
then applicable conversion price on the date of conversion and for at least 20
trading days over the preceding 30 trading days. The Company has the right to
repurchase the Notes after May 1, 2007 at 103% of the face amount during 2007,
102% of the face amount during 2008, 101% of the face amount during 2009 and
100% of the face amount thereafter. The notes are unsecured general obligations
of the Company and are subordinated to all other indebtedness of the Company
unless the other indebtedness is expressly made subordinate to the notes.

The conversion feature, the conversion price, reset provision and the Company's
optional early redemption right have been bundled together as a single compound
embedded derivative liability, and using a layered discounted
probability-weighted cash flow approach, was initially fair valued (as amended-
see restatement in Note 1) at $2,368,485 at May 4, 2005. The fair value model
comprises multiple probability-weighted scenarios under various assumptions
reflecting the economics of the Convertible Notes, such as the risk-free
interest rate, expected Company stock price and volatility, likelihood of
conversion and or redemption, and likelihood default status and timely
registration. At inception, the fair value of this single compound embedded
derivative was bifurcated from the host debt contract and recorded as a
derivative liability which

F-12

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2005
----------------------------------

resulted in a reduction of the initial notional carrying amount of the
Convertible Notes (as unamortized discount which will be amortized over a
five-year period under the effective interest method). At inception the excess
of the unamortized discount over the notional amount of the Convertible Note in
the amount of $285,547 was charged to expense in the Company's statement of
operations.

At May 4, 2005 (inception as amended), the Convertible Notes were adjusted as
follows:

Notional balance of Convertible Notes at inception $ 2,125,000
Adjustment-Discount for single compound derivative liability (2,125,000)
------------
Convertible Notes balance at inception, as adjusted $ -
============

At December 31, 2005, the Convertible Notes comprised the following:

Notional balance of Convertible Notes at December 31, 2005 $ 2,125,000
Adjustment-Discount for single compound derivative liability (2,090,833)
------------
Convertible Notes balance at December 31, 2005, as adjusted $ 34,167
============

For the period from inception of the Convertible Notes (May 4, 2005) through
December 31, 2005, the amortization of unamortized discount on the Convertible
Notes was $34,167, which has been classified as interest expense in the
accompanying statement of operation.

The Derivative Liability-Compound Embedded Derivatives within Convertible Notes
reflect the following activity for the period from inception (May 4, 2005)
through December 31, 2005:

Balance at inception (May 4, 2005) $2,368,485
Mark-to-market adjustment for the period from inception through December 31, 2005 15,561
----------
Balance at December 31, 2005 $2,384,046
==========

WARRANTS

On May 4, 2005, the Company entered into three year warrant agreements (the
'Warrants") with nine parties whereby 191,250 warrants were issued at an
exercise price of $1.00 per share, subject to a reset provision whereby the
exercise price would be adjusted downward in the event the Company issued its
common stock to others at a price below the initial warrant exercise price. This
reset provision represents an embedded derivative, which has not been bifurcated
from the host warrant contract (as both are derivatives) and has been a
derivative liability at its fair value at date of inception utilizing the
Black-Scholes method with a probability weighted exercise price. This fair value
model comprises multiple probability-weighted scenarios under various
assumptions reflecting the economics of the warrants, such as risk free interest
rate, expected Company stock price and volatility, likelihood of exercise, and
timely registration. The assumptions used at December 31, 2005 were a risk-free
interest rate of 3.08%, volatility of 40%, expected term of 2.3 years, dividend
yield of 0.00% and a probability weighted exercise price of $.983. The common
stock warrants and the embedded warrant price reset provision were initially
fair valued (as amended-see restatement in Note 1) at $42,063 at May 4, 2005. At
inception, the amount of the value assigned over the notional amount of the
Convertible Note in the amount of $42,063 was charged to expense in the
Company's statement of operations.

The Derivative Liability-Compound Embedded Derivatives within Warrants reflect
the following activity for the period from inception (May 4, 2005) through
December 31, 2005.

F-13

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2005
----------------------------------

Balance at inception (May 4, 2005) $ 42,063
Mark-to-market adjustment for the period from inception through December 31, 2005 387,067
--------
Balance at December 31, 2005 $429,130
========

Activity of warrants during the year ended December 31, 2005 is as follows:

Weighted
Average
Warrants Share Price
-------- ------------

Outstanding at beginning of period - -
Granted 191,250 $ 1.00
-------- ------------
Outstanding at end of period 191,250 $ 1.00
======== ============

Warrants outstanding and exercisable as of December 31, 2005:

Exercise Number of Remaining Number of
Price Shares Life Shares
--------- --------- --------- ---------

1.00 191,250 2.58 191,250
========= ========= ========= =========

CHANGE IN FAIR VALUE OF DERIVATIVE LIABILITIES

For the period from inception of the Convertible Notes and Warrants (May 4,
2005) through December 31, 2005, the change in fair value of the derivative
liabilities includes the following:

Derivative Liability-Compound Embedded Derivatives within Convertible Notes $ 15,561
Derivative liability-Compound Embedded Derivatives within Common Stock Warrants 387,067
--------
Net increase in fair value of derivative liabilities $402,628
========

NOTE 3. - RELATED PARTIES

In conjunction with the Company's efforts to secure oil and gas prospects,
financing and services, it has, from time to time, granted overriding royalty
interests in the Company's various mineral properties to John F. Terwilliger,
Chief Executive Officer, and Orrie L. Tawes, a significant shareholder. During
2005 and 2004, approximately $60,000 and $36,000, respectively, was paid to John
Terwilliger and Orrie L. Tawes from these royalty interests.

NOTE 4 - INCOME TAXES

F-14

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2005
----------------------------------

The following table sets forth a reconciliation of the statutory federal income
tax for the year ended December 31, 2005 and 2004.

2005 2004
---------- ---------

(Loss) income before income taxes $(262,579) $115,238
========== =========

Income tax computed at statutory rates $ (89,277) $ 39,196
Derivative expense 245,596 -
Effect of foreign tax provision, before effect of
changes in tax rate, on the total tax provision 171,247 -
Permanent differences, nondeductible expenses 1,934 7,168
Increase (decrease) in valuation allowance (96,766) (58,264)
Other 6,467 11,900
---------- ---------

Tax provision $ 239,201 $ -
========== =========

Current provision
United States $ - $ -
Foreign 239,201 -
Deferred provision - -
---------- ---------
Total provision $ 239,201 $ -
========== =========

No federal income taxes have been paid since the inception of the Company. The
Company has a net operating loss carry forward of approximately $1,173,000 which
will expire in 2016 through 2018. In addition, the Company has approximately
$239,000 of foreign tax credit carryforward which will expire in 2016. The
Company's net operating loss carryforwards may be subject to annual limitations,
which could reduce or defer the utilization of the loss as a result of an
ownership change as defined in section 382 of the Internal Revenue Code.

The tax effects of the temporary differences between financial statement income
and taxable income are recognized as a deferred tax asset and liability.
Significant components of the deferred tax asset and liability as of December
31, 2005 are set out below.

2005 2004
---------- ----------

Deferred tax asset:
Net operating loss carryforwards $ 398,888 $ 459,550
Foreign tax credit carryforward 239,201
Asset retirement obligation 15,115 13,584
Valuation allowance (420,450) (337,259)
Book over tax depreciation, depletion
and capitalization methods on oil
and gas properties (234,250) (137,371)
Book over tax accrued interest payments 1,496 1,496
---------- ----------

Net deferred tax asset $ - $ -
========== ==========

F-15

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2005
----------------------------------

FOREIGN INCOME TAXES
----------------------

The Company owns an interest in a Limited Liability Company that operates the
activities in Columbia. Colombia's tax rate is 38.5%. Based on information
provided by the manager of the LLC the company has determined their share of the
Columbia tax liability for 2005 will be $239,201. This amount has been accrued
in the fourth quarter and will be funded by withholdings from the revenue
received in 2006.

NOTE 5. - STOCK OPTION

On August 12, 2005, the Company's Board of Directors adopted the Houston
American Energy Corp. 2005 Stock Option Plan (the "Plan"). The terms of the Plan
allow for the issuance of options to purchase 500, 000 shares of the Company's
common stock. Persons eligible to participate in the Plan are key employees,
consultants and directors of the Company. During the year the Company granted
60,000 options to the members of the Board of Directors and 29,000 to
consultants.

The fair value of the options granted to consultants was valued on the date of
the grant using the Black-Scholes option-pricing model with the following
assumptions, risk-free interest rate of 4.29%, expected life of 10 years ,
expected stock volatility of 40%, expected dividend yield 0.0%. Using this model
yielded a value of $49,447 which was charge to expense in 2005.

The fair value of the options granted to members of the board of directors was
valued on the date of the grant using the Black-Scholes option-pricing model
with the following assumptions, risk-free interest rate of 4.29%, expected life
of 10 years , expected stock volatility of 40%, expected dividend yield 0.0%. If
the Company had accounted for the option as recommended in SFAS 123, directors
fee expense would have had the following pro forma effect on our net loss and
earnings per share for the year ended December 31, 2005.

Net loss as reported $(501,780)
Less: Directors fees determined using fair value method (69,600)
----------

Net (loss) $(571,380)
==========

Net loss per share - as reported $ (0.03)

Net loss per share pro-forma $ (0.03)

Option activity during 2005 is as follows:

F-16

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2005
----------------------------------

Weighted
Average
Options Share Price
------- ------------

Outstanding at beginning of year - $ -

Granted 89,000 2.42
Excersied - -
Forfieted - -
------- ------------
Outstanding at end of year 89,000 $ 2.42
======= ============

NOTE 6. - COMMON STOCK

During the year ended December 31, 2005, the Company issued 2,500 shares of its
common stock for services valued at $2,450.

NOTE 7. - COMMITMENTS AND CONTINGENCIES

LEASE COMMITMENT - The Company leases office facilities under an operating lease
----------------
agreement which expires November 30, 2006. The lease agreement requires payments
of $33,026 in 2006. Total rental expense in 2005 was $41,014 and $39,772 in
2004. The Company does not have any capital leases or other operating lease
commitments.

LEGAL CONTINGENCIES - The Company is subject to legal proceedings, claims and
--------------------
liabilities that arise in the ordinary course of its business. The Company
accrues for losses associated with legal claims when such losses are probable
and can be reasonably estimated. These accruals are adjusted as further
information develops or circumstances change. During the twelve months ended
December 31, 2005, the Company was named as defendant in a suit filed in the
United States Bankruptcy Court for the Southern District of Texas. The Company
settled the bankruptcy litigation. The Company paid the $25,000 to settle the
case.

DEVELOPMENT COMMITMENTS - During the ordinary course of oil and gas prospect
------------------------
development, the Company commits to a proportionate share for the cost of
acquiring mineral interest, drilling exploratory or development wells and
acquiring seismic and geological information. At January 1, 2006, our
acquisition and drilling budget for 2006 totaled $1,700,000.

POST RETIREMENT BENEFITS - At December 31, 2005, the Company does not have any
--------------------------
pension plans, other postretirement benefits or employee savings plans.

NOTE 8 - SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND
PRODUCTION ACTIVITIES (UNAUDITED)

This footnote provides unaudited information required by Statement of Financial
Accounting Standards No. 69, "Disclosures about Oil and gas Producing
Activities".

GEOGRAPHICAL DATA - The following table shows the Company's oil and gas revenues
-----------------
and lease operating expenses, which includes the joint venture expenses incurred
in South America, by geographic area:

F-17

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2005
----------------------------------

2005 2004

REVENUES
North America $ 739,384 $ 373,591
South America 2,041,072 808,472
---------- ----------

$2,780,456 $1,182,063
========== ==========

PRODUCTION COST
North America $ 79,542 $ 59,275
South America 874,082 354,448
---------- ----------
$ 953,624 $ 413,723
========== ==========

CAPITAL COSTS - Capitalized costs and accumulated depletion relating to the
--------------
Company's oil and gas producing activities as of December 31, 2005, all of which
are onshore properties located in the United States and Columbia, South America
are summarized below:

NORTH SOUTH
AMERICA AMERICA TOTAL
----------- ----------- ------------

Unproved properties not
being amortized $ 44,855 $ 151,039 $ 195,894

Properties being amortized 1,760,286 2,039,944 3,800,230
Accumulated depreciation, depletion
and amortization (960,053) (404,865) (1,364,918)
----------- ----------- ------------

Total capitalized costs $ 845,088 $1,786,118 $ 2,631,206
=========== =========== ============

AMORTIZATION RATE
-----------------

The amortization rate per unit based on barrel equivalents was $6.08 for North
America and $6.82 for South America.

ACQUISITION, EXPLORATION AND DEVELOPMENT COSTS INCURRED -Costs incurred in oil
---------------------------------------------------------
and gas property acquisition, exploration and development activities for
December 31, 2005 and 2004 is summarized below:

2005
----------------------
North South
America America
---------- ----------

Property acquisition costs:
Proved $ 733,719 $ 355,000
Unproved 44,548 -
Exploration costs 954,916 1,508,388
Development costs 71,950 324,398
---------- ----------

Total costs incurred $1,805,133 $2,187,786
========== ==========

F-18

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2005
----------------------------------

2004
----------------------
North South
America America
---------- ----------

Property acquisition costs:
Proved $ 776,219 $ 405,002
Unproved 48,636 12,159
Exploration costs 428,476 128,275
Development costs 21,077 583,685
---------- ----------

Total costs incurred $1,274,408 $1,129,121
========== ==========

RESERVE INFORMATION AND RELATED STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET
--------------------------------------------------------------------------------
CASH FLOWS -
-----------

The supplemental unaudited presentation of proved reserve quantities and related
standardized measure of discounted future net cash flows provides estimates only
and does not purport to reflect realizable values or fair market values of the
Company's reserves. Volumes reported for proved reserves are based on
reasonable estimates. These estimates are consistent with current knowledge of
the characteristics and production history of the reserves. The Company
emphasizes that reserve estimates are inherently imprecise and that estimates of
new discoveries are more imprecise than those of producing oil and gas
properties. Accordingly, significant changes to these estimates can be expected
as future information becomes available.

Proved reserves are those estimated reserves of crude oil (including condensate
and natural gas liquids) and natural gas that geological and engineering data
demonstrate with reasonable certainly to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed reserves are those expected to be recovered through existing wells,
equipment, and operating methods.

Independent petroleum engineers estimated proved reserves for the Company's
properties which represented approximately 65% of total estimated future net
revenues at December 31, 2005. The remaining reserves were estimated by a
petroleum engineer who is also a shareholder and director of the Company.
Reserve definitions and pricing requirements prescribed by the Securities and
Exchange Commission were used. Total estimated proved developed and undeveloped
reserves by product type and the changes therein are set forth below for the
years indicated.

F-19

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2005
----------------------------------

North America South America Total
--------------------- -------------------- ---------------------
Gas (mcf) Oil (bbls) Gas(mcf) Oil (bbls) Gas (mcf) Oil (bbls)
--------------------- -------------------- ---------------------

Total proved reserves
Balance December 31, 2003 176,600 4,400 - 269,707 176,600 274,107
Extensions and discoveries 54,458 11,274 - 264,981 54,458 276,255
Revisions of prior estimates 32,881 (3,198) - (214,948) 32,881 (218,146)
Production (61,519) (886) - (24,040) (61,519) (24,926)
--------- ---------- -------- ---------- --------- ----------
Balance December 31, 2004 202,420 11,590 - 295,700 202,420 307,290

Extensions and discoveries 270,536 424 - 146,109 270,536 146,533
Revisions of prior estimates 456,656 (7,810) - (128,290) 456,656 (136,100)
Production (78,962) (1,404) - (42,898) (78,962) (44,302)
--------- ---------- -------- ---------- --------- ----------
Balance December 31, 2005 850,650 2,800 - 270,621 850,650 273,421
========= ========== ======== ========== ========= ==========

Proved developed reserves
at December 31, 2004 141,000 2,500 97,610 141,000 100,110
========= ========== ========== ========= ==========
at December 31, 2005 364,970 560 - 200,437 364,970 200,997
========= ========== ======== ========== ========= ==========

The standardized measure of discounted future net cash flows relating to proved
oil and gas reserves is computed by applying year-end prices of oil and gas
(with consideration of price changes only to the extent provided by contractual
arrangements) to the estimated future production of proved oil and gas reserves,
less estimated future expenditures (based on year-end costs) to be incurred in
developing and producing the proved reserves, less estimated related future
income tax expenses (based on year-end statutory tax rates, with consideration
of future tax rates already legislated), and assuming continuation of existing
economic conditions. Future income tax expenses give effect to permanent
differences and tax credits but do not reflect the impact of continuing
operations including property acquisitions and exploration. The estimated
future cash flows are then discounted using a rate of ten percent a year to
reflect the estimated timing of the future cash flows.

F-20

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2005
----------------------------------

Standard measure of discounted future net cash flows at December 31, 2005:

NORTH SOUTH
AMERICA AMERICA TOTAL
-------------------------------------

Future net cash flows $7,838,800 $13,738,632 $21,577,432
Future production cost 3,596,700 5,281,244 8,877,944
Future income tax expense 413,513 3,608,140 4,021,653
---------- ----------- ------------
Future net cash flow 3,828,587 4,849,248 8,677,835
10% annual discount for timing of cash flows 1,217,161 1,085,074 2,302,235
---------- ----------- ------------

Standardized measure of discounted future net
cash flow relating to proved oil and gas reserves $2,611,426 $ 3,764,174 $ 6,375,600
========== =========== ============

Changes in standardized measure:

Change due to current year operations
Sales, net of production costs $(1,826,833)
Changes due to revisions in standardized variables:
Income taxes (2,530,084)
Accretion of discount 517,721
Net change in sales and transfer price, net of production costs 1,332,704
Revision and others (1,374,796)
Discoveries 4,865,019
Changes in production rates and other 1,386,245
------------
Net 2,369,976
Beginning of year 4,005,624
------------

End of year $ 6,375,600
============

F-21

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2005
----------------------------------

Standard measure of discounted future net cash flows at December 31, 2004:

NORTH SOUTH
AMERICA AMERICA TOTAL
---------- ----------- ------------

Future net cash flows $1,693,780 $10,018,312 $11,712,092
Future production cost 267,550 4,709,171 4,976,721
Future income tax expense 271,884 1,219,685 1,491,569
---------- ----------- ------------
Future net cash flow 1,154,346 4,089,456 5,243,802
10% annual discount for timing of cash flows 310,053 928,125 1,238,178
---------- ----------- ------------

Standardized measure of discounted future net
cash flow relating to proved oil and gas reserves $ 844,293 $ 3,161,331 $ 4,005,624
========== =========== ============

Changes in standardized measure:

Change due to current year operations
Sales, net of production costs $ (726,396)
Changes due to revisions in standardized variables:
Income taxes (516,350)
Accretion of discount 389,559
Revision and others (2,329,947)
Discoveries 4,016,119
------------
Net 832,985
Beginning of year 3,172,639
------------

End of year $ 4,005,624
============

F-22