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, 2003

[ ] 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
incorporation or organization) Identification No.)

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: (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 disclosure of delinquent filers in response to Item 405 of
Regulation S-B is not contained in this form, and will not 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]

The Issuer's revenues for the fiscal year ended December 31, 2003 were
$220,600.

The number of shares of the registrant's common stock, $.001 par value per
share, outstanding as of March 22, 2004 was 19,513,089. The aggregate market
value of the voting and non-voting common equity held by non-affiliates of the
registrant on March 22, 2004, based on the last sales price on the OTC Bulletin
Board as of such date, was approximately $6,648,354.

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 . . . . . . . . . . . . . . . . . 12
ITEM 3. LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . 12
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF
SECURITY HOLDERS. . . . . . . . . . . . . . . . . . . . . 12

PART II

ITEM 5. MARKET FOR COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS . . . . . . . . . . . . . . . 13
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS. . . . . . . . . . . 14
ITEM 7. FINANCIAL STATEMENTS. . . . . . . . . . . . . . . . . . . 19
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE. . . . . . . . . . 19
ITEM 8A. CONTROLS AND PROCEDURES . . . . . . . . . . . . . . . . . 19

PART III

ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND
CONTROL PERSONS; COMPLIANCE WITH
SECTION 16(a) OF THE EXCHANGE ACT . . . . . . . . . . . . 19
ITEM 10. EXECUTIVE COMPENSATION. . . . . . . . . . . . . . . . . . 19
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT . . . . . . . . . . . . . . . . . . 19
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. . . . . . 19
ITEM 13. EXHIBITS AND REPORTS OF FORM 8-K. . . . . . . . . . . . . 20
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES. . . . . . . . . . 22

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. In addition to seeking out oil and gas prospects using advanced
seismic techniques, we utilize the contacts of John F. Terwilliger, our sole
director and executive officer, to identify potential acquisition targets in the
Onshore Texas Gulf Coast Region of the State of Texas, where Mr. Terwilliger has
been involved in oil and gas exploration and production activities since 1983.
Further, we have, through an interest in a limited liability company, interests
in two concessions in the South American country of Colombia. As a result, we
expect to be active in Colombia for the foreseeable future. Moreover, as well
as our own drilling activities and acquisition strategy, we may also encourage
others in the oil and gas industry to enter into partnerships or joint ventures
with us for the purpose of acquiring properties and conducting drilling and
exploration activities.

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, 2003 consisted on the
following:

LAVACA COUNTY, TEXAS. In Lavaca County, Texas, we hold two separate interests
consisting of a 5% non-participating royalty interest in a 150 acre tract known
as the Mavis Wharton Lease and a 38% working interest in a 65.645 acre tract
known as the West Hardys Creek Prospect.

The Mavis Wharton #3 well was drilled on the Mavis Wharton Lease and, following
completion, experienced production problems. The well was reworked and
determined to be non-commercial and abandoned. We have been advised that a deep
gas test is planned to include the Mavis Wharton Lease. Our royalty interest in
the Mavis Wharton Lease does not bear any costs of well operations.

The Goyen #1 well was drilled on the West Hardys Creek Prospect in the third
quarter of 2003. The Goyen #1 well tested the Frio and Miocene Sands to a depth
of 3,000 feet. The Goyen #1 well was successfully completed in September 2003
and commenced production as a gas well with an initial production rate of 350MCF
per day. We presently have no plans with respect to drilling additional wells
on the West Hardys Creek Prospect.

MATAGORDA COUNTY, TEXAS. In Matagorda County, Texas, we hold two separate
interests consisting of a 3.5% working interest with a 2.415% net revenue
interest in a 779 acre tract known as the S.W. Pheasant Prospect and an option
to participate, based on a 3.5% working interest with a 2.415% net revenue
interest, in a 672 acre tract known as the Turtle Creek Prospect.

A well was successfully completed on the S.W. Pheasant Prospect in July 2003
with initial production rates from the Frio K Sand of 1400 MCF and 35 barrels of
oil per day. Pursuant to our option covering the adjacent Turtle Creek
Prospect, we anticipate participating in the drilling of a well on the Turtle
Creek Prospect within the next year. Other than the anticipated well on the
Turtle Creek Prospect, we presently have no plans with respect to drilling
additional wells in Matagorda County.

JACKSON COUNTY, TEXAS. In Jackson County, Texas, we hold a 100% leasehold,
subject to a 27% royalty, on an 80 acre tract known as the W. Harmon Prospect.
At December 31, 2003, we had developed a plan with respect to drilling of the
Miller #1 well on the W. Harmon Prospect and had engaged an operator to drill a
7,300 foot test well. Drilling of the Miller #1 is expected to begin in the
third quarter of 2004 if we are successful in resolving certain location and gas
line issues with the surface owner.

ST. JOHN THE BAPTIST PARISH, LOUISIANA. In St. John the Baptist Parish,
Louisiana, we hold a 2% working interest with a 1.44% net revenue interest in a
726 acre leasehold known as the Bougere Estate and the Bougere Estate #1 well.
The Bougere Estate #1 well was completed in June 2003 with initial production of
200 barrels of oil and 170 MCF of gas per day. Commercial production of the
well commenced in December 2003 following installation of a gas sales pipeline.
We presently have no additional plans with respect to drilling additional wells
on the Bougere Estate.

LLANOS BASIN, COLOMBIA. In the Llanos Basin, Colombia, we hold an interest,
through our ownership in Hupecol, LLC, in a 357,000 acre tract known as the Cara
Cara concession. In conjunction with our acquisition of 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 covering 88,000 acres
in the State of Casanare, Colombia.

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 December 2003, Hupecol commenced drilling an additional three wells on the
Cara Cara concession as offsets to, and to delineate, the Jaguar #1 well.

Included in our interest in the Tambaqui Association Contract is an interest in
a producing well, the Tambaqui #1, and in two exploration wells. The first
exploration well drilled as an offset to the Tambaqui #1, the Tambaqui #1Am, was
dry. We expect to commence drilling another offset to the Tambaqui #1 well by
April 2004.

In conjunction with the efforts to develop the Cara Cara concession, Hupecol has
acquired 50 square miles of 3D seismic grid surrounding the Jaguar #1 well and
two other prospect areas. That data is expected to be 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 our exploration projects in Colombia are subject to an
escalating royalty of 8% on the first 5,000 barrels of oil per day 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.

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 expected to be utilized to
map prospects in key areas with a view to delineating multiple drilling
opportunities beginning in 2004. We will hold a 12.5% interest in all prospects
developed by Hupecol arising from the acquired seismic data.

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

Acres Leased or Under Option at
December 31, 2003 (1)
-------------------------------------------------
Project Project Company Net Project
Project Area Gross Net Interest
------------------------------- ------------- ---------- ----------- ---------

TEXAS:

Lavaca County, Texas

Mavis Wharton. . . . . . . . 300.00 150.00 7.50 5.00%

West Hardys Creek. . . . . . 65.65 65.65 24.95 38.00%

Jackson County, Texas

W. Harmon Prospect . . . . . 80.00 80.00 80.00 100.00%

San Patricio County, Texas

St. Paul Prospect. . . . . . 380.00 380.00 19.00 5.00%

Matagorda County, Texas

S.W. Pheasant Prospect . . . 779.00 779.00 27.27 3.50%

Turtle Creek Prospect. . . . 672.00 672.00 23.52 3.50%
------------- ---------- -----------
Texas Sub-Total . . . . . . . . 2,276.65 2,126.65 182.24

LOUISIANA:

St. John the Baptist Parish,

Louisiana . . . . . . . . . . 726.00 726.00 14.52 2.00%
------------- ---------- -----------
Louisiana Sub-Total . . . . . . 726.00 726.00 14.52 2.00%

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 . . . . 357,000.00 357,000.00 5,676.30 1.59%

Tambaqui Assoc. Contract (2) 88,000.00 88,000.00 11,088.00 12.6%
------------- ---------- -----------
Colombia Sub-Total. . . . . . . 445,000.00 445,000.00 16,764.30
------------- ---------- -----------
Total . . . . . . . . . . . . . 448,162.65 448,012.65 16,964.84
============= ========== ===========

(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

From April 2001 (inception of the Company) through December 31, 2003, we drilled
9 exploratory and developmental wells, of which 7 were completed and 2 were dry
holes. In 2001, 3 exploratory and 0 developmental wells were drilled of which 2
were completed and 1 was a dry hole. In 2002, 2 exploratory and 0 developmental
wells were drilled of which 2 were completed and 0 were dry holes. In 2003, 3
exploratory and 1 developmental wells were drilled of which 3 were completed and
1 was a dry hole

The following table sets forth certain information regarding the actual drilling
results for each of the years 2002 and 2003 as to wells drilled in each such
individual year:

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

2002
----

Productive . . . . . . . . 2 0.04 0 0

Dry. . . . . . . . . . . . 0 0.00 0 0

2003
----

Productive . . . . . . . . 3 0.435 0 0

Dry. . . . . . . . . .. . . 0 0 1 0.125

(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, 2003, on the Cara Cara concession in
Colombia.

PRODUCTIVE WELL SUMMARY

The following table sets forth certain information regarding our ownership as of
December 31, 2003 of productive gas and oil wells in the areas indicated:

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

Texas. . . . . . . . . 2 0.415 0 0

Louisiana. . . . . . . 1 0.020 0 0

Oklahoma . . . . . . . 1 0.024 0 0

Colombia . . . . . . . 0 0.000 2 0.141
---------- ---------- ---------- ----------

Total . . . . . . 4 0.459 2 0.141
========== ========== ========== ==========

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,
----------------------
2002 2003
---------- ----------

Net Production:

Gas (Mcf):

United States . . . 8,957 15,993
Columbia. . . . . . na 0

Oil (Bbls):

United States . . . 0 246
Columbia. . . . . . 0 5,880

Average sales price:

Gas ($per Mcf) . . . . . 2.88 5.11

Oil (Bbls) . . . . . . . na 30.17

Average production expense and
Taxes ($per Bble):

United States . . . . 2.17 2.35
Columbia. . . . . . . na 24.88

NATURAL GAS AND OIL RESERVES

The following table summarizes the estimates of our historical net proved
reserves as of December 31, 2002 and 2003, 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,
------------------------
2002 2003
------------ ----------

Net proved reserves (1):
Natural gas (Mcf) . . . . . . . . . . . 18,872 176,600

Oil (Bbls). . . . . . . . . . . . . . . 0 274,107

Standardized measure of discounted future net
cash flows (2) . . . . . . . . . . . . . . . $ 41,289 $3,172,639

(1) At December 31, 2003, net proved reserves, by region, consisted of
269,707 barrels of oil in Columbia and 4,400 barrels of oil in the U.S.;
all natural gas reserves were in the U.S.

(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 prospectus 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, 2003, 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. . . . . . . 225.65 30.55 480.00 16.80 1,571.00 134.90

Louisiana. . . . . 300.00 6.00 0.00 0.00 426.00 8.52

Oklahoma . . . . . 160.00 3.78 0.00 0.00 0.00 0.00

Colombia . . . . . 640.00 27.65 3,320.00 88.16 441,040.00 16,648.49
-------- ------ -------- -------- ---------- ---------

Total . . . . 1,325.65 67.98 3,800.00 104.96 443,037.00 16,791.91
======== ====== ======== ======== ========== =========

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 1, 2004, we had no contractual agreements to sell our gas and oil
production and all production was sold on spot markets.

RISKS RELATED TO OUR OIL AND GAS OPERATIONS

Operational Hazards and Insurance. Our development, exploitation and exploration
activities may be unsuccessful for many reasons, including weather, cost
overruns, equipment shortages and mechanical difficulties. Moreover, the
successful drilling of a natural gas and oil well does not ensure a profit on
investment. A variety of factors, both geological and market related can cause
a well to become uneconomical or only marginally profitable. Our business
involves a variety of operating risks which may adversely affect our
profitability, including:

- fires;

- explosions;

- blow-outs and surface cratering;

- uncontrollable flows of oil, natural gas, and formation water;

- natural disasters, such as hurricanes and other adverse weather
conditions;

- pipe, cement, or pipeline failures;

- casing collapses;

- embedded oil field drilling and service tools;

- abnormally pressured formations; and

- environmental hazards, such as natural gas leaks, oil spills, pipeline
ruptures and discharges of toxic gases.

In accordance with industry practice, our insurance protects us against some,
but not all, operational risks. Further, we do not carry business interruption
insurance at levels that would provide enough cash for us to continue operating
without access to additional funds. As pollution and environmental risks
generally are not fully insurable, our insurance may be inadequate to cover any
losses or exposure for such liability.

Volatility of Oil and Gas Prices. As an independent oil and gas producer, our
revenue, profitability and future rate of growth are substantially dependent
upon the prevailing prices of, and demand for, natural gas, oil, and condensate.
Our realized profits affect the amount of cash flow available for capital
expenditures. Our ability to maintain or increase our borrowing capacity and to
obtain additional capital on attractive terms is also substantially dependent
upon oil and gas prices. Prices for oil and natural gas are subject to wide
fluctuation in response to relatively minor changes in the supply of, and demand
for, oil and gas, market uncertainty and a variety of additional factors that
are beyond our control. Among the factors that can cause the volatility of oil
and gas prices are:

- worldwide or regional demand for energy, which is affected by economic
conditions;

- the domestic and foreign supply of natural gas and oil;

- weather conditions;

- domestic and foreign governmental regulations;

- political conditions in natural gas and oil producing regions;

- the ability of members of the Organization of Petroleum Exporting
Countries to agree upon and maintain oil prices and production levels;
and

- the price and availability of other fuels.

OPERATIONS IN COLOMBIA

As described above, we currently have interests in two concessions in the South
American country of Colombia and expect 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 our Colombian operations, we may be forced to abandon or suspend our efforts.
Either of such events could be harmful to our expected business prospects.

COMPETITION

Competition in the oil and gas industry is intense and we compete with major and
other independent oil and gas companies with respect to the acquisition of
producing properties and proved undeveloped acreage. Our competitors actively
bid for desirable oil and gas properties, as well as for the equipment and labor
required to operate and develop the properties. Many of those competitors,
however, have financial resources and exploration and development budgets that
are substantially greater than ours and may be able to absorb the burden of any
changes in federal, state and local laws and regulations more easily than we can
do so, which would adversely affect our competitive position. These competitors
may be able to pay more for natural gas and oil properties and may be able to
define, evaluate, bid for and purchase a greater number of properties than we
can. Our ability to acquire additional properties and develop new and existing
properties in the future will depend on our capability to conduct operations, to
evaluate and select suitable properties and to consummate transactions in this
highly competitive environment.

GOVERNMENTAL REGULATION

Our business and the oil and gas industry in general are subject to extensive
laws and regulations, including environmental laws and regulations. As such, we
may be required to make large expenditures to comply with environmental and
other governmental regulations. State and federal regulations, including those
enforced by the Texas Railroad Commission as the primary regulator of the oil
and gas industry in the State of Texas, are generally intended to prevent waste
of oil and gas, protect rights to produce oil and gas between owners in a common
reservoir and control contamination of the environment. Matters subject to
regulation in the State of Texas include:

- location and density of wells;

- the handling of drilling fluids and obtaining discharge permits for
drilling operations;

- accounting for and payment of royalties on production from state,
federal and Indian lands;

- bonds for ownership, development and production of natural gas and oil
properties;

- transportation of natural gas and oil by pipelines;

- operation of wells and reports concerning operations; and

- taxation.

Under these laws and regulations, we could be liable for personal injuries,
property damage, oil spills, discharge of hazardous materials, remediation and
clean-up costs and other environmental damages. Failure to comply with these
laws and regulations also may result in the suspension or termination of our
operations and subject us to administrative, civil and criminal penalties.
Moreover, these laws and regulations could change in ways that substantially
increase our operating costs.

Natural gas operations are subject to various types of regulation at the
federal, state and local levels. Prior to commencing drilling activities for a
well, we are required to procure permits and/or approvals for the various stages
of the drilling process from the applicable state and local agencies. Permits
and approvals include those for the drilling of wells, and regulations including
maintaining bonding requirements in order to drill or operate wells and the
location of wells, the method of drilling and casing wells, the surface use and
restoration of properties on which wells are drilled, the plugging and
abandoning of wells, and the disposal of fluids used in connection with
operations.

Our operations are also subject to various conservation laws and regulations.
These include the regulation of the size of drilling and spacing units and the
density of wells, which may be drilled and the unitization or pooling of natural
gas properties. In this regard, some states allow the forced pooling or
integration of tracts to facilitate exploration while other states rely
primarily or exclusively on voluntary pooling of lands and leases. In areas
where pooling is voluntary, it may be more difficult to form units, and
therefore, more difficult to develop a project if the operator owns less than
100 percent of the leasehold.

Regulation of Sales and Transportation of Natural Gas. Historically, the
transportation and resale of natural gas in interstate commerce have been
regulated by the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978,
and the regulations promulgated by the Federal Energy Regulatory Commission.
Maximum selling prices of some categories of natural gas sold in "first sales,"
whether sold in interstate or intrastate commerce, were regulated under the
NGPA. The Natural Gas Well Head Decontrol Act removed, as of January 1, 1993,
all remaining federal price controls from natural gas sold in "first sales" on
or after that date. FERC's jurisdiction over natural gas transportation was
unaffected by the Decontrol Act. While sales by producers of natural gas and
all sales of crude oil, condensate and natural gas liquids can currently be made
at market prices, Congress could reenact price controls in the future.

Sales of natural gas are affected by the availability, terms and cost of
transportation. The price and terms for access to pipeline transportation are
subject to extensive regulation. In recent years, FERC has undertaken various
initiatives to increase competition within the natural gas industry. As a
result of initiatives like FERC Order No. 636, issued in April 1992, the
interstate natural gas transportation and marketing system has been
substantially restructured to remove various barriers and practices that
historically limited non-pipeline natural gas sellers, including producers, from
effectively competing with interstate pipelines for sales to local distribution
companies and large industrial and commercial customers. The most significant
provisions of Order No. 636 require that interstate pipelines provide
transportation separate or "unbundled" from their sales service, and require
that pipelines make available firm and interruptible transportation service on
an open access basis that is equal for all natural gas suppliers.

In many instances, the result of Order No. 636 and related initiatives has been
to substantially reduce or eliminate the interstate pipelines' traditional role
as wholesalers of natural gas in favor of providing only storage and
transportation services. Another effect of regulatory restructuring is the
greater transportation access available on interstate pipelines. In some cases,
producers and marketers have benefited from this availability. However,
competition among suppliers has greatly increased and traditional long-term
producer pipeline contracts are rare. Furthermore, gathering facilities of
interstate pipelines are no longer regulated by FERC, thus allowing gatherers to
charge higher gathering rates.

Environmental Regulations. Our operations are subject to additional laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. Public interest in the
protection of the environment has increased dramatically in recent years. It
appears that the trend of more expansive and stricter environmental legislation
and regulations will continue.

We generate wastes that may be subject to the Federal Resource Conservation and
Recovery Act ("RCRA") and comparable state statutes, which have limited the
approved methods of disposal for some hazardous wastes. Additional wastes may be
designated as "hazardous wastes" in the future, and therefore become subject to
more rigorous and costly operating and disposal requirements. Although
management believes that we utilize good operating and waste disposal practices,
prior owners and operators of our properties may not have done so, and
hydrocarbons or other wastes may have been disposed of or released on or under
the properties owned or leased by us or on or under locations where wastes have
been taken for disposal. These properties and the wastes disposed on the
properties may be subject to the Comprehensive Environmental Response,
Compensation and Liability Act ("CERCLA"), RCRA and analogous state laws, which
require the removal and remediation of previously disposed wastes, including
waste disposed of or released by prior owners or operators.

CERCLA and similar state laws impose liability, without regard to fault or the
legality of the original conduct, on some classes of persons that are considered
to have contributed to the release of a "hazardous substance" into the
environment. These persons include the owner or operator of the disposal site or
sites where the release occurred and companies that disposed of or arranged for
the disposal of the hazardous substances found at the site. Persons who are or
were responsible for release of hazardous substances under CERCLA may be subject
to joint and several liability for the costs of cleaning up the hazardous
substances that have been released into the environment and for damages to
natural resources, and it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the hazardous substances released into the environment.

EMPLOYEES

As of March 1, 2004, we had one 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
three additional employees over the next six to eight months.

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

As of March 1, 2004, we were not party to any pending litigation and were not
aware of any threatened litigation.

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

None

PART II

ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Since January 18, 2002, our Common Stock has been 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 2003

Fourth Quarter . . . . . . . . . . $0.75 $0.38
Third Quarter. . . . . . . . . . . 0.52 0.31
Second Quarter . . . . . . . . . . 0.42 0.23
First Quarter. . . . . . . . . . . 0.51 0.30

Calendar Year 2002

Fourth Quarter . . . . . . . . . . $0.40 $0.11
Third Quarter. . . . . . . . . . . 0.40 0.11
Second Quarter . . . . . . . . . . 0.72 0.23
First Quarter. . . . . . . . . . . 0.75 0.05

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

At March 22, 2004, the closing bid price of the Common Stock was $0.85.

As of March 22, 2004, there were approximately 1,012 beneficial holders of our
Common Stock.

In December 2003, John Terwilliger, the President and sole Director of the
Company, acquired 1,103,791 shares of the Company's common stock in exchange for
the conversion of outstanding loans in the amount of $441,516.29 and Orrie Lee
Tawes acquired 465,042 shares of the Company's common stock in exchange for the
conversion of outstanding loans in the amount of $186,016.83.

In December 2003, the Company issued an aggregate of 1,405,966 shares of common
stock for a purchase price of $562,371 to fourteen accredited investors, being
E.C. Broun III, Lior Bergman, Rochelle Zudkewich, Amit Solomon, Jack Lahav,
LibertyView Funds, LP, Pudding Hill Partners, Lincoln Partners Group LLC, Andrew
Arno, J. Mitchell Hull, William Hyler, LibertyView Special Opportunities Fund,
LP, David B. Wheeler, and Stephen P. Hartzell.

The issuance of all shares of our common stock described above was pursuant to
the exemption from registration provided by Section 4(2) of the Securities Act
of 1933, as amended and related state private offering exemptions. All of the
investors were Accredited Investors as defined in the Securities Act who took
their shares for investment purposes without a view to distribution and had
access to information concerning the Company and its business prospects, as
required by the Securities Act.

In addition, there was no general solicitation or advertising for the purchase
of our shares. Our securities were sold only to persons with whom we had a
direct personal preexisting relationship, and after a thorough discussion. All
certificates for our shares contain a restrictive legend. Finally, our stock
transfer agent has been instructed not to transfer any of such shares, unless
such shares are registered for resale or there is an exemption with respect to
their transfer.

No commissions were paid in connection with the issuances described above.

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 director and 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 DEVELOPMENT FROM INCEPTION TO DECEMBER 2003

We were incorporated in April 2001 and consummated a merger with Texas Nevada
Oil and Gas Co. ("TNOG") in January 2002.

Our initial efforts in 2001 and 2002 consisted of the evaluation and assembly of
various interests in oil and gas properties in the onshore Gulf Coast of Texas
and Louisiana regions. Pursuant to those efforts, we acquired varying interests
in (1) two properties in Lavaca County, Texas, (2) two properties in Matagorda
County, Texas, and (3) one property in Jackson County, Texas.

In January 2003, we acquired, from Rio Exploration Company for $312,500, a 12.5%
interest in Hupecol, LLC and in the Tambaqui Association Contract. Through the
acquisition of the interest in Hupecol and in the Tambaqui Association Contract,
we acquired interests in two properties in the South American country of
Colombia. Subsequently, in December 2003, we exercised our right, through
Hupecol, to participate in the acquisition of over 3,000 kilometers of seismic
data in Colombia covering in excess of 20 million acres.

In 2003, we acquired interests in properties in St. John the Baptist Parish,
Louisiana, Oklahoma and San Patricio County, Texas.

From inception through December 31, 2002, we had drilled four domestic wells in
Lavaca County, Texas. Two of the wells had been completed and were awaiting a
pipeline hook-up, one of the wells was dry and one was being completed at
December 31, 2002. The Mavis Wharton #3 well in Lavaca County, Texas
experienced production problems and was unsuccessfully reworked and, ultimately,
abandoned, in 2003. During fiscal year 2003, we drilled (1) one successful
well in Matagorda County, Texas, (2) one successful well in Lavaca County,
Texas, and (3) one successful well in Louisiana. A test well in San Patricio
County, Texas was drilled in January 2004 with completion scheduled to follow
and a test well in Jackson County, Texas (the Miller #1) is scheduled to begin

drilling in the third quarter of 2004 if we are successful in resolving certain
location and gas line issues with the surface owner.

The acquisition of our interest in the Colombian properties included a producing
well, the Tambaqui #1. An offset well to that well was drilled as a dry hole in
2003. A second offset well is scheduled to commence drilling by April 2004.

The second Colombian property, the Cara Cara concession, was successfully tested
with the completion of the Jaguar #1 well in April 2003. Our Colombian venture
acquired 50 square miles of 3D seismic grid covering the Cara Cara concession
and two other prospect areas. In December 2003, drilling began on the first of
three wells planned to offset, and to delineate, the Jaguar #1 well.

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, 2003. 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. An allowance for impairment of
$109,573 and $574,331 was provided at December 31, 2002 and 2001, respectively.

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, 2002 and 2003:

At December 31, 2002 At December 31, 2003
--------------------- ---------------------

Acquisition costs $ 68,000 $ 103,404

Evaluation costs 120,418 23,470
--------------------- ---------------------

Total $ 188,418 $ 126,874
===================== =====================

The carrying value of unevaluated oil and gas prospects include $57,747 and
$5,617 expended for properties in the South American country of Colombia at
December 31, 2002 and December 31, 2003, respectively. We are maintaining our
interest in these properties and development has or is anticipated to commence
within the next twelve months.

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2003 COMPARED TO YEAR ENDED DECEMBER 31, 2002

Oil and Gas Revenues. Total oil and gas revenues increased $194,795 to $220,600
in fiscal 2003 when compared to fiscal 2002. Consequently, total oil and gas
revenues increased by 759% for the year ended December 31, 2003 when compared to
the year ended December 31, 2002. This increase is attributable to the full
implementation of the Company's drilling and development program, which was
initiated in 2002. At the end of 2002 there was one revenue producing property,
the Kalmus. At December 31, 2003, the Company had three commercial wells in the
U.S. and two commercial wells in Columbia and the Kalmus gas well was plugged
and abandon at mid-year. Following is a summary comparison of revenues for the
years ended December 31, 2003 and 2002.

Columbia U.S. Total
--------- ------- --------

Year ended 2003
Oil sales $ 128,520 $11,957 $140,477
Gas sales 0 80,123 80,123
Year ended 2002
Gas sales 0 25,805 25,805

Fiscal 2002 sales were from the gas production of the Kalmus well. That well
was abandoned in May of 2003 with gas revenues to that date of $28,958.

Lease Operating Expenses. Lease operating expenses, excluding joint venture
expenses relating to our Columbian operations discussed below, increased 657% to
$146,914 in 2003 from $19,397 in 2002. The increase in lease operating expenses
was attributable to the increase in the number of wells (5) operated during the
2003 period. Following is a summary comparison of revenues for the years ended
December 31, 2003 and 2003.

Columbia U.S. Total
--------- ------- --------

Year ended 2003 $ 109,348 $37,566 $146,914
Year ended 2002 0 19,397 19,397

The relatively high operating cost of the wells coming on the revenue stream in
Columbia is influenced by the fact that in their early developmental, daily
operating costs are generally reasonably certain at the commencement of
production. However, the per unit of production costs can vary greatly due to
the fact that certain operating and field administration costs include a
significant fixed component and that initial equivalent barrel production may be
lower or higher than the sustained production achieved over the life of the
well. It is management's opinion that the per unit production costs of all of
its new discoveries can be reduced substantially through optimizing the level of
production from existing wells or the drilling of additional wells. This may be
especially true with our two new Columbian wells where the per well
administrative costs are expected to be reduced as additional successful wells
are completed on the prospect acreage.

Joint Venture Expenses. Joint venture expenses totaled $36,940 in 2003. We
incurred no joint venture expenses in 2002. The joint venture expenses
represent our allocable share of the indirect field operating and region
administrative expenses billed by the operator of the Columbian CaraCara and
Tambaqui concessions.

Depreciation and Depletion Expense. Depreciation and depletion expense
increased by 57.2% to $56,434 in fiscal 2003 when compared to $24,166 in 2002.
The increase in depreciation and depletion expense was primarily attributable to
the increased production from new wells (5) coming on line during 2003.
Depletion on the U.S. wells was $33,135, which was disproportionately higher
because of the increase in the depletable "cost pool" with the abandonment of
the Kalmus well and the Lavaca county prospects. The remainder of the increase
is in the depletion ($23,299) associated with the Columbian ventures.

Interest Expense. Interest expense increased 26.6% to $142,349 in 2003 compared
to $112,405 in 2002. The interest expense increase was attributable to
additional borrowings ($194,200) from two principal shareholders to finance our
operations. In December 2003, those shareholders converted $627,530 of loans
and accrued interest to 1,568,825 of the Company's common stock and reduced the
interest rate on the remaining $1 million of loans from 10% to 7.2%. In
December 2003, we raised approximately $562,400 from the sale of common stock to
support our future operations. Accordingly, with the reduced shareholder loans
and with the reduced interest rate on current loans, interest expense is
expected to decline as much as 40% in fiscal 2004. The planned budget for 2004
also calls for interest to be paid current if monies are available from
operating cash flow.

General and Administrative Expenses. General and administrative expense
decreased by 7.7% to $182,293 in 2003 from the $197,518 experienced in 2002.
The decrease in G&A expense was attributable to a 32.1% decrease in professional
fees. In spite of the decrease in professional fees during 2003, we continue to
incur the high cost of accounting and legal fees associated with meeting our
reporting obligations as a public company. The decrease in the professional fee
component of G&A was partially offset by increases in other G&A expenses,
including a 37.6% increase in shareholders relations costs resulting from an
undertaking during 2002 and 2003 to increase our profile in the investment
community in light of our need to access capital to support our accelerated
exploration activities.

Write-Down of Oil and Gas Properties. During the 2002 period, we incurred a
charge of $109,573 relating to the write down of oil and gas properties. We
incurred no write-downs during 2003. The write-down during the 2002 period was
attributable to a determination, based on the findings in an independent reserve
report, that, at September 30, 2002, the capitalized cost of our oil and gas
properties exceeded the maximum carrying value under the full cost method of
accounting.

Gain on Settlement of Accounts Payable. During 2002, we reported a gain on the
settlement of accounts payable of $42,870. The gain arose from the settlement,
for less than face value, of certain previously recorded expenses/payables
associated with our becoming a public reporting company. We incurred no gain on
settlement of accounts payable during 2003.

FINANCIAL CONDITION

LIQUIDITY AND CAPITAL RESOURCES. At December 31, 2003, we had a cash balance of
$663,422 and working capital of $654,451 compared to a cash balance of $939 and
a deficit in working capital of $1.27 million at December 31, 2002. This change
in our working capital position, is attributable to the debt restructuring and
conversion in December of 2003. As previously mentioned, $627,530 of loans and
interest was converted to equity. In addition, the open shareholder loans were
restructured to long-term notes with a due date in 2007.

As discussed in our prior financial statements included herewith, our revenue
was insufficient to cover our costs and expenses. In addition to the income
received from our wells, certain significant shareholders, including John F.
Terwilliger, our sole director and executive officer, provided us the funds
needed to continue our development and operations. Our current business plan
projects positive cash flows from operation by the second quarter of fiscal 2004
and management anticipates raising any necessary funds for major capital
expenditures from outside investors or commercial bank or mezzanine lenders.

During 2003, we completed private placements of shares, raising $1,386,922, net
of costs, from the sale of 4,271,390 shares. These funds were raised to support
our working capital requirements, including our ongoing Colombian development
activities and our onshore domestic leasing, drilling and development programs.

Simultaneous with the closing of our December 2003 private placement, we issued
1,568,825 shares of common stock in full satisfaction of $627,530 of loans from
shareholders. The balance of the loans from shareholders in the amount of $1
million, including accrued interest, was converted into unsecured promissory
notes, with interest accruing at 7.2% per annum and with a maturity date of
January 1, 2007.

Loans from shareholders totaled $1,004,400, including accrued interest, at
December 31, 2003.

Capital and Exploration Expenditures and Commitments. Our principal capital and
exploration expenditures relate to our ongoing efforts to acquire, drill and
complete prospects. Historically, we have funded our capital and exploration
expenditures from funds borrowed from John F. Terwilliger, our principal
shareholder and officer. With the receipt of additional equity financing in
2003, we expect that future capital and exploration expenditures will be funded
principally through additional stock offerings, mezzanine loans, funds on hand
and funds generated from operations.

During 2003, we invested $770,769 for the acquisition and development of oil and
gas properties, consisting of (1) acquisition of a 12.5% interest in the
Tambaqui concession in Colombia, (2) acquisition of 3D seismic on the Cara Cara
concession in Colombia, (3) acquisition of a 2.4% working interest in the Jenny
#1-14 well in Oklahoma, and (4) drilling and/or completing expenses for the
Jaguar #1 well in Colombia, the Tambaqui #1 and the Tambaqui #1Am wells in
Colombia, the Harrison #1 well in Matagorda County, Texas, the Bougere Estate #1
well in Louisiana and the Goyen #1 well in Lavaca County, Texas.

At January 1, 2004, our acquisition and drilling budget for 2004 totaled
$420,000, consisting of (1) $28,500 for drilling of three wells in Colombia on
the Cara Cara concession and $173,350 to drill the Tambaqui #2, (2) $140,000 for
South Texas leasehold prospects that are to be purchased for resale, and (3)
$60,000 to $80,000 for the acquisition and drilling of the LaFurs well on the
South Sibley Prospect in Louisiana. 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.

Our only material contractual obligations requiring determinable future payments
on our part are a note payable to our principal shareholder and our lease
relating to our executive offices.

The following table details our contractual obligations as of December 31, 2003:

Payments due by period
------------------------------------------------------------
Total 2004 2005 - 2006 2007 - 2008 Thereafter
---------- ------- ------------ ------------ -----------

Long-term debt $1,000,000 $ 0 $ 0 $ 1,000,000 $ 0
Operating lease
commitments 112,288 39,631 72,657 0 0
---------- ------- ------------ ------------ -----------
Total $1,112,288 $39,631 $ 72,657 $ 1,000,000 $ 0
========== ======= ============ ============ ===========

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 employees, including officers, consultants
and third parties. As of December 31, 2003, we had granted ORRIs to affiliates
ranging from 1.0% to 4.02166% of our interest in selected properties. ORRI
payments during 2003 were estimated to total $3,600.

At December 31, 2003, we had two revenue producing wells in Columbia, two
revenue producing wells in south Texas and one revenue producing wells in south
Louisiana. Preliminary indications are that these wells will more than double
current monthly revenue at the current equivalent per barrel price in the
mid-twenty dollar range. At December 31, 2003, our total reserves had increased
to an estimated 340,344 equivalent barrels with an estimated discounted future
net revenue stream in excess of $3,172,639.

Management anticipates that our current financing strategy of private debt and
equity offerings, combined with an expected increase in revenues, will meet our
anticipated objectives and business operations for the next 12 months.
Management continues to evaluate producing property acquisitions as well as a
number of drilling prospects. Subject to our ability to obtain adequate
financing at the applicable time, we may enter into definitive agreements on one
or more of those projects.

OFF-BALANCE SHEET ARRANGEMENTS

We had no off-balance sheet arrangements or guarantees of third party
obligations at December 31, 2003.

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 24 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. Based on
this evaluation, our management, including the CEO, concluded that our
disclosure controls and procedures were effective. There have been no
significant changes in our internal controls or in other factors that could
significantly affect internal control subsequent to the evaluation.

PART III

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

The information required by this Item will be included in a definitive proxy
statement, pursuant to Regulation 14A, to be filed not later than 120 days after
the close of the Company's fiscal year. Such information is incorporated herein
by reference.

ITEM 10. EXECUTIVE COMPENSATION

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

ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

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

2.1 Amended and Restated Plan and Agreement of Merger dated
as of September 26, 2001, between Texas Nevada Oil &
Gas Co. and Houston American Energy Corp. (incorporated
by reference to Exhibit 2.1 to Amendment No. 5 to the
Company's Registration Statement on Form SB-2,
registration number 333-66638 (the "Company's
Registration Statement"), filed with the SEC on
November 30, 2001).

3.1 Certificate of Incorporation of Houston American Energy
Corp. filed April 2, 2001 (incorporated by reference to
Exhibit 3.1 to the Company's Registration Statement
filed with the SEC on August 3, 2001).

3.2 Certificate of Merger Merging Opportunity Acquisition
Company with and into Houston American Energy Corp.
filed April 12, 2001 (incorporated by reference to
Exhibit 3.2 to the Company's Registration Statement
filed with the SEC on August 3, 2001).

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

3.4 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 Company's
Registration Statement filed with the SEC on October 1,
2001).

3.5 Certificate of Merger Merging Texas Nevada Oil & Gas
Co. with and into Houston American Energy Corp. filed
January 17, 2002 (incorporated by reference to Exhibit
3.5 to the Company's Annual Report on Form 10-QSB filed
with the SEC on March 27, 2002).

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

4.2 Text of Preferred Stock Certificate of Houston American
Energy Corp. (incorporated by reference to Exhibit 4.2
to the Company's Registration Statement filed with the
SEC on August 3, 2001).

10.1 Model Form Operating Agreement dated April 6, 2001,
between Moose Operating Co., Inc. and Houston American
Energy Corp. (incorporated by reference to Exhibit 10.1
to the Company's Registration Statement filed with the
SEC on August 3, 2001).

10.2 Agreement to Assign Interests in Oil and Gas Leases
dated as of April 6, 2001, between Moose Oil & Gas
Company and Houston American Energy Corp. (incorporated
by reference to Exhibit 10.2 to the Company's
Registration Statement filed with the SEC on August 3,
2001).

10.3 Assignment of Interests in Oil and Gas Leases and Bill
of Sale effective as of April 6, 2001, between Moose
Oil & Gas Company and Houston American Energy Corp.
(incorporated by reference to Exhibit 10.3 to the
Company's Registration Statement filed with the SEC on
August 3, 2001).

10.4 Promissory Note of Houston American Energy Corp. in the
amount of $216,981.06 dated April 15, 2001, payable to
Moose Oil & Gas Company. (incorporated by reference to
Exhibit 10.4 to the Company's Registration Statement
filed with the SEC on August 3, 2001).

10.5 Plan and Agreement of Merger dated as of April 12,
2001, between Opportunity Acquisition Company and
Houston American Energy Corp. (incorporated by
reference to Exhibit 10.5 to the Company's Registration
Statement filed with the SEC on August 3, 2001).

10.6 Agreement dated as of March 23, 2001, between Unicorp,
Inc., Equitable Assets, Incorporated, Texas Nevada Oil
& Gas Co. and Opportunity Acquisition Company
(incorporated by reference to Exhibit 10.6 to the
Company's Registration Statement filed with the SEC on
August 3, 2001).

10.7 First Amendment of Agreement dated as of July 31, 2001,
between Unicorp, Inc., Equitable Assets, Incorporated,
Texas Nevada Oil & Gas Co. and Houston American Energy
Corp. (incorporated by reference to Exhibit 10.7 to the
Company's Registration Statement filed with the SEC on
August 3, 2001).

10.8 Gas Purchase Contract No. 36-1599 dated as of May 1,
2001, between Kinder Morgan Texas Pipeline, L.P. and
Moose Operating Co., Inc. (incorporated by reference to
Exhibit 10.8 to Amendment No. 1 to the Company's
Registration Statement filed with the SEC on October 1,
2001).

10.9 Gas Purchase Agreement dated July 31, 1997, between
Dominion Pipeline Company (as predecessor-in-interest
to Pinnacle Natural Gas Co.) and Moose Operating Co.,
Inc. (incorporated by reference to Exhibit 10.9 to
Amendment No. 1 to the Company's Registration Statement
filed with the SEC on October 1, 2001).

10.10 Model Form Operating Agreement dated December 11, 1997,
between Louis Dreyfus Natural Gas Corp., Seisgen
Exploration, Inc. and Moose Operating Co., Inc.
(incorporated by reference to Exhibit 10.10 to
Amendment No. 1 to the Company's Registration Statement
filed with the SEC on October 1, 2001).

10.11 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 Company's Registration
Statement filed with the SEC on November 21, 2001).

10.12 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 Company's Registration
Statement filed with the SEC on November 21, 2001).

10.13 Assignment of Term Royalty Interest dated July 18,
2002, between Houston American Energy Cop. and Marlin
Data Research, Inc. (incorporated by reference to
Exhibit 2.5 to the July 2002 8-K).

10.14 Bill of Sale dated July 18, 2002, between Houston
American Energy Cop. and Marlin Data Research, Inc.
(incorporated by reference to Exhibit 2.6 to the July
2002 8-K).

10.15 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 Company's Form 10-QSB for the quarter ended June
30, 2003 (the "June 2003 Form 10-QSB")).

10.16 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 Company's June 2003
Form 10-QSB).

10.17 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 Company's June 2003 Form 10-QSB).

10.18 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 Company's June 2003 Form
10-QSB).

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

10.20 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 Company's June 2003 Form 10-QSB).

10.21 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 Company's June 2003 Form 10-QSB).

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

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

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

10.25 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
Company's 2004 Registration Statement).

10.26 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
Company's 2004 Registration Statement).

14.1 Code of Ethics for CEO and Senior Financial Officers

31.1 Section 302 Certifications

32.1 Section 906 Certifications

(b) Reports on Form 8-K

None

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

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 24, 2004

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

In accordance with the Exchange Act, this report has been signed below by
the following persons on behalf of the registrant and in the capacities and on
the dates indicated.

Signatures Title Date
---------- ----- ----

/s/ John F. Terwilliger President, Director and March 24, 2004
JOHN F. TERWILLIGER Treasurer (Principal Executive
and Financial Officer)

HOUSTON AMERICAN ENERGY CORP.

INDEX TO FINANCIAL STATEMENTS

Independent Auditors Report . . . . . . . . . . . . . . . . . . . . . . . F-1

Balance Sheet as of December 31, 2003 . . . . . . . . . . . . . . . . . . F-2

Statements of Operations For the Years ended December
31, 2003 and 2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-3

Statements of Shareholders' Equity for the Years ended
December 31, 2003 and 2002. . . . . . . . . . . . . . . . . . . . . . . . F-4

Statements of Cash Flows For the Years Ended December
31, 2003 and 2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-5

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

INDEPENDENT AUDITORS REPORT

Houston American Energy Corp.
Houston, Texas

We have audited the accompanying balance sheet of Houston American Energy Corp.
as of December 31, 2003 and the related statements of operations, shareholders'
equity, and cash flows for the years ended December 31, 2003 and 2002. 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 auditing standards generally accepted
in the United States of America. 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, 2003, and the results of its operations and its cash flows for
the years ended December 31, 2003 and 2002 in conformity with accounting
principles generally accepted in the United States of America.

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

March 16, 2004
Houston, Texas

F-1

HOUSTON AMERICAN ENERGY CORP.
BALANCE SHEET
DECEMBER 31, 2003
===========================================================================

ASSETS
------

CURRENT ASSETS
Cash $ 663,422
Accounts receivable 66,003
Prepaid expenses 5,938
------------

TOTAL CURRENT ASSETS 735,363
------------

PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties, full cost method
Costs subject to amortization 1,617,581
Costs not being amortized 126,874
Office equipment 10,878
------------
Total properties 1,755,333
Accumulated depreciation and depletion oil and gas properties (802,096)
------------

PROPERTY, PLANT AND EQUIPMENT, NET 953,237
------------

OTHER ASSETS 40,030
------------

TOTAL ASSETS $ 1,728,630
============

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

CURRENT LIABILITIES
Accounts payable and accrued expenses $ 76,512
Accrued interest on shareholder loans 4,400
------------

TOTAL CURRENT LIABILITIES 80,912
------------

LONG-TERM DEBT
Notes payable to principal shareholder 1,000,000
------------

SHAREHOLDERS' EQUITY
Common stock, par value $.001;
100,000,000 shares authorized, 19,285,106 shares outstanding 19,285
Additional paid-in capital 2,299,767
Accumulated deficit (1,671,334)
------------

TOTAL SHAREHOLDERS' EQUITY 647,718
------------

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 1,728,630
============

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, 2003 AND 2002
==========================================================================

2003 2002
------------ ------------

OIL AND GAS REVENUE $ 220,600 $ 25,805
------------ ------------

EXPENSES OF OPERATIONS
Lease operating expense 146,914 19,397
Joint venture expense 36,940 -
Depreciation and depletion 56,434 24,166
Interest expense on shareholder debt 142,349 112,405
General and administrative expense
Accounting and legal 63,630 93,688
Rent 41,219 38,000
Shareholder relations 41,402 30,092
Miscellaneous 36,042 35,738
Write-down of oil and gas properties
due to ceiling limitation - 109,573
Gain from settled accounts payable - (42,870)
------------ ------------
Total expenses 564,930 420,189
------------ ------------

FEDERAL INCOME TAXES - -
------------ ------------

NET LOSS $ (344,330) $ (394,384)
============ ============

BASIC AND DILUTED LOSS PER SHARE $ (0.02) $ (0.03)
============ ============

BASIC WEIGHTED AVERAGE SHARES 15,398,070 12,119,842
============ ============

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, 2003 AND 2002
===========================================================================================

Common Stock
-------------------------------
Paid - in Accumulated
Shares Amount Capital Deficit Total
---------- ------- ---------- ------------- ------------

Balance at December 31, 2001 11,403,414 $11,403 $ - $ (932,620) $ (921,217)

Stock issued for -
Reverse merger with
Texas Nevada Oil and Gas Co. 596,469 597 - - 597
Cash 1,350,000 1,350 268,650 - 270,000
Consulting services 75,000 75 14,925 - 15,000

Net loss - - - (394,384) (394,384)
---------- ------- ---------- ------------- ------------
Balance at December 31, 2002 13,424,883 13,425 283,575 (1,327,004) (1,030,004)

Shares issued for -
Cash 4,271,390 4,271 1,382,650 1,386,922
Stock issued for services 20,000 20 7,580 7,600
Converted shareholder debt 1,568,825 1,569 625,961 627,530

Net loss - - - (344,330) (344,330)
---------- ------- ---------- ------------- ------------

Balance at December 31, 2003 19,285,098 $19,285 $2,299,767 $ (1,671,334) $ 647,718
========== ======= ========== ============= ============

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, 2003 AND 2002
=========================================================================================

2003 2002
----------- ----------

CASH FLOW FROM OPERATING ACTIVITIES
Loss from operations $ (344,330) $(394,384)

ADJUSTMENTS TO RECONCILE NET LOSS TO
NET CASH FROM OPERATIONS
Depreciation and depletion 56,434 24,166
Write-down oil and gas properties - 109,573
Non-cash expenses 13,641 38,076
Gain from payable settlement - (42,871)
(Increase) in accounts receivable (58,863) (1,921)
(Increase) decrease in prepaid expense 1,088 1,116
(Increase) decrease in other assets (35,285) 796
Increase in accounts payable
and accrued expenses 213,616 108,076
----------- ----------

Net cash (used) provided by operations (153,699) (157,373)
----------- ----------

CASH FLOW FROM INVESTING ACTIVITIES
Acquisition of properties and assets (764,940) (210,427)
----------- ----------

CASH FLOW FROM FINANCING ACTIVITIES
Sale of common stock - net of costs 1,386,922 285,000
Loans from principal shareholders 194,200 74,350
----------- ----------

Net cash provided by 1,581,122 359,350
----------- ----------

INCREASE (DECREASE) IN CASH 662,483 (8,450)
Cash, beginning of period 939 9,389
----------- ----------

Cash, end of period $ 663,422 $ 939
=========== ==========

SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING
AND FINANCING ACTIVITIES
Shareholder notes payable converted to common stock $ 627,530 $ -
Non-cash expense 13,641 38,076
Shareholder note payable given for oil and gas properties
and general and administrative expenses 17,152 20,888

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

F-5

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2003
---------------------------------

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.

HISTORY - The Company completed a reverse merger with Texas Nevada Oil and Gas
-------
Co. ("TNOG") in January 2002. The Company issued 596,469 shares of common stock
to the shareholders of TNOG. As the majority surviving ownership in the merger,
the Company changed the name to Houston American Energy Corp. and treated the
transaction as an acquisition of TNOG.

COMPLETION OF THE DEVELOPMENT STAGE- Since inception, the Company has been in
--------------------------------------
the process of accumulating adequate resources to sustain its operations.
During the latter part of fiscal 2002 and early 2003, operations and funding
became sufficient to permit the Company to be reclassified and emerge from its
development stage history.

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 amortization. The sum of net capitalized costs subject to
amortization, including estimated future development and abandonment costs, are
amortized using the unit-of-production method.

F-6

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2003
---------------------------------

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

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 $1,119 and $1,603 at December 31,
2003 and 2002, respectively and accumulated reserved for depreciation was $3,227
at December 31, 2003. Depletion and amortization for oil and gas properties was
$54,831 and $22,563 at December 31, 2003 and 2002, respectively and accumulated
reserve for depletion and amortization was $798,813 at December 31, 2003.

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.

F-7

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2003
---------------------------------

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

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 88% of
reserves) and a reservoir engineer that is a shareholder, 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,
2003 include the following:

Acquisition costs $103,404
Geological, geophysical and screening costs 23,470
--------
Total $126,874
========

All but $5,617 of this cost was incurred on U. S. properties.

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.

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. The Company
paid no interest or taxes during the period of the accompanying financial
statements.

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, as retroactively adjusted by the stock split
described in the third paragraph of Note 1.

F-8

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2003
---------------------------------

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

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 two 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 project operator.

The Company currently has interests in two 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, 2003, 63% of the Company's net oil and gas property investment
and 58% of its revenue was with or derived from the company managing the
Columbian properties.

RECENT ACCOUNTING DEVELOPMENTS - The EITF is considering two issues related to
----------------------------------
the reporting of oil and gas mineral rights. Issue No. 03-O, "Whether Mineral
Rights Are Tangible or Intangible Assets," is whether or not mineral rights are
intangible assets. Issue No. 03-S, "Application of SFAS No. 142, Goodwill and
Other Intangible Assets, to Oil and Gas Companies," is, if oil and gas drilling
rights are intangible assets, whether those assets are subject to the
classification and disclosure provisions of SFAS No. 142.

If the EITF determines that oil and gas mineral rights are intangible assets and
are subject to the applicable classification and disclosure provisions of SFAS
No. 142, the Company estimates that $923,000 and $41,000 would be reclassified
from oil and gas properties to intangible assets on its balance sheet as of
December 31, 2003. These amounts represent oil and gas mineral rights acquired
after June 2001 through the end of the year. These amounts are net of
accumulated DD&A. In addition, the disclosures required by SFAS Nos. 141 and 142
would be made in the notes to the financial statements. There would be no effect
on the statements of operations or cash flows as the intangible assets related
to oil and gas mineral rights would continue to be amortized under the full cost
method of accounting.

NOTE 2. - NOTES PAYABLE

Notes payable at December 31, 2003, in the amount of $1,000,000, is owed to John
Terwilliger, Chief Executive Officer, who is also a significant shareholder.
The notes are not secured, bear interest at 7.2% and are due on January 1, 2007
with interest paid monthly, based on cash flow.

On December 9, 2003, two principal shareholders, including the Chief Executive
Officer mentioned above, exchanged notes payable and unpaid interest aggregating
$339,875 and $287,655, respectively, for 1,568,825 shares of the Company's
common stock.

F-9

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2003
---------------------------------

NOTE 4. - RELATED PARTIES

The Company's original oil and gas properties in Lavaca County Texas were
purchased from John F. Terwilliger, Chief Executive Officer, and a principal
shareholder, at their cost.

Since inception of the Company's operations, John F. Terwilliger has received no
direct or indirect compensation or other salary related benefits from the
Company.

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
2003, approximately $3,600 was paid to John Terwilliger and Orrie L. Tawes from
these royalty interests.

NOTE 5 - INCOME TAXES

The following table sets forth a reconciliation of the statutory federal income
tax for the year ended December 31, 2003 and 2002.

2003 2002
---------- ----------

Loss before income taxes $(344,330) $(394,384)
========== ==========

Income tax computed at statutory rates $(117,073) $(134,091)
Adjustment to net operating loss carryforward - 30,560
Permanent differences, nondeductible expenses (47,752) -
Increase in valuation allowance 164,825 103,531
---------- ----------

Tax provision $ - $ -
========== ==========

No federal income taxes have been paid since the inception of the Company. The
Company has a net operating loss carry forward of approximately $1,328,000 which
will expire in 2016 through 2018. 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 or 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, 2003 are set out below.

2003
----------

Deferred tax asset:
Net operating loss carry forwards $ 451,723
Valuation allowance (381,939)
Book over tax depreciation, depletion
and capitalization methods on oil
and gas properties (118,183)
Book over tax accrued interest payments 48,399
----------

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

F-10

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2003
---------------------------------

NOTE 6. - COMMITMENTS

LEASE COMMITMENT - The Company leases office facilities under an operating lease
----------------
agreement which expires November 30, 2006. The lease agreement requires
payments of $39,631 in 2004 and 2005 and $33,026 in 2006. Total rental expense
in 2003 was $41,219 and $38,000 in 2002. 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. At December 31, 2003 there are no
known assertions, claims or legal actions pending. Consequently there are no
contingency claims accrued.

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, 2004, our
acquisition and drilling budget for 2004 totaled $420,000, consisting of (1)
$28,500 for drilling of three wells in Colombia on the Cara Cara concession and
$173,350 to drill the Tambaqui #2, (2) $140,000 for South Texas leasehold
prospects that are to be purchased for resale, and (3) $60,000 to $80,000 for
the acquisition and drilling of the LaFurs well on the South Sibley Prospect in
Louisiana.

POST RETIREMENT BENEFITS - At December 31, 2003, the Company had no pension
--------------------------
plans, other postretirement benefits or employee savings plans.

SHAREHOLDER ROYALTY INTEREST - In conjunction with HUSA'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, CEO, and Orrie L. Tawes, a significant shareholder

NOTE 7. - 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 Columbia, by geographic area:

2003 2002
-------- -------

REVENUES
U.S. $ 92,080 $24,983
Columbia 128,520 -
-------- -------
$220,600 $24,983
======== =======

LEASE OPERATING EXPENSE
U.S. $ 37,566 $19,397
Columbia 146,288 -
-------- -------
$183,854 $19,397
======== =======

F-11

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2003
---------------------------------

NOTE 7. - SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND
PRODUCTION ACTIVITIES (UNAUDITED) CONTINUED . .

CAPITAL COSTS - Capitalized costs and accumulated depletion relating to the
--------------
Company's oil and gas producing activities as of December 31, 2003, all of which
are on shore properties located in the United States and Columbia, South America
are summarized below:

U.S. COLUMBIA TOTAL
----------- ---------- -----------

Unproved properties not
being amortized $ 121,257 $ 5,617 $ 126,874

Properties being amortized 1,000,070 617,511 1,617,581
Accumulated depreciation, depletion
and amortization (775,513) (23,299) (798,812)
----------- ---------- -----------

Total capitalized costs $ 345,814 $ 599,829 $ 945,643
=========== ========== ===========

ACQUISITION, EXPLORATION AND DEVELOPMENT COSTS INCURRED -Costs incurred in oil
---------------------------------------------------------
and gas property acquisition, exploration and development activities for
December 31, 2003 and 2002 is summarized below:

2003
---------------------
U. S. Columbia
---------- ---------

Property acquisition costs:
Proved ($34,433) $ 317,500
Unproved 28,149 -
Exploration costs 188,373 195,448
Development costs 29,300 46,432
---------- ---------

Total costs incurred $ 211,389 $ 559,380
========== =========

2002
-------------------
U. S. Columbia
-------- ---------

Property acquisition costs:
Proved $ 22,009 $ -
Unproved 5,008 57,747
Exploration costs 125,663 -
Development costs - -
-------- ---------

Total costs incurred $152,680 $ 57,747
======== =========

MAJOR CUSTOMERS - The majority of the production for 2003 from the Company's
----------------
mineral interests were sold to an international integrated oil company (58%) and
to a U.S. natural gas marketing company (17%). There were no other production
sales of more than 10% to a single buyer.

F-12

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2003
---------------------------------

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

The supplemental un-audited 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 88% of total estimated future net
revenues at December 31, 2003. The remaining reserves were estimated by a
petroleum engineer who is also a shareholder 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.

U.S. Columbia Total
--------------------- -------------------- ---------------------
Gas (mcf) Oil (bbls) Gas(mcf) Oil (bbls) Gas (mcf) Oil (bbls)
--------- ---------- -------- ---------- --------- ----------

Total proved reserves
Balance December 31, 2001 27,999 - - - 27,999 -
Revision of previous estimates (170) - - - (170) -
Production (8,957) - - - (8,957) -
--------- ---------- -------- ---------- --------- ----------
Balance December 31, 2002 18,872 18,872

Extensions and discoveries 181,227 4,557 - 275,587 181,227 280,144
Revisions of prior estimates (7,506) 89 - - (7,506) 89
Production (15,993) (246) - (5,880) (15,993) (6,126)
--------- ---------- ======== ---------- --------- ----------
Balance December 31, 2003 176,600 4,400 - 269,707 176,600 274,107
========= ========== ======== ========== ========= ==========

Proved developed reserves
at December 31, 2003 140,400 3,700 - 260,424 140,400 164,124
========= ========== ======== ========== ========= ==========

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

F-13

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2003
---------------------------------

NOTE 7. - SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND
PRODUCTION ACTIVITIES (UNAUDITED) CONTINUED . .

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.

Standard measure of discounted future net cash flows at December 31, 2003:

U.S. COLUMBIA TOTAL
-----------------------------------

Future net cash flows $ 938,550 $5,942,380 $6,880,930
Future production cost 175,300 1,450,645 1,625,945
Future income tax expense 141,640 833,549 975,189
----------- ---------- ----------
Future net cash flow 621,610 3,658,186 4,279,796
10% annual discount for timing of cash flows 160,807 946,350 1,107,157
----------- ---------- ----------

Standardized measure of discounted future net
cash flow relating to proved oil and gas reserves $ 460,803 $2,711,836 $3,172,639
=========== ========== ==========

Changes in standardized measure:

Change due to current year operations
Sales, net of production costs $ (36,746)
Changes due to revisions in standardized variables:
Income taxes (722,915)
Accretion of discount 4,128
Revision and others (8,708)
Discoveries 3,895,591
-----------
Net 3,131,350
Beginning of year 41,289
-----------

End of year $3,172,639
===========

F-14

HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2003
---------------------------------

NOTE 7. - SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND
PRODUCTION ACTIVITIES (UNAUDITED) CONTINUED .

Standard measure of discounted future net cash flows at December 31, 2002:

U S
---------

Standard measure of discounted future net cash flows:
Future cash inflows $ 65,760
Future production cost (19,993)
---------
Future net cash flow 45,767
10% annual discount for timing of cash flows (4,478)
---------

Standardized measure of discounted future net
cash flow relating to proved gas reserves $ 41,289
=========

Changes in standardized measure:

Changes due to current year operations
Sales, net of production costs $ (4,843)
Changes due to revisions in standardized variables
Prices and production cost 23,940
Revision of previous quantity estimates (280)
Accretioned discount 2,367
Production rates (timing) and other (3,562)
---------
Net 17,622
Beginning of year 23,677
---------

End of year $ 41,289
=========

F-15