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, 2004
[ ] 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.
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(Name of Small Business Issuer in its charter)
Delaware 76-0675953
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(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
801 Travis Street, Suite 2020
Houston, Texas 77002
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(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
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None None
Securities to be registered pursuant to Section 12(g) of the Act:
Common Stock, $0.001 par value
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(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, 2004 were
$1,182,063.
The number of shares of the registrant's common stock, $.001 par value per
share, outstanding as of March 9, 2005 was 19,970,589. The aggregate market
value of the voting and non-voting common equity held by non-affiliates of the
registrant on March 9, 2005, based on the last sales price on the OTC Bulletin
Board as of such date, was approximately $6,854,450.
DOCUMENTS INCORPORATED BY REFERENCE
None
Transition Small Business Disclosure Format: Yes [ ] No [X]
TABLE OF CONTENTS
Page
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PART I
ITEM 1. DESCRIPTION OF BUSINESS............................ 3
ITEM 2. DESCRIPTION OF PROPERTY............................ 13
ITEM 3. LEGAL PROCEEDINGS.................................. 13
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF
SECURITY HOLDERS................................... 13
PART II
ITEM 5. MARKET FOR COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS........................ 14
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS............... 15
ITEM 7. FINANCIAL STATEMENTS............................... 20
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE............. 20
ITEM 8A. CONTROLS AND PROCEDURES............................ 20
ITEM 8B. OTHER INFORMATION.................................. 20
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND
CONTROL PERSONS; COMPLIANCE WITH
SECTION 16(a) OF THE EXCHANGE ACT.................. 21
ITEM 10. EXECUTIVE COMPENSATION............................. 22
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT.............................. 23
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS..... 23
ITEM 13. EXHIBITS AND REPORTS OF FORM 8-K................... 24
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES............. 27
SIGNATURES
2
FORWARD-LOOKING STATEMENTS
This annual report on Form 10-KSB contains forward-looking statements within the
meaning of the federal securities laws. These forwarding-looking statements
include without limitation statements regarding our expectations and beliefs
about the market and industry, our goals, plans, and expectations regarding our
properties and drilling activities and results, our intentions and strategies
regarding future acquisitions and sales of properties, our intentions and
strategies regarding the formation of strategic relationships, our beliefs
regarding the future success of our properties, our expectations and beliefs
regarding competition, competitors, the basis of competition and our ability to
compete, our beliefs and expectations regarding our ability to hire and retain
personnel, our beliefs regarding period to period results of operations, our
expectations regarding revenues, our expectations regarding future growth and
financial performance, our beliefs and expectations regarding the adequacy of
our facilities, and our beliefs and expectations regarding our financial
position, ability to finance operations and growth and the amount of financing
necessary to support operations. These statements are subject to risks and
uncertainties that could cause actual results and events to differ materially.
We undertake no obligation to update forward-looking statements to reflect
events or circumstances occurring after the date of this annual report on Form
10-KSB.
As used in this annual report on Form 10-KSB, unless the context otherwise
requires, the terms "we," "us," "the Company," and "Houston American" refer to
Houston American Energy Corp., a Delaware corporation.
PART I
ITEM 1. DESCRIPTION OF BUSINESS
General
Houston American Energy Corp. is an oil and gas exploration and production
company. Our oil and gas exploration and production activities are focused on
properties in the U.S. onshore Gulf Coast Region, principally Texas, and
development of two concessions in the South American country of Colombia. We
seek to utilize the contacts and experience of our sole executive officer, John
F. Terwilliger, to identify favorable drilling opportunities, to use advanced
seismic techniques to define prospects and to form partnerships and joint
ventures to spread the cost and risks to us of drilling.
Exploration Projects
Our exploration projects are focused on existing property interests, and future
acquisition of additional property interests, in the onshore Texas Gulf Coast
region, Colombia and Louisiana.
Each of our exploration projects differs in scope and character and consists of
one or more types of assets, such as 3-D seismic data, leasehold positions,
lease options, working interests in leases, partnership or limited liability
company interests or other mineral rights. Our percentage interest in each
exploration project ("Project Interest") represents the portion of the interest
in the exploration project we share with other project partners. Because each
exploration project consists of a bundle of assets that may or may not include a
working interest in the project, our Project Interest simply represents our
proportional ownership in the bundle of assets that constitute the exploration
project. Therefore, our Project Interest in an exploration project should not be
confused with the working interest that we will own when a given well is
drilled. Each exploration project represents a negotiated transaction between
the project partners. Our working interest may be higher or lower than our
Project Interest.
Our principal exploration projects as of December 31, 2004 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. Our royalty interest in the Mavis
Wharton Lease does not bear any costs of well operations.
3
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. We presently have no plans with respect to drilling additional
wells in Matagorda County.
San Patricio County, Texas. In San Patricio County, Texas, we hold a 5% working
interest in a 380 acre leasehold known as the St. Paul Prospect. The Garza #1
well was drilled in the first quarter of 2004 and successfully completed as a
gas well. We presently have no plans with respect to drilling additional wells
on the St. Paul Prospect.
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.
Vermillion Parish, Louisiana. In Vermillion Parish, Louisiana, we hold a 3%
working interest in the LaFurs F-16 well. The LaFurs F-16 well was drilled in
the second quarter of 2004 and was completed as a gas well with commercial sales
of gas beginning in the third quarter of 2004. We have no additional drilling
rights or plans with respect to the Vermillion Parish prospect.
Acadia Parish, Louisiana. In Acadia Parish, Louisiana, we hold a 3% working
interest and a 2.25% net revenue interest until payout in a 620 acre leasehold
known as the Crowley Prospect. The Hoffpauer #1 (formerly the Baronet #1) was
drilled in the third quarter of 2004. Commercial production of the well
commenced in December 2004 with initial production rates of 1,525 MCF of gas and
15.5 barrels of condensate per day. We presently plan to drill the Baronet #2
well in the first quarter of 2005 to test the deeper Hayes formation of the
prospect.
Terrebonne Parish, Louisiana. In Terrebonne Parish, Louisiana, we hold a 1.25%
carried working interest to the casing point in a 194 acre leasehold known as
the Donner Field. We plan to drill the Donner Field well in early 2005.
Plaquemines Parish, Louisiana. In Plaquemines Parish, Louisiana, we hold a 1.8%
working interest after casing point, and a 1.35% net revenue interest in a 300
acre leasehold known as the Bakers Bay Prospect. The SL18077 #1 well was drilled
in the fourth quarter of 2004. The well was completed as a gas and oil well in
December 2005 and was awaiting a pipeline hookup at December 31, 2004 with sales
expected to commence by April 2005. We presently have no plans with respect to
drilling additional wells on the Bakers Bay Prospect.
North Louisiana. In December 2004, we sold our interest in a 1,428 acre
leasehold in Northern Louisiana and joined the purchaser of that interest in
forming a 7,680 acre area of mutual interest. Pursuant to that agreement, we
received a 7.5% working interest in the first well drilled on the acreage, a
7.5% working interest back in after payout in the second and third wells and
will have an option to participate for its 7.5% working interest in all
subsequent wells. We also retained overriding royalty interests ranging from
1.35% to 2.5% on leases covering 3,200 acres. Drilling of the Northern Louisiana
prospects is expected to begin during the first half of 2005.
4
Llanos Basin, Colombia. In the Llanos Basin, Colombia, we hold interests in (1)
a 232,050 acre tract known as the Cara Cara concession, (2) the Tambaqui
Association Contract covering 88,000 acres in the State of Casanare, Colombia,
and (3) two concessions, the Dorotea Contract and the Cabiona Contract, totaling
over 185,000 acres.
Our interest in the Cara Cara concession and the two additional concessions is
held through an interest in Hupecol, LLC. The additional concessions were
acquired by Hupecol in the fourth quarter of 2004. We hold a 12.5% working
interest in each of the prospects of Hupecol. In conjunction with our interest
in Hupecol, we also acquired, and hold, a 12.6% working interest, with an 11.31%
net revenue interest, in the Tambaqui Association Contract.
The first well drilled in the Cara Cara concession, the Jaguar #1 well, was
completed in April 2003 with initial production of 892 barrels of oil per day.
In conjunction with the efforts to develop the Cara Cara concession, Hupecol
acquired 50 square miles of 3D seismic grid surrounding the Jaguar #1 well and
two other prospect areas. That data is being utilized to identify additional
drill site opportunities to develop a field around the Jaguar #1 well and in
other prospect areas within the grid.
Our working interest in the Cara Cara concession and the Tambaqui Association
Contract are subject to an escalating royalty of 8% on the first 5,000 barrels
of oil per day to 20% at 125,000 barrels of oil per day. Our interest in the
Tambaqui Association Contract is subject to reversionary interests of Ecopetrol,
the state owned Colombian oil company, that could cause 50% of the working
interest to revert to Ecopetrol after we have recouped four times our initial
investment. Our working interest in the additional concessions is subject to an
escalating royalty ranging from 5% to 20% depending upon production volumes and
pricing and an additional 6% to 10% per concession when 5,000,000 barrels of oil
have been produced on that concession.
In December 2003, we exercised our right to participate in the acquisition,
through Hupecol, of over 3,000 kilometers of seismic data in Colombia covering
in excess of 20 million acres. The seismic data is being utilized to map
prospects in key areas with a view to delineating multiple drilling
opportunities. We will hold a 12.5% interest in all prospects developed by
Hupecol arising from the acquired seismic data, including the two concessions
acquired in the fourth quarter of 2004. Hupecol plans, during the first half of
2005, to acquire approximately 75 square miles of 3D seismic data covering the
two additional concessions and 46 square miles of new 3D seismic on the Cara
Cara concession.
During 2004, Hupecol drilled nine wells on the Cara Cara concession in Colombia
to offset, and delineate, the Jaguar #1 well, with production commencing on the
Jaguar #2 in March 2004, the Bengala #2 in April 2004, the Jaguar #6 in July
2004, the Jaguar #12 in September 2004, the Jaguar #3A in October 2004, and the
Jaguar #15 in December 2004. The Cara Cara #1, the Cara Cara #7 and the Cara
Cara #7 Side Track were dry holes. We hold a 1.59% working interest in each of
the wells. Through Hupecol, we presently plan to drill an additional nine wells
on the Cara Cara concession during 2005.
Included in our interest in the Tambaqui Association Contract was an interest in
a producing well, the Tambaqui #1, and in two exploration wells. The Tambaqui #1
is no longer producing due to uneconomic production rates. The first exploration
well drilled as an offset to the Tambaqui #1, the Tambaqui #1Am, was dry. The
Tambaqui #2 well was successfully drilled and began production in June 2004. We
presently plan to drill an additional one well under the Tambaqui Association
Contract during 2005.
Through Hupecol, we presently plan to commence drilling on the Dorotea Contract
and the Cabiona Contract during 2005.
5
The following table sets forth certain information about each of our exploration
projects:
Acres Leased or Under Option at
December 31, 2004 (1)
------------------------------------------
Project Project Company Project
Project Area Gross Net 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%
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 ............... 2,196.65 2,046.65 102.24
LOUISIANA:
Vermillion Parish, Louisiana .. 830.00 830.00 24.90 3.00%
Acadia Parish, Louisiana ...... 620.00 620.00 18.60 3.00%
Terrebonne Parish, Louisiana .. 194.00 194.00 2.42 1.25%
Plaquemines Parish, Louisiana . 300.00 300.00 5.40 1.80%
Northern Louisiana ............ 1,668.71 1,668.71 125.15 7.50%
St. John the Baptist Parish,
Louisiana ................... 726.00 726.00 14.52 2.00%
------------ ------------ -----------
Louisiana Sub-Total ........... 4,338.71 4,338.71 190.99
OKLAHOMA
Jenny #1-14 ................... 160.00 160.00 3.78 2.36%
------------ ------------ -----------
Oklahoma Sub-Total ............ 160.00 160.00 3.78
COLOMBIA
Cara Cara Concession ....... 232,050.00 232,500.00 3,689.00 1.59%
Tambaqui Assoc. Contract (2) 88,000.00 88,000.00 11,088.00 12.6%
Dorotea Contract ........... 82,065.00 82,065.00 10,258.00 12.5%
Cabiona Contract ........... 103,740.00 103,740.00 12,967.00 12.5%
------------ ------------ -----------
Colombia Sub-Total ............ 505,855.00 505,855.00 38,002.00
------------ ------------ -----------
Total ......................... 512,550.36 512,400.36 38,299.01
============ ============ ===========
6
(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, 2004, we drilled
18 exploratory and 7 developmental wells, of which 18 were completed and 7 were
dry holes. In 2003, 3 exploratory and 1 developmental wells were drilled of
which 3 were completed and 1 was a dry hole. In 2004, 9 exploratory and 7
developmental wells were drilled of which 11 were completed and 5 were dry
holes.
The following table sets forth certain information regarding the actual drilling
results for each of the years 2003 and 2004 as to wells drilled in each such
individual year:
Exploratory Wells (1) Developmental Wells (1)
----------------------- ------------------------
Gross Net Gross Net
--------- --------- --------- ---------
2003
Productive ............. 3 0.435 0 0
Dry .................... 0 0.000 1 0.125
2004
Productive ............. 4 0.128 7 0.220
Dry .................... 5 0.238 0 0
(1) Gross wells represent the total number of wells in which we owned an
interest; net wells represent the total of our net working interests owned
in the wells.
One well was in progress at December 31, 2004, on the Cara Cara prospect.
Productive Well Summary
The following table sets forth certain information regarding our ownership as of
December 31, 2004 of productive gas and oil wells in the areas indicated:
Gas Oil
--------------------------- --------------------------
Gross Net Gross Net
------------ ------------ ------------ ------------
Texas .................. 3 0.465 0 0
Louisiana .............. 4 0.078 0 0
Oklahoma ............... 1 0.024 0 0
Colombia ............... 0 0 8 0.236
------------ ------------ ------------ ------------
Total ............. 8 0.567 8 0.236
============ ============ ============ ============
7
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,
---------------------------
2003 2004
------------ ------------
Net Production:
Gas (Mcf):
North America .................................. 15,993 61,519
South America .................................. 0 0
Oil (Bbls):
North America .................................. 246 886
South America .................................. 5,880 24,040
Average sales price:
Gas ($ per Mcf) ..................................... 5.11 5.43
Oil (Bbls) .......................................... 30.17 33.85
Average production expense and taxes ($ per Bble):
North America .................................... 2.35 5.32
South America .................................... 24.88 14.74
Natural Gas and Oil Reserves
The following table summarizes the estimates of our historical net proved
reserves as of December 31, 2003 and 2004, 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,
---------------------------
2003 2004
------------ ------------
Net proved reserves (1):
Natural gas (Mcf) ................................... 176,600 202,420
Oil (Bbls) .......................................... 274,107 307,290
Standardized measure of discounted future net
cash flows (2) ........................................... $ 3,172,639 $ 4,005,624
(1) At December 31, 2004, net proved reserves, by region, consisted of 295,700
barrels of oil in South America and 11,590 barrels of oil in North
America; all natural gas reserves were in North America.
(2) The standardized measure of discounted future net cash flows represents
the present value of future net revenues after income tax discounted at
10% per annum and has been calculated in accordance with SFAS No. 69,
"Disclosures About Oil and Gas Producing Activities" (see Note 7 -
Supplemental Information on Oil and Gas Exploration, Development and
Production Activities (Unaudited)) and, in accordance with current SEC
guidelines, and does not include estimated future cash inflows from
hedging. The standardized measure of discounted future net cash flows
attributable to our reserves was prepared using prices in effect at the
end of the respective periods presented, discounted at 10% per annum on a
pre-tax basis.
8
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, 2004, the gross and net acres
of proved developed and proved undeveloped and unproven gas and oil leases which
we hold or have the right to acquire:
Proved Developed Proved Undeveloped Unproven
----------------------- ----------------------- -----------------------
Gross Net Gross Net Gross Net
---------- ---------- ---------- ---------- ---------- ----------
Texas ............ 1,524.65 78.72 0 0 672.00 23.52
Louisiana ........ 2,244.00 57.32 0 0 2,094.71 133.67
Oklahoma ......... 160.00 3.78 0 0 0 0
Colombia ......... 2,560.00 75.61 6,720.00 141.76 496,575.00 37,784.63
---------- ---------- ---------- ---------- ---------- ----------
Total ....... 6,488.65 215.43 6,720.00 141.76 499,341.71 37,941.82
========== ========== ========== ========== ========== ==========
During 2004, (1) we released 35% of the acreage in the Cara Cara concession, (2)
our Jackson County, Texas lease of the W. Harmon Prospect expired, and (3) we
leased 290 acres in Wharton County, Texas and subsequently sold our 50% interest
in the lease retaining a 9.5% carried interest in two wells that were drilled as
dry holes.
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 9, 2005, 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:
9
- 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 South America
As described above, we currently have interests in four 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.
10
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.
11
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.
12
Employees
As of March 9, 2005, 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 by the end of 2005.
ITEM 2. DESCRIPTION OF PROPERTY
We currently lease approximately 2,000 square feet of office space in Houston,
Texas as our executive offices. Management anticipates that our space will be
sufficient for the foreseeable future. The monthly rental under the lease, which
expires on November 30, 2006, is $3,302.59.
A description of our interests in oil and gas properties is included in "Item 1.
Description of Business."
ITEM 3. LEGAL PROCEEDINGS
During the quarter ended March 31, 2004, we were named as defendant in a suit
styled Alan Gerger, Trustee for the Substantially Consolidated Bankruptcy Estate
of Moose Oil and Gas Company and Moose Operating Company v. John Terwilliger,
Marlin Data Research, Inc. and Houston American Energy Corp., filed in the
United States Bankruptcy Court for the Southern District of Texas. The plaintiff
alleges that expenses relating to the formation and operation of Houston
American were paid by Moose Oil and Gas or Moose Operating Company, that
interests in certain oil and gas properties were transferred to Houston American
from Moose Oil and Gas or Moose Operating Company and that the alleged payments
and transfers constituted fraudulent transfers and voidable preferences. The
plaintiff seeks to recover all properties alleged to have been wrongfully
transferred as well as costs of suit and other relief. We believe that the
action is without merit and intend to vigorously contest the same.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
13
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 2004
Fourth Quarter.............................. $1.05 $0.83
Third Quarter............................... 1.10 0.83
Second Quarter.............................. 1.35 0.60
First Quarter............................... 1.00 0.65
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
The quotations reflect inter-dealer prices without retail mark-up, mark-down or
commission and may not represent actual transactions.
At March 9, 2005, the closing bid price of the Common Stock was $0.84.
As of March 9, 2005, there were approximately 992 record holders of our Common
Stock.
In December 2004, the Company issued an aggregate of 305,000 shares of common
stock for a purchase price of $259,250 to one accredited investor.
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.
14
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 Developments During 2004
Drilling Activities
During 2004, we drilled four successful on-shore domestic wells as follows:
o A test well in San Patricio County, Texas, the Saint Paul Prospect Garza
#1, was drilled in January 2004 and completed as a natural gas well.
Natural gas sales from the well began March 1, 2004. We hold a 5% working
interest in the well.
o A test well in Vermillion Parish, Louisiana, the LaFurs #F-16, was drilled
in May 2004 and completed as a natural gas well. Natural gas sales from
the well began in September 2004. We hold a 3% working interest in the
well.
o A test well in Acadia Parish, Louisiana, the Hoffpauer #1 (formerly, the
Baronet #1), on the 620-acre Crowley Prospect, was drilled in September
2004. After reaching a depth of 12,042 feet, the well encountered a stuck
drill pipe. The well was plugged back and a side track attempt was made.
After encountering a second stuck drill pipe and following negotiations
with the operator, the well was taken off of turnkey, intermediate casing
was set and a completion rig is being contracted with the objective of
completing a well in the Camerina sands that produced gas shows. The well
was completed and production began in December 2004. We hold a 3% working
interest in the well. A second rig has been contracted to drill a new well
to test the Hayes sands on the prospect. Drilling is expected to begin in
the first quarter of 2005.
15
o A test well in Plaquemines Parish, Louisiana, the SL18077 #1, was drilled
in December 2004. The well was completed in January 2005. We hold a 1.8%
working interest in the well.
We also participated in two dry holes drilled during 2004, the Hutchins Peareson
#1 and the Hutchins Peareson #2 drilled in Wharton County, Texas.
At December 31, 2004, we had no domestic wells being drilled but plan drilling
operations during 2005 on three prospects in Louisiana.
During 2004, we drilled seven international wells in South America as follows:
o Drilling of six offset wells on the Cara Cara concession in Colombia was
completed with production commencing on the Jaguar #2 in March 2004, the
Bengala #2 in April 2004, the Jaguar #6 in July 2004, the Jaguar #12 in
September 2004 and the Jaguar #3A in October 2004. The sixth well, the
Cara Cara #1 is shut in pending evaluation. We hold a 1.59% working
interest in each of the wells.
o An oil well, the Tambaqui #2, was drilled and successfully completed under
the Company's Tambaqui Association Contract in Columbia and began
production in June 2004. The Company holds a 12.6% working interest and an
11.59% net revenue interest in the well.
At December 31, 2004, we had no wells being drilled in South America but we
presently plan to drill during 2005, with our partners, up to 9 additional wells
on the Cara Cara concession and 1 well under the Tambaqui Association Contract.
We also plan to commence, during 2005, a drilling program on the two additional
concessions secured in Colombia during 2004.
Leasehold Activities
During 2004, we invested approximately $612,000 for the acquisition of oil and
gas properties, consisting of (1) acquisition of a 3% interest in the North
Freshwater Bayou Field in Louisiana, (2) acquisition of a 100% interest in the
South Sibley Prospect, (3) acquisition of a 50% interest in the Southern Star
Wharton Prospect, and (4) acquisition, by Hupecol, of two additional concessions
in Colombia covering approximately 180,000 acres.
In September 2004, we sold our 50% interest in a 280 acre leasehold in Wharton
County, Texas to an independent exploration and production company. We received
funds in excess of our acquisition cost on the Wharton County lease. The excess
proceeds from the sale, totaling approximately $21,650, were applied to reduce
the cost of oil and gas properties. Pursuant to the terms of the sale, the buyer
agreed to drill two wells on the prospect with the Company retaining a carried
working interest of 9.5% to the casing point and a net revenue interest of
7.125%. The two wells, the Hutchins Peareson #1 and the Hutchins Peareson #2
were drilled as dry holes.
In December 2004, we sold our interest in a 1,428 acre leasehold in Northern
Louisiana and joined the purchaser of that interest in forming a 7,680 acre area
of mutual interest. Pursuant to that agreement, we received a 7.5% working
interest in the first well drilled on the acreage, a 7.5% working interest back
in after payout in the second and third wells and will have an option to
participate for its 7.5% working interest in all subsequent wells. We also
retained overriding royalty interests ranging from 1.35% to 2.5% on leases
covering 3,200 acres. Drilling of the Northern Louisiana prospects is expected
to begin during the first half of 2005.
Other Developments
In August 2004, we joined a Libya Study Group consisting of twelve oil companies
for the purpose of developing drilling prospects and applying for concessions to
exploit drilling opportunities in Libya. The study group plans to have completed
the process of defining prospects followed by a formal request for drilling
concessions in early 2005.
In September 2004, we approved the payment of a salary of $15,000 per month,
commencing in October 2004, to John Terwilliger, our President and Chief
Executive Officer. Mr. Terwilliger had previously served without compensation.
16
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,
2004. The capitalized costs of oil and gas properties, plus estimated future
development costs relating to proved reserves are amortized on a
units-of-production method over the estimated productive life of the reserves.
Unevaluated oil and gas properties are excluded from this calculation. The
capitalized oil and gas property costs, less accumulated amortization, are
limited to an amount (the ceiling limitation) equal to the sum of: (a) the
present value of estimated future net revenues from the projected production of
proved oil and gas reserves, calculated at prices in effect as of the balance
sheet date (with consideration of price changes only to the extent provided by
contractual arrangements) and a discount factor of 10%; (b) the cost of unproved
and unevaluated properties excluded from the costs being amortized; (c) the
lower of cost or estimated fair value of unproved properties included in the
costs being amortized; and (d) related income tax effects. Excess costs are
charged to proved properties impairment expense.
Unevaluated Oil and Gas Properties. Unevaluated oil and gas properties consist
principally of our cost of acquiring and evaluating undeveloped leases, net of
an allowance for impairment and transfers to depletable oil and gas properties.
When leases are developed, expire or are abandoned, the related costs are
transferred from unevaluated oil and gas properties to depletable oil and gas
properties. Additionally, we review the carrying costs of unevaluated oil and
gas properties for the purpose of determining probable future lease expirations
and abandonments, and prospective discounted future economic benefit
attributable to the leases. We record an allowance for impairment based on a
review of present value of future cash flows. Any resulting charge is made to
operations and reflected as a reduction of the carrying value of the recorded
asset. Unevaluated oil and gas properties not subject to amortization include
the following at December 31, 2004 and 2003:
At December 31, 2004 At December 31, 2003
----------------------- -----------------------
Acquisition costs $ 48,636 $ 103,404
Evaluation costs 12,159 23,470
----------------------- -----------------------
Total $ 60,795 $ 126,874
======================= =======================
The carrying value of unevaluated oil and gas prospects include $12,519 and
$5,617 expended for properties in South America at December 31, 2004 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.
17
Results of Operations
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Oil and Gas Revenues. Total oil and gas revenues increased $961,463, or 435%, to
$1,182,063 in fiscal 2004 when compared to fiscal 2003. The increase in revenue
is due to (1) increased production resulting from the development of the South
American fields and the new domestic wells that have come on line during 2003
and 2004 and (2) increases in oil prices. We had interests in 8 producing wells
in South America and 8 producing wells in North America during 2004 as compared
to 2 producing wells in South America and 3 producing wells in North America
during 2003. Average prices from sales were $33.85 per barrel of oil and $5.43
per mcf of gas during 2004 as compared to $30.17 per barrel of oil and $5.11 per
mcf of gas during 2003. Following is a summary comparison, by region, of oil and
gas sales for the periods.
South America North America Total
-------------- -------------- --------------
Year ended 2004
Oil sales $ 808,472 $ 39,376 $ 847,848
Gas sales 0 334,215 334,215
Year ended 2003
Oil sales $ 128,520 $ 11,957 $ 140,477
Gas sales 0 80,123 80,123
Lease Operating Expenses. Lease operating expenses, excluding joint venture
expenses relating to our South American operations discussed below, increased
182% to $413,723 in 2004 from $146,914 in 2003. The increase in lease operating
expenses was attributable to the increase in the number of wells operated during
2004. Following is a summary comparison of lease operating expenses for the
years ended December 31, 2004 and 2003.
South America North America Total
-------------- -------------- --------------
Year ended 2004 $ 354,448 59,275 413,723
Year ended 2003 109,348 37,566 146,914
Joint Venture Expenses. Joint venture expenses totaled $41,944 in 2004 compared
to $36,940 in 2003. The joint venture expenses represent our allocable share of
the indirect field operating and region administrative expenses billed by the
operator of the South American CaraCara and Tambaqui concessions. The increase
in joint venture expenses was attributable to increased exploration and
production in South America.
Depreciation and Depletion Expense. Depreciation and depletion expense increased
by 275% to $211,759 in fiscal 2004 when compared to $56,434 in 2003. The
increase in depreciation and depletion expense was primarily attributable to the
increased production from new wells coming on line during 2004.
Interest Expense. Interest expense decreased 49% to $72,000 in 2004 compared to
$142,349 in 2003. The interest expense decrease was attributable to reduced debt
relating to the conversion of certain debt to equity in 2003 and a reduction in
the interest rate.
General and Administrative Expenses. General and administrative expense
increased by 79% to $327,354 in 2004 from the $182,293 in 2003. The increase in
G&A expense was principally attributable to (1) a 137% increase in professional
fees arising in connection with the Moose Oil litigation commenced during 2004
and (2) the commencement of salary to our President and CEO during the fourth
quarter of 2004, totaling $15,000 per month for three months.
Financial Condition
Liquidity and Capital Resources. At December 31, 2004, we had a cash balance of
$721,613 and working capital of $771,392 compared to a cash balance of $663,422
and working capital of $654,451 at December 31, 2003. The 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.
18
As discussed in our prior financial statements, our revenue was previously
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, previously provided us the funds needed
to continue our development and operations. During 2004, we, for the first time,
operated profitably and with positive cash flow. At current production levels
and prices, our operations are self-supporting from a cash flow standpoint.
Management anticipates raising any necessary funds for major capital
expenditures from outside investors or commercial bank or mezzanine lenders.
During 2004, we (1) issued 532,991 shares of common stock for cash consideration
of $350,443, (2) in conjunction with an agreement with an individual to assist
us in locating viable oil and gas prospects, issued 50,000 shares of common
stock, valued at $47,500, and granted an interest equal to 10% of our interest
in any prospects generated by the individual's contacts, and (3) issued 100,000
shares of common stock, valued at $103,000, for financial public relations
services over a six month period. We terminated the financial public relations
service contract and the 100,000 shares previously issued in connection with the
contract were returned and are reflected as treasury stock.
Loans from shareholders totaled $1,000,000 at December 31, 2004.
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 funded our capital and exploration
expenditures from funds borrowed from John F. Terwilliger, our principal
shareholder and officer, and from sales of common stock. 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 2004, we invested approximately $559,380 for the acquisition and
development of oil and gas properties, consisting of (1) acquisition of a 3%
interest in the North Freshwater Bayou Field in Louisiana, (2) acquisition of a
100% interest in the South Sibley Prospect, (3) acquisition of a 50% interest in
the Southern Star Wharton Prospect, (4) consulting fee in forming the joint
venture with a private company and (5) drilling and/or completing expenses for
the Jaguar #2, Bengala #1, Cara Cara #1, Tambaqui #2, Jaguar #6, Jaguar #12 and
Jaguar #3A wells in South America and the Garza #1, LaFurs #F-16, Hoffpauer #1
and SL 18077 #1 in the U.S.
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 2005 2006 - 2007 2008 - 2009 Thereafter
------------ ------------ ------------ ------------ ------------
Long-term debt $ 1,000,000 $ 0 $ 1,000,000 $ 0 $ 0
Operating lease
commitments 72,657 39,631 33,026 0
------------ ------------ ------------ ------------ ------------
Total $ 1,072,657 $ 39,631 $ 1,033,026 $ 0 $ 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, 2004, we had granted ORRIs to affiliates,
including our President, ranging from 1.0% to 4.02166% of our interest in
selected properties.
At December 31, 2004, we had 8 revenue producing wells in South America, 3
revenue producing wells in south Texas, 4 revenue producing well in south
Louisiana and 1 producing well in Oklahoma.
19
At January 1, 2005, our acquisition and drilling budget for 2005 totaled
$886,000, consisting of (1) $216,000 for drilling of 9 wells in South America on
the Cara Cara concession and $170,000 to drill one additional concession
acquired in South America in 2004, and (2) $500,000 for seismic surveying in
Colombia. Our acquisition and drilling budget has historically been subject to
substantial fluctuation over the course of a year based upon successes and
failures in drilling and completion of prospects and the identification of
additional prospects during the course of a year.
Management anticipates that our current 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, 2004.
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 28 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.
During the quarter ended December 31, 2004, there were no significant changes in
our internal controls over financial reporting that materially affected, or are
reasonably likely to materially affect, internal controls over financial
reporting.
In connection with the audit of our financial statements for the fiscal year
ended December 31, 2004, our independent registered public accounting firm
informed us that we have significant deficiencies constituting material
weaknesses as defined by the standards of the Public Company Accounting
Oversight Board. The material weaknesses were in our internal controls over
accounting for non-routine transactions as well as is in overall financial
reporting functions. The accounting firm noted that adequate segregation of
duties do not exist in our financial reporting process, as our President and CEO
also functions as our CFO. The President is performing these duties with
assistance from a part time consultant. Accordingly, the preparation of
financial statements and the related monitoring controls surrounding this
process have not been segregated.
The nature and size of our business have prevented us from being able to employ
sufficient resources to enable us to have an adequate segregation of duties
within our internal control system. We will continue to monitor and assess the
costs and benefits of additional staffing in the accounting and financial
reporting area.
ITEM 8B. OTHER INFORMATION
NA
20
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE
WITH SECTION 16(a) OF THE EXCHANGE ACT
Directors and Executive Officers
The following table sets forth the names, ages and offices of the present
executive officers and directors of the Company. The periods during which such
persons have served in such capacities are indicated in the description of
business experience of such persons below.
Name Age Position
---- --- --------
John Terwilliger 57 President, Treasurer and Director
The following is a biographical summary of the business experience of the
present directors and executive officers of the Company:
John F. Terwilliger has served as our president, secretary and treasurer since
our inception in April 2001. From 1988 to April 2002, Mr. Terwilliger served as
the chairman of the board and president of Moose Oil & Gas Company, and its
wholly-owned subsidiary, Moose Operating Co., Inc., both Houston, Texas based
companies. Prior to 1988, Mr. Terwilliger was the chairman of the board and
president of Cambridge Oil Company, a Houston, Texas based oil exploration and
production company. Mr. Terwilliger served in the United States Army, receiving
his honorable discharge in 1969. On April 9, 2002, Moose Oil & Gas Company and
its wholly-owned subsidiary, Moose Operating Co., Inc., filed a bankruptcy
petition under Chapter 7 of the United States Bankruptcy Code in Cause No.
02-33891-H507: 02-22892, in the United States District Court for the Southern
District of Texas, Houston Division. At the time of the filing of the bankruptcy
petition, Mr. Terwilliger was the chairman of the board and president of both
Moose Oil & Gas Company and Moose Operating Co., Inc. Mr. Terwilliger resigned
those positions on April 9, 2002.
Although we currently have only one director, our board of directors is divided
into three classes, each elected for staggered three-year terms. Mr.
Terwilliger, our only director, is a Class C director. His term is scheduled to
expire at the third annual meeting following the end of our 2001 fiscal year.
Our executive officers are elected by our board of directors and serve terms of
one year or until their death, resignation or removal by the board of directors.
Committees of the Board
We do not presently maintain an audit committee, a compensation committee, a
nomination committee or any other committees of our board of directors.
Similarly, we do not have an "audit committee financial expert".
At such time as our Board determines that the size and scope of our operations
and our available financial resources warrant such, we expect to seek to add
independent directors and to form committees to perform the functions of an
audit committee, compensation committee and nominating committee.
Codes of Ethics
The Board of Directors has adopted a Code of Business Ethics covering all of our
officers, directors and employees. We require all employees to adhere to the
Code of Business Ethics in addressing legal and ethical issues encountered in
conducting their work. The Code of Business Ethics requires that our employees
avoid conflicts of interest, comply with all laws and other legal requirements,
conduct business in an honest and ethical manner and otherwise act with
integrity and in the company's best interest.
The Board of Directors has also adopted a separate Code of Business Ethics for
the CEO and Senior Financial Officers. This Code of Ethics supplements our
general Code of Business Ethics and is intended to promote honest and ethical
conduct, full and accurate reporting, and compliance with laws as well as other
matters.
The Code of Business Ethics for the CEO and Senior Financial Officers is filed
as an exhibit to this Annual Report on Form 10-KSB for the year ended December
31, 2004 and is available for review at the SEC's web site at www.sec.gov.
21
Compliance With Section 16(a) of Exchange Act
Under the securities laws of the United States, our directors, executive
officers, and any person holding more than ten percent of our Common Stock are
required to report their initial ownership of our Common Stock and any
subsequent changes in that ownership to the Securities and Exchange Commission.
Specific due dates for these reports have been established and we are required
to disclose any failure to file by these dates during fiscal year 2004. To our
knowledge, all of the filing requirements were satisfied on a timely basis in
fiscal year 2004. In making these disclosures, we have relied solely on written
statements of our directors, executive officers and shareholders and copies of
the reports that they filed with the Commission.
ITEM 10. EXECUTIVE COMPENSATION
Executive Compensation
The following table sets forth information concerning cash and non-cash
compensation paid or accrued for services in all capacities to the Company
during the year ended December 31, 2004 of each person who served as the
Company's Chief Executive Officer during fiscal 2004 and the next four most
highly paid executive officers (the "Named Officers").
Annual Compensation
Name and -------------------
Principal Position Year Salary($) Bonus($) Other ($)
------------------ ---- --------- -------- ---------
John Terwilliger 2004 45,000 -0- -0- (1)(2)
President and 2003 -0- -0- -0- (1)(2)
Chief Executive Officer 2002 -0- -0- -0- (1)(2)
----------------
(1) Mr. Terwilliger receives receives no other compensation or benefits other
than vacation benefits, expense reimbursements and participation in medical,
retirement and other benefit plans which are generally available to the
Company's executives.
(2) Mr. Terwilliger received overriding royalty interests in three properties
identified by Mr. Terwilliger. No value was assigned to those overriding royalty
interests for purposes of this table. Payments received by Mr. Terwilliger
pursuant to those overriding royalty interests totaled $21,170, $3,600 and $0 in
2004, 2003 and 2002, respectively.
We have no employment agreements with any of our officers or employees.
Director Compensation
We do not compensate our directors for serving in such capacity.
22
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The following table sets forth information as of March 9, 2005, based on
information obtained from the persons named below, with respect to the
beneficial ownership of shares of our Common Stock held by (i) each person known
by us to be the owner of more than 5% of the outstanding shares of our Common
Stock, (ii) each director, (iii) each named executive officer, and (iv) all
executive officers and directors as a group:
Name and Address Number of Shares Percentage
of Beneficial Owner (1) Beneficially Owned (2) of Class
----------------------- ---------------------- --------
John F. Terwilliger 8,574,486 42.9%
801 Travis, Suite 2020
Houston, Texas 77002
Orrie Lee Tawes (3) 3,236,044 16.2%
c/o O. Lee Tawes
C.E. Unterberg Towbin
350 Madison Avenue, 8th Floor
New York, New York 10017
All directors and officers
as a group (one person) 8,574,486 42.9%
---------------------
(1) Unless otherwise indicated, each beneficial owner has both sole voting and
sole investment power with respect to the shares beneficially owned by
such person, entity or group. The number of shares shown as beneficially
owned include all options, warrants and convertible securities held by
such person, entity or group that are exercisable or convertible within 60
days of March 9, 2005.
(2) The percentages of beneficial ownership as to each person, entity or group
assume the exercise or conversion of all options, warrants and convertible
securities held by such person, entity or group which are exercisable or
convertible within 60 days, but not the exercise or conversion of options,
warrants and convertible securities held by others shown in the table.
(3) Shares shown as beneficially owned by Orrie Lee Tawes include 119,034 held
by his wife, Marsha Russell.
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In July 2001, we borrowed approximately $664,000 from John F. Terwilliger, our
sole director and executive officer. We utilized a portion of the funds borrowed
from Mr. Terwilliger to pay the principal and accrued interest on the $216,981
promissory note that was payable to Moose Oil & Gas Company upon the purchase of
our oil and gas properties, and to repay Moose Operating for the operating
expenses and drilling and completing costs it had advanced on our behalf
pursuant to the Operating Agreement.
In December 2003, Mr. Terwilliger converted $441,516.29 of loans into 1,103,791
shares of common stock of Houston American and modified the repayment terms with
respect to the balance of the loans to Houston American, totaling $1 million, to
reduce the interest rate on the loans to 7.2% and provide for a fixed maturity
date of January 1, 2007. Also, in December 2003, Orrie L. Tawes, a principal
shareholder of the Company, converted the entire principal and accrued interest
on his loans to Houston American, in the amount of $186,016.83, into 465,042
shares of common stock. As of December 31, 2004, we owed $1,004,400 to Mr.
Terwilliger, including accrued interest.
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 Orrie L. Tawes, a
significant shareholder. During 2004, approximately $14,500 was paid to Mr.
Tawes from these royalty interests.
23
ITEM 13. 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).
24
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")).
25
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 (incorporated by
reference to Exhibit 14.1 to the Company's 2003 Form 10-KSB)
31.1 Section 302 Certifications
32.1 Section 906 Certifications
26
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Fees Paid to Independent Public Accountants
The following table presents fees for professional audit services rendered by
Thomas Leger & Co., L.L.P. for the audit of the Company's annual financial
statements for the years ended December 31, 2004 and December 31, 2003 and fees
billed for other services rendered by Thomas Leger & Co., L.L.P. during those
periods.
Fiscal 2004 Fiscal 2003
------------ ------------
Audit fees (1) $ 31,750 $ 20,610
Audit related fees -- --
Tax fees -- --
All other fees -- --
------------ ------------
Total $ 31,750 $ 20,610
============ ============
(1) Audit Fees consist of fees billed for professional services rendered for
the audit of the Company's consolidated annual financial statements and
review of the interim consolidated financial statements included in
quarterly reports and services that are normally provided by Thomas Leger
& Co., L.L.P. in connection with statutory and regulatory filings or
engagements.
Policy on Pre-Approval of Audit and Non-Audit Services of Independent Auditor
At such time, if ever, as we form an audit committee, we intend that the audit
committee will establish a specific policy relating to pre-approval of all audit
and non-audit services provided by our independent auditors. As we do not
presently maintain an audit committee, no such policy has been adopted to date.
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant
caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
HOUSTON AMERICAN ENERGY CORP.
Dated: March 9, 2005
By: /s/ John F. Terwilliger
--------------------------
John F. Terwilliger
President
27
HOUSTON AMERICAN ENERGY CORP.
INDEX TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm.............................. F-1
Balance Sheet as of December 31, 2004................................................ F-2
Statements of Operations For the Years ended December 31, 2004 and 2003.............. F-3
Statements of Shareholders' Equity for the Years ended December 31, 2004 and 2003.... F-4
Statements of Cash Flows For the Years Ended December 31, 2004 and 2003.............. F-5
Notes to Financial Statements........................................................ F-6 to F-17
28
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Houston American Energy Corp.
Houston, Texas
We have audited the accompanying balance sheet of Houston American Energy Corp.
as of December 31, 2004 and the related statements of operations, shareholders'
equity, and cash flows for the years ended December 31, 2004 and 2003. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit.
We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the over-all
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects the financial position of Houston American Energy Corp. as
of December 31, 2004, and the results of its operations and its cash flows for
the years ended December 31, 2004 and 2003 in conformity with accounting
principles generally accepted in the United States of America.
Thomas Leger & Co., L.L.P.
March 4, 2004
Houston, Texas
F-1
HOUSTON AMERICAN ENERGY CORP.
BALANCE SHEET
December 31, 2004
================================================================================
ASSETS
CURRENT ASSETS
Cash $ 721,613
Accounts receivable 240,141
Prepaid expenses 89,947
------------
Total current assets 1,051,701
------------
PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties, full cost method
Costs subject to amortization 2,342,733
Costs not being amortized 60,795
Office equipment 10,878
------------
Total properties 2,414,406
Accumulated depreciation and depletion oil and
gas properties (1,010,855)
------------
Property, plant and equipment, net 1,403,551
------------
OTHER ASSETS 3,167
------------
TOTAL ASSETS $ 2,458,419
============
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 195,774
Accrued expenses 80,135
Accrued interest on shareholder loans 4,400
------------
Total current liabilities 280,309
------------
LONG-TERM DEBT
Notes payable to principal shareholder 1,000,000
------------
SHAREHOLDERS' EQUITY
Common stock, par value $.001;
100,000,000 shares authorized, 19,968,089
shares outstanding 19,968
Additional paid-in capital 2,800,027
Treasury stock, at cost; 100,000 shares (85,834)
Accumulated deficit (1,556,051)
------------
Total shareholders' equity 1,178,110
------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 2,458,419
============
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, 2004 AND 2003
================================================================================
2004 2003
------------ ------------
OIL AND GAS REVENUE $ 1,182,063 $ 220,600
------------ ------------
EXPENSES OF OPERATIONS
Lease operating expense 413,723 146,914
Joint venture expense 41,944 36,940
Depreciation and depletion 211,759 56,434
Interest expense on shareholder debt 72,000 142,349
General and administrative expense
Professional fees 150,603 63,630
Rent 39,772 41,219
Investor relations 29,363 41,402
Salary 45,000 --
Miscellaneous 62,616 36,042
------------ ------------
Total expenses 1,066,780 564,930
------------ ------------
FEDERAL INCOME TAXES -- --
------------ ------------
NET INCOME (LOSS) $ 115,283 $ (344,330)
============ ============
Basic and diluted income (loss) per share $ 0.01 $ (0.02)
============ ============
Basic and diluted weighted average shares 19,619,084 15,398,070
============ ============
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, 2004 and 2003
================================================================================
Common Stock Treasury Stock
--------------------------------------- --------------------------
Paid - in
Shares Amount Capital Shares Amount
----------- ----------- ----------- ----------- -----------
Balance at December 31, 2002 13,424,883 $ 13,425 $ 283,575 -- $ --
Stock issued for -
Cash 4,271,390 4,271 1,382,651 -- --
Services 20,000 20 7,580 -- --
Converted shareholder debt 1,568,825 1,569 625,961 -- --
Net loss -- -- -- -- --
----------- ----------- ----------- ----------- -----------
Balance at December 31, 2003 19,285,098 19,285 2,299,767 -- --
Stock issued for -
Cash 532,991 533 349,910 -- --
Oil and gas activity and services 150,000 150 150,350 -- --
Purchase of treasury stock -- -- -- (100,000) (85,834)
Net income -- -- -- -- --
----------- ----------- ----------- ----------- -----------
Balance at December 31, 2004 19,968,089 $ 19,968 $ 2,800,027 (100,000) $ (85,834)
=========== =========== =========== =========== ===========
Accumulated
Equity
(Deficit) Total
----------- -----------
Balance at December 31, 2002 $(1,327,004) $(1,030,004)
Stock issued for -
Cash -- 1,386,922
Services -- 7,600
Converted shareholder debt -- 627,530
Net loss (344,330) (344,330)
----------- -----------
Balance at December 31, 2003 (1,671,334) 647,718
Stock issued for -
Cash -- 350,443
Oil and gas activity and services -- 150,500
Purchase of treasury stock -- (85,834)
Net income 115,283 115,283
----------- -----------
Balance at December 31, 2004 $(1,556,051) $ 1,178,110
=========== ===========
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, 2004 and 2003
================================================================================
2004 2003
------------ ------------
CASH FLOW FROM OPERATING ACTIVITIES
Income (loss) from operations $ 115,283 $ (344,330)
Adjustments to reconcile net income (loss)
to net cash from operations
Depreciation and depletion 211,759 56,434
Non-cash expenses 17,166 13,641
(Increase) in accounts receivable (174,138) (58,863)
(Increase) decrease in prepaid expense (84,009) 1,088
(Increase) decrease in other assets 36,864 (35,285)
Increase in accounts payable
and accrued expenses 175,070 213,616
------------ ------------
Net cash provided by (used in) operations 297,995 (153,699)
------------ ------------
CASH FLOW FROM INVESTING ACTIVITIES
Acquisition of properties and assets (611,897) (764,940)
Funds in excess of prospect costs 21,650 --
------------ ------------
Net cash used in investing activities (590,247) (764,940)
------------ ------------
CASH FLOW FROM FINANCING ACTIVITIES
Sale of common stock - net of costs 350,443 1,386,922
Loans from principal shareholders -- 194,200
------------ ------------
Net cash provided by financing 350,443 1,581,122
------------ ------------
INCREASE IN CASH 58,191 662,483
Cash, beginning of period 663,422 939
------------ ------------
Cash, end of period $ 721,613 $ 663,422
============ ============
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid $ 67,600 $ --
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING
AND FINANCING ACTIVITIES
Shareholder notes payable converted to common stock $ -- $ 627,530
Stock issued for oil and gas activity 47,500 --
Acquisition of treasury stock 85,834 --
Shareholder note payable given for oil and gas
properties and general and administrative expenses -- 17,152
Stock issued for services 103,000 --
The accompanying notes are an integral part of these financial statements.
F-5
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2004
=================================
NOTE 1. - NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General - Houston American Energy Corp. (a Delaware Corporation) ("the Company"
or "HUSA") was incorporated on April 2, 2001. The Company is engaged, as a
non-operating joint owner, in the exploration, development, and production of
natural gas, crude oil, and condensate from properties located principally in
the Gulf Coast area of the United States and international locations with proven
production, which to date has focused on Columbia, South America.
General Principles And Use Of Estimates - The financial statements have been
prepared in conformity with accounting principles generally accepted in the
United States of America. In preparing financial statements, Management makes
informed judgments and estimates that affect the reported amounts of assets and
liabilities as of the date of the financial statements and affect the reported
amounts of revenues and expenses during the reporting period. On an ongoing
basis, Management reviews its estimates, including those related to such
potential matters as litigation, environmental liabilities, income taxes and
determination of proved reserves. Changes in facts and circumstances may result
in revised estimates and actual results may differ from these estimates.
Certain amounts for prior periods have been reclassified to conform to the
current presentation.
Oil and Gas Revenues - The Company recognizes sales revenues based on the amount
of gas, oil and condensate sold to purchasers when delivery to the purchaser has
occurred and title has transferred. This occurs when production has been
delivered to a pipeline. Currently, the Company does not anticipate that the oil
and gas sold will be significantly different from the Company's production
entitlement.
Oil and Gas Properties and Equipment - The Company uses the full cost method of
accounting for exploration and development activities as defined by the SEC.
Under this method of accounting, the costs for unsuccessful, as well as
successful, exploration and development activities are capitalized as oil and
gas properties. Capitalized costs include lease acquisition, geological and
geophysical work, delay rentals, costs of drilling, completing and equipping the
wells and any internal costs that are directly related to acquisition,
exploration and development activities but does not include any costs related to
production, general corporate overhead or similar activities. Gain or loss on
the sale or other disposition of oil and gas properties is not recognized,
unless the gain or loss would significantly alter the relationship between
capitalized costs and proved reserves of oil and natural gas attributable to a
country.
The Company categorizes its full costs pools as costs subject to amortization
and costs not being 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.
Office equipment is stated at original cost and is depreciated on the
straight-line basis over the useful life of the assets, which ranges from three
to five years. Oil and gas properties and office equipment carrying values do
not purport to represent replacement or market values.
Depreciation expense for office equipment was $2,175 and $1,119 at December 31,
2004 and 2003, respectively and accumulated reserve for depreciation was $5,458
at December 31, 2004. Depletion and amortization for oil and gas properties was
$206,584 and $54,831 at December 31, 2004 and 2003, respectively and accumulated
reserve for depletion and amortization was $1,005,397 at December 31, 2004.
Repairs and maintenance are expensed as incurred.
F-6
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2004
=================================
NOTE 1. - NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(continued)
Costs Excluded - Oil and gas properties include costs that are excluded from
capitalized costs being amortized. These amounts represent costs of investments
in unproved properties. The Company excludes these costs on a country-by-country
basis until proved reserves are found or until it is determined that the costs
are impaired. All costs excluded are reviewed quarterly to determine if
impairment has occurred. The amount of any impairment is transferred to the
costs subject to amortization.
Ceiling Test - Under the full cost method of accounting, a ceiling test is
performed each quarter. The full cost ceiling test is an impairment test
prescribed by Securities and Exchange Commission (SEC") Regulation S-X. The
ceiling test determines a limit, on a country-by-country basis, on the book
value of oil and gas properties. The capitalized costs of proved oil and gas
properties, net of accumulated depreciation, depletion and amortization ("DD&A")
and the related deferred income taxes, may not exceed the estimated future net
cash flows from proved oil and gas reserves, using prices in effect at the end
of the period with consideration of price change only to the extent provided by
contractual arrangement, discounted at 10%, net of related tax effects. If
capitalized costs exceed this limit, the excess is charged to expense and
reflected as additional accumulated DD&A.
Proved oil and gas reserves, as defined by SEC Regulation S-X, are the estimated
quantities of crude oil, natural gas, and condensate which geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery are included as proved developed
reserves only after testing by a pilot project or after the operation of an
installed program has confirmed through production response that increased
recovery will be achieved.
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage are limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units are claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive formation.
The Company emphasizes that the volumes of reserves are estimates, which, by
their nature, are subject to revision. The estimates are made using all
available geological and reservoir data, as well as production performance data.
These estimates, made by an independent reservoir engineer (approximately 79% 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.
F-7
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2004
=================================
NOTE 1. - NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(continued)
Ceiling Test (continued)
Unevaluated oil and gas properties not subject to amortization at December 31,
2004 include the following:
Acquistion costs $ 48,636
Geological, geophysical and screening costs 12,159
--------
Total $ 60,795
========
All but $12,519 of this cost was incurred on U.S. properties.
Asset Retirement Obligations - On January 1, 2003, we adopted SFAS 143,
"Accounting for Asset Retirement Obligations," which addresses accounting and
reporting for obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs. For us, asset retirement
obligations ("ARO") represent the systematic, monthly accretion and depreciation
of future abandonment costs of tangible assets such as platforms, wells, service
assets, pipelines, and other facilities. SFAS 143 requires that the fair value
of a liability for an asset's retirement obligation be recorded in the period in
which it is incurred if a reasonable estimate of fair value can be made, and
that the corresponding cost is capitalized as part of the carrying amount of the
related long-lived asset. The liability is accreted to its then present value
each period, and the capitalized cost is depreciated over the useful life of the
related asset. If the liability is settled for an amount other than the recorded
amount, an adjustment is made to the full cost pool, with no gain or loss
recognized, unless the adjustment would significantly alter the relationship
between capitalized costs and proved reserves. Under our previous accounting
method, we included estimated future costs of abandonment and dismantlement in
our full cost amortization base and amortized these costs as a component of our
depletion expense. Subsequent to our adoption of SFAS 143, the ARO assets, which
are carried on the balance sheet as part of the full cost pool, have been
included in our amortization base for the purposes of calculating depreciation,
depletion and amortization expense. The future cash outflows associated with
settling the ARO liability have been adjusted so they are included in the
ceiling test.
The following table describes changes in our asset retirement liability during
each of the years ended December 31, 2004 and 2003. The ARO liability in the
table below includes amounts classified as both current and long-term at
December 31, 2004 and 2003.
2004 2003
---------- ----------
ARO liability at January 1, $ 15,625 $ 12,750
Accretion expense 3,000 --
Liabilities incurred from drilling 21,327 2,875
---------- ----------
ARO liability at December 31 $ 39,952 $ 15,625
========== ==========
Joint Venture Expense - Joint venture expense reflects the indirect field
operating and regional administrative expenses billed by the operator of the
Columbian CaraCara and Tambaqui concessions.
F-8
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2004
=================================
Income Taxes - Deferred income taxes are provided on a liability method whereby
deferred tax assets and liabilities are established for the difference between
the financial reporting and income tax basis of assets and liabilities as well
as operating loss and tax credit carry forwards. Deferred tax assets are reduced
by a valuation allowance when, in the opinion of management, it is more likely
than not that some portion or all of the deferred tax assets will not be
realized. Deferred tax assets and liabilities are adjusted for the effects of
changes in tax laws and rates on the date of enactment.
Preferred Stock - The Company has authorized 10,000,000 shares of preferred
stock with a par value of $.001. The Board of Directors shall determine the
designations, rights, preferences, privileges and voting rights of the preferred
stock as well as any restrictions and qualifications thereon. No shares of
preferred stock have been issued.
Statement of Cash Flows - Cash equivalents consists of demand deposits and cash
investments with initial maturity dates of less than three months.
Net Loss Per Share - Basic loss per share is computed by dividing the net loss
available to common shareholders by the weighted average of common shares
outstanding during the period. Diluted per share amounts assume the conversion,
exercise, or issuance of all potential common stock instruments unless the
effect is anti-dilutive, thereby reducing the loss or increasing the income per
share.
Concentration of Risk - The Company is dependent upon the industry skills and
contacts of John F. Terwilliger, the sole director and chief executive officer,
to identify potential acquisition targets in the onshore coastal Gulf of Mexico
region of Texas and Louisiana. Further, as a non-operator oil and gas
exploration and production company and through its interest in a limited
liability company and four concessions in the South American country of
Colombia, the Company is dependent on the personnel, management and resources of
those entities to operate efficiently and effectively.
As a non-operating joint interest owner, the Company has a right of investment
refusal on specific projects and the right to examine and contest its division
of costs and revenues determined by the company operator.
The Company currently has interests in four 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.
The Company maintains cash balances in several banks in Houston, Texas. Accounts
at banks are insured by the Federal Deposit Insurance Corporation up to
$100,000. At December 31, 2004, the Company's uninsured cash balance was
approximately $501,000.
Major Customers - The majority of production for 2004 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 product sales of
more than 10% to a single buyer.
At December 31, 2004, 71% of the Company's net oil and gas property investment
and 68% of its revenue was with or derived from the company managing the
Columbian properties.
Recent Accounting Developments - On September 28, 2004, the SEC released Staff
Accounting Bulletin ("SAB") 106 regarding the application of SFAS 143,
"Accounting for Asset Retirement Obligations ("AROs")," by oil and gas producing
companies following the full cost accounting method. Pursuant to SAB 106, oil
and gas producing companies that have adopted SFAS 143 should exclude the future
cash outflows associated with settling AROs (ARO liabilities) from the
computation of the present value of estimated future net revenues for the
purposes of the full cost ceiling calculation. In addition, estimated
dismantlement and abandonment costs, net of estimated
F-9
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2004
=================================
NOTE 1. - NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(continued)
Recent Accounting Developments (continued)
salvage values, which have been capitalized (ARO assets) should be included in
the amortization base for computing depreciation, depletion and amortization
expense. Disclosures are required to include discussion of how a company's
ceiling test and depreciation, depletion and amortization calculations are
impacted by the adoption of SFAS 143. SAB 106 is effective prospectively as of
the beginning of the first fiscal quarter beginning after October 4, 2004. Since
the Company's adoption of SFAS 143 on January 1, 2003, they have calculated the
ceiling test and depreciation, depletion and amortization expense in accordance
with the interpretations set forth in SAB 106; therefore, the adoption of SAB
106 had no effect on the financial statements.
On December 16, 2004, the FASB revised Statement 123 (revised 2004),
"Share-Based Payment" that will require compensation costs related to
share-based payment transactions (e.g., issuance of stock options and restricted
stock) to be recognized in the financial statements. With limited exceptions,
the amount of compensation cost will be measured based on the grant-date fair
value of the equity or liability instruments issued. In addition, liability
awards will be remeasured each reporting period. Compensation cost will be
recognized over the period that an employee provides service in exchange for the
award. Statement 123(R) replaces SFAS 123, "Accounting for Stock- Based
Compensation," and supersedes Accounting Principles Board ("APB") Opinion No.
25, "Accounting for Stock Issued to Employees." For the Company, SFAS 123(R) is
effective for the first quarterly reporting period after December 15, 2005.
Entities that use the fair-value-based method for either recognition or
disclosure under SFAS 123 are required to apply SFAS 123(R) using a modified
version of prospective application. Under this method, an entity records
compensation expense for all awards it grants after the date of adoption. In
addition, the entity is required to record compensation expense for the unvested
portion of previously granted awards that remain outstanding at the date of
adoption. In addition, entities may elect to adopt SFAS 123(R) using a modified
retrospective method where by previously issued financial statements are
restated based on the expense previously calculated and reported in the pro
forma footnote disclosures. The Company does not expect the adoption of SFAS
123(R) to have a material impact on the financial statements.
On December 16, 2004, the FASB issued Statement 153, "Exchanges of Nonmonetary
Assets", an amendment of APB Opinion No. 29, to clarify the accounting for
nonmonetrary exchanges of similar productive assets. SFAS 153 eliminates the
exception from the fair value measurement for nonmonetary exchanges of similar
productive assets and replaces it with a general exception for exchanges of
nonmonetary assets that do not have commercial substance. A nonmonetary exchange
has commercial substance if the future cash flows of the entity are expected to
change significantly as a result of the exchange. The Statement will be applied
prospectively and is effective for nonmonetary asset exchanges occurring in
fiscal periods beginning after June 15, 2005. The Company does not have any
nonmonetary transactions for any period presented that this Statement would
apply. The Company does not expect the adoption of SFAS 153 to have a material
impact on the financials statements.
NOTE 2. - NOTES PAYABLE
Notes payable at December 31, 2004, 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.
F-10
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2004
=================================
NOTE 2. - NOTES PAYABLE (continued)
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.
NOTE 3. - 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.
John F. Terwilliger has not received any direct or indirect compensation or
other salary related benefits from the Company before October 1, 2004. Effective
that date he started receiving a salary. He was paid $45,000 in 2004.
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
2004, approximately $36,000 was paid to John Terwilliger and Orrie L. Tawes from
these royalty interests.
NOTE 4 - INCOME TAXES
The following table sets forth a reconciliation of the statutory federal income
tax for the year ended December 31, 2004 and 2003.
2004 2003
---------- ----------
Income (loss) before income taxes $ 115,238 $ (344,330)
========== ==========
Income tax computed at statutory rates $ 39,196 $ (117,073)
Net increase in net operating loss carryforward 7,827 --
Permanent differences, nondeductible expenses 7,168 (47,752)
Increase (decrease) in valuation allowance (58,264) 164,825
Other 4,073 --
---------- ----------
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 $1,351,000 which
will expire in 2016 through 2019. 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, 2004 are set out below.
F-11
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2004
=================================
NOTE 4 - INCOME TAXES (continued)
2004
------------
Deferred tax asset:
Net operating loss carry forwards $ 459,550
Valuation allowance (323,675)
Book over tax depreciation, depletion
and capitalization methods on oil
and gas properties (137,371)
Book over tax accrued interest payments 1,496
------------
Net deferred tax asset $ --
============
NOTE 5. - COMMON STOCK
During the year ended December 31, 2004, the Company (1) issued 532,983 shares
of its common stock for cash consideration of $350,443, (2) in conjunction with
an agreement with an individual to assist the Company in locating viable oil and
gas prospects, issued 50,000 shares of its common stock, valued at $47,500, and
granted an interest equal to 10% of the Company's interest in any prospects
generated by the individual's contacts, and (3) issued 100,000 shares of its
common stock, valued at $103,000, for financial public relations services over a
six month period. The value of the shares issued for financial public relations
services was recorded as prepaid expense and charged to shareholders relations
expense ratably over the life of the contract. During September 2004, the
Company entered into negotiations to terminate the financial public relations
contract as a result of disputes relating to performance under the contract. The
financial public relations contract was terminated, the 100,000 shares
originally issued under the contract were returned to the Company and the
Company paid $5,000 in full settlement of the contract. As a result of the
termination and settlement of the public relations contract, during the quarter
ended September 30, 2004, the Company recorded shareholder relations expense of
$5,000, credited $85,834 against prepaid expenses and recorded treasury stock in
the amount of $85,834.
NOTE 6. - COMMITMENTS AND CONTINGENCIES
Lease Commitment - The Company leases office facilities under an operating lease
agreement which expires November 30, 2006. The lease agreement requires payments
of $39,631 in 2005 and $33,026 in 2006. Total rental expense in 2004 was $39,772
and $41,219 in 2003. The Company does not have any capital leases or other
operating lease commitments.
Legal Contingencies - The Company is subject to legal proceedings, claims and
liabilities that arise in the ordinary course of its business. The Company
accrues for losses associated with legal claims when such losses are probable
and can be reasonably estimated. These accruals are adjusted as further
information develops or circumstances change. During the twelve months ended
December 31, 2004, the Company was named as defendant in a suit filed in the
United States Bankruptcy Court for the Southern District of Texas. The plaintiff
alleges that expenses relating to the formation and operation of the Company
were paid by Moose Oil and Gas or Moose Operating Company, that interests in
certain oil and gas properties were transferred to the Company from Moose Oil
and Gas or Moose Operating Company and that the alleged payments and transfers
constituted fraudulent transfers and avoidable preferences. The plaintiff seeks
to recover all properties alleged to have been wrongfully transferred as well as
costs of suit and other relief. The Company believes that the action is without
merit and intends to vigorously contest the same.
F-12
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2004
=================================
NOTE 6. - COMMITMENTS AND CONTINGENCIES (continued)
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, 2005, our
acquisition and drilling budget for 2005 was estimated at $886,000.
Post Retirement Benefits - At December 31, 2004, the Company does not have any
pension plans, other postretirement benefits or employee savings plans.
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 South America, by geographic area:
2004 2003
------------ ------------
Revenues
North America $ 373,591 $ 92,080
South America 808,472 128,520
------------ ------------
$ 1,182,063 $ 220,600
============ ============
Production Cost
North America $ 59,275 $ 37,566
South America 354,448 146,288
------------ ------------
$ 413,723 $ 183,854
============ ============
Capital Costs - Capitalized costs and accumulated depletion relating to the
Company's oil and gas producing activities as of December 31, 2004, all of which
are onshore properties located in the United States and Columbia, South America
are summarized below:
NORTH SOUTH
AMERICA AMERICA TOTAL
------------ ------------ ------------
Unproved properties not
being amortized $ 48,636 $ 12,159 $ 60,795
Properties being amortized 1,225,771 1,116,962 2,342,733
Accumulated depreciation,
depletion and amortization (866,080) (139,317) (1,005,397)
------------ ------------ ------------
Total capitalized costs $ 408,327 $ 989,804 $ 1,398,131
============ ============ ============
F-13
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2004
=================================
NOTE 7. - SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND
PRODUCTION ACTIVITIES (UNAUDITED) (continued)
Amortization Rate
The amortization rate per unit base on barrel equivalents was $8.13 for North
America and $4.69 for South America.
Acquisition, Exploration and Development Costs Incurred - Costs incurred in oil
and gas property acquisition, exploration and development activities for
December 31, 2004 and 2003 is summarized below:
2004
---------------------------
North South
America America
------------ ------------
Property acquisition costs:
Proved $ 776,219 $ 405,002
Unproved 48,636 12,159
Exploration costs 428,476 128,275
Development costs 21,077 583,685
------------ ------------
Total costs incurred $ 1,274,408 $ 1,129,121
============ ============
2003
---------------------------
North South
America America
------------ ------------
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
============ ============
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.
F-14
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2004
=================================
NOTE 7. - SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND
PRODUCTION ACTIVITIES (UNAUDITED) (continued)
Reserve Information and Related Standardized Measure of Discounted Future Net
Cash Flows - (continued)
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 certainty 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 79% of total estimated future net
revenues at December 31, 2004. 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.
North America South America Total
---------------------------- --------------------------- ----------------------------
Gas (mcf) Oil (bbls) Gas(mcf) Oil (bbls) Gas (mcf) Oil (bbls)
---------------------------- --------------------------- ----------------------------
Total proved reserves
Balance December 31, 2002 18,872 -- -- -- 18,872 --
Extensions and discoveries 181,227 4,557 -- 275,587 181,227 280,144
Revision of previous 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
Extensions and discoveries 54,458 11,274 -- 264,981 54,458 276,255
Revisions of prior estimates 32,881 (3,198) -- (214,948) 32,881 (218,146)
Production (61,519) (886) -- (24,040) (61,519) (24,926)
------------ ------------ ------------ ------------ ------------ ------------
Balance December 31, 2004 202,420 11,590 -- 295,700 202,420 307,290
============ ============ ============ ============ ============ ============
Proved developed reserves
at December 31, 2004 141,000 2,500 -- 97,610 141,000 100,110
============ ============ ============ ============ ============ ============
The standardized measure of discounted future net cash flows relating to proved
oil and gas reserves is computed by applying year-end prices of oil and gas
(with consideration of price changes only to the extent provided by contractual
arrangements) to the estimated future production of proved oil and gas reserves,
less estimated future expenditures (based on year-end costs) to be incurred in
developing and producing the proved reserves, less estimated related future
income tax expenses (based on year-end statutory tax rates, with consideration
of future tax rates already legislated), and assuming continuation of existing
economic conditions. Future income tax expenses give effect to permanent
differences and tax credits but do not reflect the impact of continuing
operations including property acquisitions and exploration. The estimated future
cash flows are then discounted using a rate of ten percent a year to reflect the
estimated timing of the future cash flows.
F-15
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2004
=================================
NOTE 7. - SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND
PRODUCTION ACTIVITIES (UNAUDITED) (continued)
Reserve Information and Related Standardized Measure of Discounted Future Net
Cash Flows - (continued)
Standard measure of discounted future net cash flows at December 31, 2004:
North South
America America Total
------------------------------------------
Future net cash flows $ 1,693,780 $ 10,018,312 $ 11,712,092
Future production cost 267,550 4,709,171 4,976,721
Future income tax expense 271,884 1,219,685 1,491,569
------------ ------------ ------------
Future net cash flow 1,154,346 4,089,456 5,243,802
10% annual discount for timing of cash flows 310,053 928,125 1,238,178
------------ ------------ ------------
Standardized measure of discounted future net
cash flow relating to proved oil and gas reserves $ 844,293 $ 3,161,331 $ 4,005,624
============ ============ ============
Changes in standardized measure:
Change due to current year operations
Sales, net of production costs $ (726,396)
Changes due to revisions in standardized variables:
Income taxes (516,350)
Accretion of discount 389,559
Revision and others (2,329,947)
Discoveries 4,016,119
------------
Net 832,985
Beginning of year 3,172,639
------------
End of year $ 4,005,624
============
F-16
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2004
=================================
NOTE 7. - SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND
PRODUCTION ACTIVITIES (UNAUDITED) (continued)
Reserve Information and Related Standardized Measure of Discounted Future Net
Cash Flows - (continued)
Standard measure of discounted future net cash flows at December 31, 2003:
North South
America America 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-17