SECURITIES AND EXCHANGE COMMISSION
CITYWASHINGTON, STATED.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, 2006
[_] TRANSITION REPORT UNDER SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the transition period from ____________ to _____________
Commission File No. 1-32955
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 of (I.R.S. Employer
incorporation or organization) Identification No.)
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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Common Stock, American Stock Exchange
$0.001 par value
Securities to be registered pursuant to Section 12(g) of the Act:
None
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(Title of Class)
Check whether the issuer is not required to file reports pursuant to Section 13
or 15(d) of the Exchange Act. [_]
Check whether the issuer: (1) filed all reports required to be filed by Section
13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter
period that the registrant was required to file such reports); and (2) has been
subject to such filing requirements for the past 90 days. Yes [X] No [_]
Check if there is no disclosure of delinquent filers in response to Item 405 of
Regulation S-B contained in this form, and no disclosure will be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-KSB or any
amendment to this Form 10-KSB. [X]
Indicate by check mark whether the registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act). Yes [_] No [X]
The Issuer's revenues for the fiscal year ended December 31, 2006 were
$3,202,731.
The aggregate market value of the voting and non-voting common equity held by
non-affiliates of the registrant on February 15, 2007, based on the last sales
price on the American Stock Exchange as of such date, was approximately
$65,776,746.
The number of shares of the registrant's common stock, $0.001 par value per
share, outstanding as of February 15, 2007 was 27,920,172.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Company's Proxy Statement for its 2007 Annual Meeting are
incorporated by reference into Part III of this Report.
Transition Small Business Disclosure Format: Yes [_] No [X]
1
TABLE OF CONTENTS
Page
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PART I
ITEM 1. DESCRIPTION OF BUSINESS. . . . . . . . . . . . . . . 3
ITEM 2. DESCRIPTION OF PROPERTY. . . . . . . . . . . . . . . 16
ITEM 3. LEGAL PROCEEDINGS. . . . . . . . . . . . . . . . . . 16
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF
SECURITY HOLDERS . . . . . . . . . . . . . . . . . . 16
PART II
ITEM 5. MARKET FOR COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS. . . . . . . . . . . . . 17
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS . . . . . . . . 18
ITEM 7. FINANCIAL STATEMENTS . . . . . . . . . . . . . . . . 25
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE . . . . . . . 25
ITEM 8A. CONTROLS AND PROCEDURES. . . . . . . . . . . . . . . 25
ITEM 8B. OTHER INFORMATION. . . . . . . . . . . . . . . . . . 25
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND
CONTROL PERSONS; COMPLIANCE WITH
SECTION 16(a) OF THE EXCHANGE ACT. . . . . . . . . . 26
ITEM 10. EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . 26
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT. . . . . . . . . . . . . . . . 26
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS . . . 27
ITEM 13. EXHIBITS AND REPORTS OF FORM 8-K . . . . . . . . . . 27
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES . . . . . . . 28
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
Louisiana, and development of concessions in the South American country of
Colombia. We seek to utilize the contacts and experience of our chief 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, 2006 consisted on the
following:
- Domestic Exploration Properties:
WEBSTER PARISH, LOUISIANA. In Webster Parish, Louisiana, we hold a 7.5% working
interest at an 8.3% net revenue interest carried to point of sales for the first
well in over 4,000 acres known as the South Sibley Prospect. Drilling of a
10,600-foot well, the first well, on the South Sibley Prospect, was completed in
May 2005 with multiple pay sands apparently identified. Sales from the well
commenced June 28, 2005.
We also hold a 7.5% working interest at a 6.055% net revenue interest in the
Holley #1 well and associated 640-acre unit, acquired in December 2005, in
Webster Parish, Louisiana.
3
ACADIA PARISH, LOUISIANA. In Acadia Parish, Louisiana, we hold a 3% working
interest and a 2.25% net revenue interest until payout in a 620-acre leasehold
known as the Crowley Prospect. The Hoffpauer #1 (formerly the Baronet #1) was
drilled in the third quarter of 2004. Commercial production of the well
commenced in December 2004. Drilling of a 12,100-foot well, the Baronet #2
well, on the Crowley Prospect in Acadia Parish, Louisiana was completed in April
2005. The well tested the Hayes Sand and flanks a natural gas well that
produced 1.6 BCF of natural gas from the Hayes Sand. After logging 21-feet of
apparent net pay, hole conditions deteriorated before logging could be
completed. The well was completed and production began in June 2005 and was
reworked during the second half of 2006. The Baronet #3, a replacement well for
the Baronet #2, is scheduled to be drilled during the first half of 2007. The
Company will own a 15.5% working interest and 11.25% net revenue interest in the
Baronet #3.
VERMILLION PARISH, LOUISIANA. In Vermillion Parish, Louisiana, we hold an 8.25%
working interest with a 6.1875% net revenue interest, subject to a 25% working
interest back in at payout, in the 425 acre Sugarland Prospect. The Broussard
#1 well, a 12,900-foot test well, was drilled on the Sugarland Prospect in
December 2005, with indications of multiple pay sands, and was completed in
January 2006. Sales from the Broussard #1 began in March 2006. The Broussard #1
was re-completed in February 2007 and, as a result, was plugged and abandoned.
JIM HOGG COUNTY, TEXAS. In Jim Hogg County, Texas, we hold a 4.375% working
interest, subject to payment of 5.8334% of costs to the casing point in the
first well, in the 500 acre Hog Heaven Prospect. The Weil #1 well, a 6,200-foot
test well, was drilled on the Hog Heaven Prospect in November 2005. Electric
log and sidewall core analysis indicated multiple pay sands in the Weil #1 well.
The well was completed in January 2006 and production and sales commenced in
March 2006.
WILBARGER COUNTY, TEXAS. In Wilbarger County, Texas, we hold a 15% working
interest with an 11.625% net revenue interest in the 900-acre West Fargo
Prospect. The Riggins #1 well, a 6,400-foot test well, was drilled on the Wells
Fargo Prospect in 2006 and was non-commercial.
We also hold a 15% working interest with an 11.25% net revenue interest in the
1340 acre Obenhaus Prospect in Wilbarger County, Texas. The Obenhaus #1 well, a
7,200-foot test well, was drilled on the Obenhaus Prospect in 2006 and was
non-commercial.
HARDEMAN COUNTY, TEXAS. In Hardeman County, Texas, we hold a 10% working
interest with a 7.5% net revenue interest in the 91.375 acre West Turkey
Prospect. The DDD-Evans #1, an 8,500-foot test well, was drilled on the West
Turkey Prospect in April 2006 and production began in May 2006. At December 31,
2006, the DDD-Evans #1 was producing, but at non-commercial levels.
- Colombian Exploration Properties:
LLANOS BASIN, COLOMBIA. In the Llanos Basin, Colombia, we hold interests in (1)
a 232,050 acre tract known as the Cara Cara concession, (2) the Tambaqui
Association Contract covering 4,400 acres in the State of Casanare, Colombia,
(3) two concessions, the Dorotea Contract and the Cabiona Contract, totaling
over 137,000 acres, (4) the Surimena concession covering approximately 69,000
acres, (5) the Las Garzas concession covering approximately 103,000 acres, (6)
the Leona concession covering approximately 70,343 acres, and (7) the Camarita
concession covering approximately 166,000 acres.
Our interest in each of the described concessions and contracts in Colombia are
held through an interest in Hupecol, LLC and affiliated entities. We hold a
12.5% working interest in each of the prospects of Hupecol other than the Cara
Cara concession, the Surimena concession and the Tambaqui Association Contract.
We hold a 1.6% working interest in the Cara Cara concession, a 6.25% working
interest in the Surimena concession and a 12.6% working interest, with an 11.31%
net revenue interest, in the Tambaqui Association Contract.
The first well drilled in the Cara Cara concession, the Jaguar #1 well, was
completed in April 2003 with initial production of 892 barrels of oil per day.
In conjunction with the efforts to develop the Cara Cara concession, Hupecol
acquired 50 square miles of 3D seismic grid surrounding the Jaguar #1 well and
other prospect areas. That data is being utilized to identify additional drill
site opportunities to develop a field around the Jaguar #1 well and in other
prospect areas within the grid.
Our working interest in the Cara Cara concession and the Tambaqui Association
Contract are subject to an escalating royalty of 8% on the first 5,000 barrels
of oil per day, increasing to 20% at 125,000 barrels of oil per day. Our
interest in the Tambaqui Association Contract is subject to reversionary
interests of Ecopetrol, the state owned
4
Colombian oil company, that could cause 50% of the working interest to revert to
Ecopetrol after we have recouped four times our initial investment. Our working
interest in the additional concessions is subject to an escalating royalty
ranging from 8% to 20% depending upon production volumes and pricing and an
additional 6% to 10% per concession when 5,000,000 barrels of oil have been
produced on that concession.
In December 2003, we exercised our right to participate in the acquisition,
through Hupecol, of over 3,000 kilometers of seismic data in Colombia covering
in excess of 20 million acres. The seismic data is being utilized to map
prospects in key areas with a view to delineating multiple drilling
opportunities. We will hold a 12.5% interest in all prospects developed by
Hupecol arising from the acquired seismic data, including the Cabiona and
Dorotea concessions acquired in the fourth quarter of 2004, the Surimena
concession acquired in the second quarter of 2005, the Las Garzas concession
acquired in November 2005, the Jagueyes TEA acquired in May 2005 and the Simon
TEA acquired in June 2005. During 2006 we acquired 3D seismic data on the Las
Garzas contract, the Jagueyes TEA and the Simon TEA. As a result of seismic
evaluation, the Jagueyes TEA was converted to the Leona concession and the Simon
TEA was converted to the Camarita concession during 2006.
During 2006, Hupecol drilled 8 wells on the Cara Cara concession in Colombia to
offset, and delineate, the Jaguar #1 well, with production commencing on 7
wells. One of the wells drilled during 2006 on the Cara Cara concession was a
dry hole. We hold a 1.59% working interest in each of the wells subject to a
30% reversionary interest to Ecopetrol at payout.
During 2006, no wells were drilled under the Tambaqui Association Contract. We
hold a 12.6% working interest in wells drilled under the Tambaqui Association
Contract.
During 2006, Hupecol drilled 5 wells on the Dorotea and Cabiona concessions with
production commencing on 2 wells. Three of the wells drilled during 2006 on the
Dorotea and Cabiona concessions were dry holes.
During 2006, 1 dry hole was drilled on Surimena concession and no wells were
drilled on the Las Garzas concession, the Leona concession (formerly known as
the Jagueyes TEA) or the Camarita concession (formerly known as the Simon TEA).
2007 DRILLING PLANS
As of January 1, 2007, we planned to drill a total of 31 wells during 2007, of
which 1 well is planned to be drilled on our domestic exploration projects and
30 wells are planned to be drilled on our Colombian exploration projects. The
following table reflects planned drilling activities during 2007:
Location Prospect Name # of Planned Wells
---------------------- --------------------- ------------------
Acadia Parish, LA Baronet #3 1
Llanos Basin, Colombia Cara Cara Concession 13
Llanos Basin, Colombia Dorotea Concession 1
Llanos Basin, Colombia Cabiona Concession 8
Llanos Basin, Colombia Las Garzas Concession 2
Llanos Basin, Colombia Leona Concession 2
Llanos Basin, Colombia Camarita Concession 4
Our planned drilling activity is subject to change from time to time without
notice.
OTHER HOLDINGS
In addition to our principal exploration projects, we hold various interests in
producing wells in Vermillion Parish, Louisiana, Plaquemines Parish, Louisiana,
Lavaca County, Texas, Matagorda County, Texas, San Patricio County, Texas,
Victoria County, Texas and Ellis County, Oklahoma. We have no present plans to
conduct additional drilling activities on those prospects.
5
The following table sets forth certain information about our oil and gas
holdings at December 31, 2006:
Acres Leased or Under Option at December 31, 2006(1)
--------------------------------------------------------
Project
Project Area Project Gross Project Net Company Net Interest
------------------------------ ----------------- ------------------ ----------------- ---------
TEXAS:
Jim Hogg County 500.00 500.0 21.88 4.38%
Wilbarger County
West Fargo Prospect. . . . . 900.00 900.00 135.00 15.00%
Obenhaus Prospect. . . . . . 1,340.00 1,340.00 201.00 15.00%
Lavaca County
West Hardys Creek. . . . . . 65.65 65.65 24.95 38.00%
San Patricio County 380.00 380.00 19.00 5.00%
Hardeman County 91.38 91.38 9.14 10.00%
Matagorda County
S.W. Pheasant Prospect . . . 779.00 779.00 27.27 3.50%
Nacogdoches County 80.94 80.94 80.94 100.00%
Victoria County 58.37 58.37 29.18 50.00%
----------------- ------------------ -----------------
Texas Sub-Total. . . . . . . . 4,195.34 4,195.34 548.36
LOUISIANA:
Webster Parish 6,244.00 4,457.00 334.28 7.50%
Vermillion Parish
Sugarland Prospect . . . . . 425.00 425.00 35.06 8.25%
LaFurs F-16 Well . . . . . . 830.00 830.00 18.68 2.25%
Acadia Parish. . . . . . . . . 620.00 620.00 18.60 3.00%
Plaquemines Parish . . . . . . 300.00 300.00 5.40 1.80%
----------------- ------------------ -----------------
Louisiana Sub-Total. . . . . . 8,419.00 6,632.00 412.02
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 . . . . 232,500.00 232,500.00 3,697.00 1.59%
Tambaqui Assoc. Contract (2) 4,403.00 4,403.00 555.00 12.6%
Dorotea Concession . . . . . 51,321.00 51,321.00 6,415.00 12.5%
Cabiona Concession . . . . . 86,066.00 86,066.00 10,758.00 12.5%
Surimena Concession. . . . . 69,189.00 69,189.00 4,324.00 6.25%
Las Garzas Concession. . . . 103,784.00 103,784.00 12,973.00 12.5%
Leona Concession . . . . . . 70,343.00 70,343.00 8,793.00 12.5%
Camarita Concession. . . . . 166,301.00 166,301.00 20,788.00 12.5%
----------------- ------------------ -----------------
Colombia Sub-Total . . . . . . 783,907.00 783,907.00 68,303.00
----------------- ------------------ -----------------
Total. . . . . . . . . . . . . 796,681.34 794,894.34 69,267.16
================= ================== =================
(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.
6
DRILLING ACTIVITIES
In 2006, we drilled 3 domestic wells and 14 wells in Colombia, consisting of 10
exploratory and 7 developmental wells of which 10 were completed and 7 were dry
holes. In 2005, 4 exploratory and 10 developmental wells were drilled of which
all 14 were completed and none were dry holes.
The following table sets forth certain information regarding the actual drilling
results for each of the years 2006 and 2005 as to wells drilled in each such
individual year:
Exploratory Wells(1) Developmental Wells(1)
---------------------- ------------------------
Gross Net Gross Net
---------- ---------- ---------- ------------
2006
----
Productive 3 0.350 7 0.111
Dry. . . . 7 0.816 0 0
2005
----
Productive 4 0.231 10 0.226
Dry. . . . 0 0 0 0
(1) Gross wells represent the total number of wells in which we owned an
interest; net wells represent the total of our net working interests owned
in the wells.
At December 31, 2006, one well was being drilled in Colombia.
SEISMIC ACTIVITY
During 2006, the Company continued its ongoing investment in acquiring and
developing seismic data with respect to its Colombian properties with shooting
being completed on approximately 133 square miles of prospect acreage during the
year.
PRODUCTIVE WELL SUMMARY
The following table sets forth certain information regarding our ownership as of
December 31, 2006 of productive gas and oil wells in the areas indicated:
Gas Oil
------------- ------------
Gross Net Gross Net
----- ------ ----- -----
Texas . . . . 4 0.5088 1 0.100
Louisiana . . 5 0.2130 0 0
Oklahoma. . . 1 0.0240 0 0
Colombia. . . 0 0 22 0.587
----- ------ ----- -----
Total . . . 10 0.7458 23 0.687
===== ====== ===== =====
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,
-------------------------
2006 2005
------------- ----------
Net Production:
Gas (Mcf):
North America . . . . . . . 78,096 106,449
South America . . . . . . . 0 0
Oil (Bbls):
North America . . . . . . . 1,687 1,396
South America . . . . . . . 48,058 42,789
Average sales price:
Gas ($per Mcf). . . . . . . . 6.75 7.83
Oil (Bbls). . . . . . . . . . 55.55 47.89
Average production expense and
Taxes ($per Bbls):
North America . . . . . . . 9.52 4.16
South America . . . . . . . 34.28 20.43
NATURAL GAS AND OIL RESERVES
The following table summarizes the estimates of our historical net proved
reserves as of December 31, 2005 and 2006, and the present value attributable to
these reserves at these dates. The reserve data and present values were
prepared by Aluko & Associates, Inc., independent petroleum engineering
consultants, and Broun Energy, LLC:
At December 31,
----------------------
2006 2005
---------- ----------
Net proved reserves (1):
Natural gas (Mcf). . . . . . . . . . . . . 425,750 850,650
Oil (Bbls) . . . . . . . . . . . . . . . . 392,356 273,421
Standardized measure of discounted future net
cash flows (2) . . . . . . . . . . . . . . . $8,082,337 $6,375,600
(1) At December 31, 2006, net proved reserves, by region, consisted of 389,446
barrels of oil in South America and 2,910 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 8 - 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 report represent only estimates. Reservoir engineering is a
subjective process of estimating underground accumulations of natural gas and
oil that cannot be measured in an exact manner. The accuracy of reserve
estimates is a function of the quality of available data and of engineering and
geological interpretation and judgment. As a result, estimates of different
engineers, including those we use, may vary. In addition, estimates of reserves
may be revised based upon actual production, results of future development and
exploration activities, prevailing natural gas and oil prices, operating costs
and other factors, which revision may be material. Accordingly, reserve
estimates may be different from the quantities of natural gas and oil that we
are ultimately able to recover and are highly dependent upon the accuracy of the
underlying assumptions. Our estimated proved reserves have not been filed with
or included in reports to any federal agency.
LEASEHOLD ACREAGE
The following table sets forth as of December 31, 2006, 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 . . . . 1,684.40 124.04 340 14.88 2,170.94 409.44
Louisiana . . 3,145.00 164.44 310 9.30 3,477.65 238.28
Oklahoma. . . 160.00 3.78 0 0 0 0
Colombia. . . 3,520.00 93.84 480 23.56 779,156.35 68,177.60
--------- ------- --------- --------- ---------- ---------
Total . . . 8,509.40 386.10 1,130 47.74 784,804.94 68,825.32
========= ======= ========= ========= ========== =========
During 2006, we acquired interests in the 91.375 acre West Turkey Prospect in
Hardeman County, Texas. Also, during 2006, we relinquished our interest in the
Green Jacket Prospect in Iberville Parish, Louisiana.
During 2006, as a result of seismic evaluation, the Jagueyes TEA covering
approximately 324,695 acres was converted to the Leona concession covering
approximately 70,343 acres and the Simon TEA covering 166,301 acres was
converted to the Camarita concession covering 166,301 acres.
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 is made
before commencement of drilling operations.
MARKETING
At January 1, 2007, we had no contractual agreements to sell our gas and oil
production and all production was sold on spot markets.
9
RISKS RELATED TO OUR BUSINESS AND STOCK
Our business activities and the value of our securities are subject to
significant hazards and risks, including those described below. If any of such
events should occur, our business, financial condition, liquidity and/or results
of operations could be materially harmed, and holders and purchasers of our
securities could lose part or all of their investments.
A SUBSTANTIAL OR EXTENDED DECLINE IN OIL AND NATURAL GAS PRICES MAY ADVERSELY
AFFECT OUR BUSINESS, FINANCIAL CONDITION OR RESULTS OF OPERATIONS AND OUR
ABILITY TO MEET OUR CAPITAL EXPENDITURE OBLIGATIONS AND FINANCIAL COMMITMENTS.
The price we receive for our oil and natural gas production heavily influences
our revenue, profitability, access to capital and future rate of growth. Oil and
natural gas are commodities and, therefore, their prices are subject to wide
fluctuations in response to relatively minor changes in supply and demand.
Historically, the markets for oil and natural gas have been volatile. These
markets will likely continue to be volatile in the future. The prices we receive
for our production, and the levels of our production, depend on numerous factors
beyond our control. These factors include, but are not limited to, the
following:
- changes in global supply and demand for oil and natural gas;
- the actions of the Organization of Petroleum Exporting Countries, or OPEC;
- the price and quantity of imports of foreign oil and natural gas;
- political conditions, including embargoes, in or affecting other
oil-producing activity;
- the level of global oil and natural gas exploration and production
activity;
- the level of global oil and natural gas inventories;
- weather conditions;
- technological advances affecting energy consumption; and
- the price and availability of alternative fuels.
Lower oil and natural gas prices may not only decrease our revenues on a
per unit basis but also may reduce the amount of oil and natural gas that we can
produce economically. Lower prices will also negatively impact the value of our
proved reserves. A substantial or extended decline in oil or natural gas prices
may materially and adversely affect our future business, financial condition,
results of operations, liquidity or ability to finance planned capital
expenditures.
A SUBSTANTIAL PERCENTAGE OF OUR PROPERTIES ARE UNPROVEN; THEREFORE THE RISK
ASSOCIATED WITH OUR SUCCESS IS GREATER THAN WOULD BE THE CASE IF THE MAJORITY OF
OUR PROPERTIES WERE CATEGORIZED AS PROVED DEVELOPED PRODUCING.
Because a substantial percentage of our properties are unproven
(approximately 99.0%), or proved undeveloped, we will require significant
additional capital to prove and develop such properties before they may become
productive. Further, because of the inherent uncertainties associated with
drilling for oil and gas, some of these properties may never be developed to the
extent that they result in positive cash flow. Even if we are successful in our
development efforts, it could take several years for a significant portion of
our undeveloped properties to be converted to positive cash flow.
While our current business plan is to fund the development costs with funds
on hand and cash flow from our other producing properties, if such funds are not
sufficient we may be forced to seek alternative sources for cash, through the
issuance of additional equity or debt securities, increased borrowings or other
means.
DRILLING FOR AND PRODUCING OIL AND NATURAL GAS ARE HIGH RISK ACTIVITIES WITH
MANY UNCERTAINTIES THAT COULD ADVERSELY AFFECT OUR BUSINESS, FINANCIAL CONDITION
OR RESULTS OF OPERATIONS.
Our future success will depend on the success of our exploitation,
exploration, development and production activities. Our oil and natural gas
exploration and production activities are subject to numerous risks beyond our
control; including the risk that drilling will not result in commercially viable
oil or natural gas production. Our decisions to purchase, explore, develop or
otherwise exploit prospects or properties will depend in part on the evaluation
of data obtained through geophysical and geological analyses, production data
and engineering studies, the results of which are often inconclusive or subject
to varying interpretations. Please read "-Reserve estimates
10
depend on many assumptions that may turn out to be inaccurate" (below) for a
discussion of the uncertainty involved in these processes. Our cost of drilling,
completing and operating wells is often uncertain before drilling commences.
Overruns in budgeted expenditures are common risks that can make a particular
project uneconomical. Further, many factors may curtail, delay or cancel
drilling, including the following:
- delays imposed by or resulting from compliance with regulatory
requirements;
- pressure or irregularities in geological formations;
- shortages of or delays in obtaining equipment and qualified personnel;
- equipment failures or accidents;
- adverse weather conditions;
- reductions in oil and natural gas prices;
- title problems; and
- limitations in the market for oil and natural gas.
IF OIL AND NATURAL GAS PRICES DECREASE, WE MAY BE REQUIRED TO TAKE WRITE-DOWNS
OF THE CARRYING VALUES OF OUR OIL AND NATURAL GAS PROPERTIES, POTENTIALLY
NEGATIVELY IMPACTING THE TRADING VALUE OF OUR SECURITIES.
Accounting rules require that we review periodically the carrying value of
our oil and natural gas properties for possible impairment. Based on specific
market factors and circumstances at the time of prospective impairment reviews,
and the continuing evaluation of development plans, production data, economics
and other factors, we may be required to write down the carrying value of our
oil and natural gas properties. A write-down could constitute a non-cash charge
to earnings. It is likely the cumulative effect of a write-down could also
negatively impact the trading price of our securities.
RESERVE ESTIMATES DEPEND ON MANY ASSUMPTIONS THAT MAY TURN OUT TO BE INACCURATE.
ANY MATERIAL INACCURACIES IN THESE RESERVE ESTIMATES OR UNDERLYING ASSUMPTIONS
WILL MATERIALLY AFFECT THE QUANTITIES AND PRESENT VALUE OF OUR RESERVES.
The process of estimating oil and natural gas reserves is complex. It
requires interpretations of available technical data and many assumptions,
including assumptions relating to economic factors. Any significant inaccuracies
in these interpretations or assumptions could materially affect the estimated
quantities and present value of reserves shown in this report.
In order to prepare our estimates, we must project production rates and
timing of development expenditures. We must also analyze available geological,
geophysical, production and engineering data. The extent, quality and
reliability of this data can vary. The process also requires economic
assumptions about matters such as oil and natural gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds.
Therefore, estimates of oil and natural gas reserves are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable oil
and natural gas reserves most likely will vary from our estimates. Any
significant variance could materially affect the estimated quantities and
present value of our reserves. In addition, we may adjust estimates of proved
reserves to reflect production history, results of exploration and development,
prevailing oil and natural gas prices and other factors, many of which are
beyond our control.
You should not assume that the present value of future net revenues from
our proved reserves, as reported from time to time, is the current market value
of our estimated oil and natural gas reserves. In accordance with SEC
requirements, we generally base the estimated discounted future net cash flows
from our proved reserves on prices and costs on the date of the estimate. Actual
future prices and costs may differ materially from those used in the present
value estimate. If future values decline or costs increase it could negatively
impact our ability to finance operations, and individual properties could cease
being commercially viable, affecting our decision to continue operations on
producing properties or to attempt to develop properties. All of these factors
would have a negative impact on earnings and net income, and most likely the
trading price of our securities.
11
WE ARE DEPENDENT UPON THIRD PARTY OPERATORS OF OUR OIL AND GAS PROPERTIES.
Under the terms of the Operating Agreements related to our oil and gas
properties, third parties act as the operator of our oil and gas wells and
control the drilling activities to be conducted on our properties. Therefore, we
have limited control over certain decisions related to activities on our
properties, which could affect our results of operations. Decisions over which
we have limited control include:
- the timing and amount of capital expenditures;
- the timing of initiating the drilling and recompleting of wells;
- the extent of operating costs; and
- the level of ongoing production.
PROSPECTS THAT WE DECIDE TO DRILL MAY NOT YIELD OIL OR NATURAL GAS IN
COMMERCIALLY VIABLE QUANTITIES.
Our prospects are properties on which we have identified what we believe,
based on available seismic and geological information, to be indications of oil
or natural gas. Our prospects are in various stages of evaluation, ranging from
a prospect that is ready to drill to a prospect that will require substantial
additional seismic data processing and interpretation. There is no way to
predict in advance of drilling and testing whether any particular prospect will
yield oil or natural gas in sufficient quantities to recover drilling or
completion costs or to be economically viable. This risk may be enhanced in our
situation, due to the fact that a significant percentage (99.0%) of our reserves
are currently unproved reserves. The use of seismic data and other technologies
and the study of producing fields in the same area will not enable us to know
conclusively prior to drilling whether oil or natural gas will be present or, if
present, whether oil or natural gas will be present in commercial quantities. We
cannot assure you that the analogies we draw from available data from other
wells, more fully explored prospects or producing fields will be applicable to
our drilling prospects.
WE MAY INCUR SUBSTANTIAL LOSSES AND BE SUBJECT TO SUBSTANTIAL LIABILITY CLAIMS
AS A RESULT OF OUR OIL AND NATURAL GAS OPERATIONS.
We are not insured against all risks. Losses and liabilities arising from
uninsured and underinsured events could materially and adversely affect our
business, financial condition or results of operations. Our oil and natural gas
exploration and production activities are subject to all of the operating risks
associated with drilling for and producing oil and natural gas, including the
possibility of:
- environmental hazards, such as uncontrollable flows of oil, natural gas,
brine, well fluids, toxic gas or other pollution into the environment,
including groundwater and shoreline contamination;
- abnormally pressured formations;
- mechanical difficulties, such as stuck oil field drilling and service tools
and casing collapse;
- fires and explosions;
- personal injuries and death; and
- natural disasters.
Any of these risks could adversely affect our ability to conduct operations
or result in substantial losses to our company. We may elect not to obtain
insurance if we believe that the cost of available insurance is excessive
relative to the risks presented. In addition, pollution and environmental risks
generally are not fully insurable. If a significant accident or other event
occurs and is not fully covered by insurance, then it could adversely affect us.
WE ARE SUBJECT TO COMPLEX LAWS THAT CAN AFFECT THE COST, MANNER OR FEASIBILITY
OF DOING BUSINESS.
Exploration, development, production and sale of oil and natural gas are
subject to extensive federal, state, local and international regulation. We may
be required to make large expenditures to comply with governmental regulations.
Matters subject to regulation include:
- discharge permits for drilling operations;
- drilling bonds;
- reports concerning operations;
- the spacing of wells;
- unitization and pooling of properties; and
- taxation.
12
Under these laws, we could be liable for personal injuries, property damage
and other damages. Failure to comply with these laws also may result in the
suspension or termination of our operations and subject us to administrative,
civil and criminal penalties. Moreover, these laws could change in ways that
substantially increase our costs. Any such liabilities, penalties, suspensions,
terminations or regulatory changes could materially adversely affect our
financial condition and results of operations.
OUR OPERATIONS MAY INCUR SUBSTANTIAL LIABILITIES TO COMPLY WITH THE
ENVIRONMENTAL LAWS AND REGULATIONS.
Our oil and natural gas operations are subject to stringent federal, state
and local laws and regulations relating to the release or disposal of materials
into the environment or otherwise relating to environmental protection. These
laws and regulations may require the acquisition of a permit before drilling
commences, restrict the types, quantities and concentration of substances that
can be released into the environment in connection with drilling and production
activities, limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas, and impose substantial
liabilities for pollution resulting from our operations. Failure to comply with
these laws and regulations may result in the assessment of administrative, civil
and criminal penalties, incurrence of investigatory or remedial obligations or
the imposition of injunctive relief. Changes in environmental laws and
regulations occur frequently, and any changes that result in more stringent or
costly waste handling, storage, transport, disposal or cleanup requirements
could require us to make significant expenditures to maintain compliance, and
may otherwise have a material adverse effect on our results of operations,
competitive position or financial condition as well as the industry in general.
Under these environmental laws and regulations, we could be held strictly liable
for the removal or remediation of previously released materials or property
contamination regardless of whether we were responsible for the release or if
our operations were standard in the industry at the time they were performed.
OUR OPERATIONS IN COLOMBIA ARE SUBJECT TO RISKS RELATING TO POLITICAL AND
ECONOMIC INSTABILITY.
We currently have interests in multiple oil and gas concessions in Colombia
and anticipate that operations in Colombia will constitute a substantial element
of our strategy going forward. The political climate in Colombia is unstable
and could be subject to radical change over a very short period of time. In the
event of a significant negative change in the political or economic climate in
Colombia, we may be forced to abandon or suspend our operations in Colombia.
UNLESS WE REPLACE OUR OIL AND NATURAL GAS RESERVES, OUR RESERVES AND PRODUCTION
WILL DECLINE, WHICH WOULD ADVERSELY AFFECT OUR CASH FLOWS AND INCOME.
Unless we conduct successful development, exploitation and exploration
activities or acquire properties containing proved reserves, our proved reserves
will decline as those reserves are produced. Producing oil and natural gas
reservoirs generally are characterized by declining production rates that vary
depending upon reservoir characteristics and other factors. Our future oil and
natural gas reserves and production, and, therefore our cash flow and income,
are highly dependent on our success in efficiently developing and exploiting our
current reserves and economically finding or acquiring additional recoverable
reserves. If we are unable to develop, exploit, find or acquire additional
reserves to replace our current and future production, our cash flow and income
will decline as production declines, until our existing properties would be
incapable of sustaining commercial production.
OUR SUCCESS DEPENDS ON OUR MANAGEMENT TEAM AND OTHER KEY PERSONNEL, THE LOSS OF
ANY OF WHOM COULD DISRUPT OUR BUSINESS OPERATIONS.
Our success will depend on our ability to retain John F. Terwilliger, our
principal executive officer, and to attract other experienced management and
non-management employees, including engineers, geoscientists and other technical
and professional staff. We will depend, to a large extent, on the efforts,
technical expertise and continued employment of such personnel and members of
our management team. If members of our management team should resign or we are
unable to attract the necessary personnel, our business operations could be
adversely affected.
13
THE UNAVAILABILITY OR HIGH COST OF DRILLING RIGS, EQUIPMENT, SUPPLIES, PERSONNEL
AND OIL FIELD SERVICES COULD ADVERSELY AFFECT OUR ABILITY TO EXECUTE ON A TIMELY
BASIS OUR EXPLORATION AND DEVELOPMENT PLANS WITHIN OUR BUDGET.
Shortages or the high cost of drilling rigs, equipment, supplies or
personnel could delay or adversely affect our development and exploration
operations. As the price of oil and natural gas increases, the demand for
production equipment and personnel will likely also increase, potentially
resulting, at least in the near-term, in shortages of equipment and personnel.
In addition, larger producers may be more likely to secure access to such
equipment by virtue of offering drilling companies more lucrative terms. If we
are unable to acquire access to such resources, or can obtain access only at
higher prices, not only would this potentially delay our ability to convert our
reserves into cash flow, but could also significantly increase the cost of
producing those reserves, thereby negatively impacting anticipated net income.
IF OUR ACCESS TO MARKETS IS RESTRICTED, IT COULD NEGATIVELY IMPACT OUR
PRODUCTION, OUR INCOME AND ULTIMATELY OUR ABILITY TO RETAIN OUR LEASES.
Market conditions or the unavailability of satisfactory oil and natural gas
transportation arrangements may hinder our access to oil and natural gas markets
or delay our production. The availability of a ready market for our oil and
natural gas production depends on a number of factors, including the demand for
and supply of oil and natural gas and the proximity of reserves to pipelines and
terminal facilities. Our ability to market our production depends in substantial
part on the availability and capacity of gathering systems, pipelines and
processing facilities owned and operated by third parties. Our failure to obtain
such services on acceptable terms could materially harm our business.
We may operate in areas with limited or no access to pipelines, thereby
necessitating delivery by other means, such as trucking, or requiring
compression facilities. Such restrictions on our ability to sell our oil or
natural gas have several adverse affects, including higher transportation costs,
fewer potential purchasers (thereby potentially resulting in a lower selling
price) or, in the event we were unable to market and sustain production from a
particular lease for an extended time, possibly causing us to lose a lease due
to lack of production.
WE MAY NEED ADDITIONAL FINANCING TO SUPPORT OPERATIONS AND FUTURE CAPITAL
COMMITMENTS.
While we presently believe that our operating cash flows and funds on hand
will support our ongoing operations and anticipated future capital requirements,
a number of factors could result in our needing additional financing, including
reductions in oil and natural gas prices, declines in production, unexpected
developments in operations that could decrease our revenues, increase our costs
or require additional capital contributions and commitments to new acquisition
or drilling programs. We have no commitments to provide any additional
financing, if needed, and may be limited in our ability to obtain the capital
necessary to support operations, complete development, exploitation and
exploration programs or carry out new acquisition or drilling programs. We have
not thoroughly investigated whether this capital would be available, who would
provide it, and on what terms. If we are unable, on acceptable terms, to raise
the required capital, our business may be seriously harmed or even terminated.
COMPETITION IN THE OIL AND NATURAL GAS INDUSTRY IS INTENSE, WHICH MAY ADVERSELY
AFFECT OUR ABILITY TO COMPETE.
We operate in a highly competitive environment for acquiring properties,
marketing oil and natural gas and securing trained personnel. Many of our
competitors possess and employ financial, technical and personnel resources
substantially greater than ours, which can be particularly important in the
areas in which we operate. Those companies may be able to pay more for
productive oil and natural gas properties and exploratory prospects and to
evaluate, bid for and purchase a greater number of properties and prospects than
our financial or personnel resources permit. Our ability to acquire additional
prospects and to find and develop reserves in the future will depend on our
ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. Also, there is substantial
competition for capital available for investment in the oil and natural gas
industry. We may not be able to compete successfully in the future in acquiring
prospective reserves, developing reserves, marketing hydrocarbons, attracting
and retaining quality personnel and raising additional capital.
14
THE PRICE OF OUR COMMON STOCK MAY FLUCTUATE SIGNIFICANTLY, AND THIS MAY MAKE IT
DIFFICULT FOR YOU TO RESELL COMMON STOCK WHEN YOU WANT OR AT PRICES YOU FIND
ATTRACTIVE.
The price of our common stock constantly changes. We expect that the market
price of our common stock will continue to fluctuate.
Our stock price may fluctuate as a result of a variety of factors, many of
which are beyond our control. These factors include:
- quarterly variations in our operating results;
- operating results that vary from the expectations of management,
securities analysts and investors;
- changes in expectations as to our future financial performance;
- announcements by us, our partners or our competitors of leasing and
drilling activities;
- the operating and securities price performance of other companies that
investors believe are comparable to us;
- future sales of our equity or equity-related securities;
- changes in general conditions in our industry and in the economy, the
financial markets and the domestic or international political
situation;
- fluctuations in oil and gas prices;
- departures of key personnel; and
- regulatory considerations.
In addition, in recent years, the stock market in general has experienced
extreme price and volume fluctuations. This volatility has had a significant
effect on the market price of securities issued by many companies for reasons
often unrelated to their operating performance. These broad market fluctuations
may adversely affect our stock price, regardless of our operating results.
THE SALE OF A SUBSTANTIAL NUMBER OF SHARES OF OUR COMMON STOCK MAY AFFECT OUR
STOCK PRICE.
Future sales of substantial amounts of our common stock or equity-related
securities in the public market or privately, or the perception that such sales
could occur, could adversely affect prevailing trading prices of our common
stock and could impair our ability to raise capital through future offerings of
equity or equity-related securities. No prediction can be made as to the
effect, if any, that future sales of shares of common stock or the availability
of shares of common stock for future sale will have on the trading price of our
common stock.
OUR CHARTER AND BYLAWS, AS WELL AS PROVISIONS OF DELAWARE LAW, COULD MAKE IT
DIFFICULT FOR A THIRD PARTY TO ACQUIRE OUR COMPANY AND ALSO COULD LIMIT THE
PRICE THAT INVESTORS ARE WILLING TO PAY IN THE FUTURE FOR SHARES OF OUR COMMON
STOCK.
Delaware corporate law and our charter and bylaws contain provisions that
could delay, deter or prevent a change in control of our company or our
management. These provisions could also discourage proxy contests and make it
more difficult for our stockholders to elect directors and take other corporate
actions without the concurrence of our management or board of directors. These
provisions:
- authorize our board of directors to issue "blank check" preferred
stock, which is preferred stock that can be created and issued by our
board of directors, without stockholder approval, with rights senior
to those of our common stock;
- provide for a staggered board of directors and three-year terms for
directors, so that no more than one-third of our directors could be
replaced at any annual meeting;
- provide that directors may be removed only for cause; and
- establish advance notice requirements for submitting nominations for
election to the board of directors and for proposing matters that can
be acted upon by stockholders at a meeting.
15
We are also subject to anti-takeover provisions under Delaware law, which
could also delay or prevent a change of control. Taken together, these
provisions of our charter and bylaws, Delaware law may discourage transactions
that otherwise could provide for the payment of a premium over prevailing market
prices of our common stock and also could limit the price that investors are
willing to pay in the future for shares of our common stock.
OUR MANAGEMENT OWNS A SIGNIFICANT AMOUNT OF OUR COMMON STOCK, GIVING THEM
INFLUENCE OR CONTROL IN CORPORATE TRANSACTIONS AND OTHER MATTERS, AND THEIR
INTERESTS COULD DIFFER FROM THOSE OF OTHER SHAREHOLDERS.
At March 1, 2007, our directors and executive officers owned approximately
46.6 percent of our outstanding common stock. As a result, our current
directors and executive officer are in a position to significantly influence or
control the outcome of matters requiring a shareholder vote, including the
election of directors, the adoption of any amendment to our certificate of
incorporation or bylaws, and the approval of mergers and other significant
corporate transactions. Such level of control of the company may delay or
prevent a change of control on terms favorable to the other shareholders and may
adversely affect the voting and other rights of other shareholders.
EMPLOYEES
As of March 1, 2007, we had 2 full-time employees and no part time employees.
The employees are not covered by a collective bargaining agreement, and we do
not anticipate that any of our future employees will be covered by such
agreements.
ITEM 2. DESCRIPTION OF PROPERTY
We currently lease approximately 4,739 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 average monthly rental under the
lease, which expires on May 31, 2012, is $6,682.
A description of our interests in oil and gas properties is included in "Item 1.
Description of Business."
ITEM 3. LEGAL PROCEEDINGS
We may from time to time be a party to lawsuits incidental to our business. As
of March 1, 2007, we were not aware of any current, pending, or threatened
litigation or proceedings that could have a material adverse effect on our
results of operations, cash flows or financial condition.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
16
PART II
ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our Common Stock is listed on the American Stock Exchange ("AMEX") under the
symbol "HGO." Previously, until July 28, 2006, our Common Stock traded on the
over-the-counter electronic bulletin board ("OTCBB") under the symbol "HUSA".
The following table sets forth the range of high and low sale prices on AMEX,
and bid prices on OTCBB, for each quarter during the past two fiscal years.
High Low
----- -----
Calendar Year 2006
Fourth Quarter . . . . . $7.95 $2.28
Third Quarter. . . . . . 3.25 2.25
Second Quarter . . . . . 4.94 2.90
First Quarter. . . . . . 3.85 2.95
Calendar Year 2005
Fourth Quarter . . . . . $3.50 $2.65
Third Quarter. . . . . . 2.75 1.00
Second Quarter . . . . . 1.25 0.76
First Quarter. . . . . . 1.00 0.78
With respect to bid prices for periods prior to July 28, 2006, the quotations
reflect inter-dealer prices without retail mark-up, mark-down or commission and
may not represent actual transactions.
At February 15, 2007, the closing price of the Common Stock on AMEX was $4.41.
As of February 15, 2007, there were approximately 2,059 record holders of our
Common Stock.
We have not paid any cash dividends since inception and presently anticipate
that all earnings, if any, will be retained for development of our business and
that no dividends on our common stock will be declared in the foreseeable
future. Any future dividends will be subject to the discretion of our Board of
Directors and will depend upon, among other things, future earnings, operating
and financial condition, capital requirements, general business conditions and
other pertinent facts. Therefore, there can be no assurance that any dividends
on our common stock will be paid in the future.
The following table provides information as of December 31, 2006 with respect to
the shares of our common stock that may be issued under our existing equity
compensation plans.
NUMBER OF SECURITIES
REMAINING AVAILABLE FOR
WEIGHTED-AVERAGE FUTURE ISSUANCE UNDER
NUMBER OF SECURITIES TO EXERCISE PRICE OF EQUITY COMPENSATION
BE ISSUED UPON EXERCISE OUTSTANDING PLANS (EXCLUDING
OF OUTSTANDING OPTIONS, OPTIONS, WARRANTS SECURITIES REFLECTED IN
PLAN CATEGORY WARRANTS AND RIGHTS (a) AND RIGHTS (b) COLUMN (a))
-------------------------------- ------------------------ ------------------ ------------------------
Equity compensation plans
approved by security holders (1) 309,000 2.89 191,000
Equity compensation plans not
approved by security holders - NA -
------------------------ ------------------ ------------------------
Total 309,000 2.89 191,000
======================== ================== ========================
(1) Consists of shares reserved for issuance under the Houston American Energy
Corp. 2005 Stock Option Plan pursuant to which 500,000 shares were
reserved. The plan was adopted by the board of directors in August 2005 and
approved by shareholders in January 2006.
17
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 founder and principal 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, our 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 2006
Drilling Activities
During 2006, we drilled 3 on-shore domestic wells as follows:
- A 7,100 -foot well on the Obenhaus Prospect in Wilbarger County, Texas was
drilled and was a dry hole.
- A 6,400-foot test well on the West Fargo Prospect in Wilbarger County,
Texas was drilled and was deemed non-commercial.
- The DDD-Evans#1, a 8,500-foot test well on the West Turkey Prospect in
Hardeman County, Texas, was completed in April 2006 and began production in
May 2006. At December 31, 2006, the DDD-Evans#1 was producing but at
non-commercial levels.
At December 31, 2006, we had no domestic wells being drilled.
During 2006, we drilled 14 international wells in Colombia as follows:
- 8 wells were drilled on the Cara Cara Concession, in which we hold a 1.6%
working interest, of which 7 were in production at December 31, 2006 and 1
was a dry hole.
- 1 dry hole was drilled on the Dorotea Concession, in which we hold a 12.5%
working interest.
- 4 wells were drilled on the Cabiona Concession, in which we hold a 12.5%
working interest, of which 2 were in production at December 31, 2006 and 2
were dry holes.
18
At December 31, 2006, we had 1 well being drilled in Colombia.
Leasehold Activities
During 2006, we acquired interests in an additional domestic prospect, a 10%
working interest with a 7.5% net revenue interest in the 91.375 acre West Turkey
Prospect in Hardeman County, Texas.
During 2006 we terminated our interest in the Green Jacket Prospect in Iberville
Parish, Louisiana.
During 2006, as a result of seismic evaluation, the Jagueyes TEA covering
approximately 324,695 acres was converted to the Leona concession covering
approximately 70,343 acres and the Simon TEA covering 166,301 acres was
converted to the Camarita concession covering 166,301 acres.
Seismic Activity
During 2006, we continued our ongoing investment in acquiring and developing
seismic data with respect to our Colombian properties with shooting being
completed on approximately 133 square miles of prospect acreage during the
period.
Capital Raising Activity
In April 2006, we sold, in a private placement, 5,533,333 shares of common stock
for gross proceeds of $16,599,999. In connection with the private placement of
shares, we paid to the placement agent commissions of $1,162,000 and issued to
the placement agent five year warrants to purchase 415,000 shares of common
stock at $3.00 per share. In December 2006, in connection with the April 2006
private placement, Sanders Morris Harris exercised 100,000 of the 415,000
Placement Agent Warrants, and Sanders Morris Harris was issued 100,000 shares
for an aggregate consideration of $300,000.
In May 2006, we repaid loans from our principal shareholder, in the principal
amount of $900,000, from the proceeds of the April 2006 private placement.
In May 2006, we exercised our right to cause our outstanding Subordinated
Convertible Notes, in the aggregate principal amount of $2,125,000, to be
converted into 2,125,000 shares of common stock.
In May 2006, the holders of $1.00 warrants issued in connection with the
Subordinated Convertible Notes exercised all of the warrants resulting in the
issuance of 191,250 shares of common stock for aggregate consideration of
$191,250.
Corporate Developments
During May 2006, our board of directors appointed an additional non-employee
director and revised the compensation of our President and non-employee
directors. Effective June 1, 2006, the base salary of our President was
increased from $180,000 to $300,000 annually. The board fixed the compensation
of non-employee directors to consist of (1) an annual retainer of $6,000 payable
in quarterly installments, (2) an annual retainer of $2,000 per committee on
which a director serves, payable in quarterly installments, (3) an annual
retainer of $2,500 for service as audit committee chair, payable in quarterly
installments, (4) an annual retainer of $1,500 for service as chair of
committees other than the audit committee, payable in quarterly installments,
(5) a grant of 20,000 stock options on initial election or appointment as a
director exercisable at fair market value on the date of grant for a term of 10
years, and (6) a grant of 10,000 stock options immediately following each
subsequent shareholders meeting at which a director stands for reelection and is
reelected.
In July 2006, we appointed James "Jay" Jacobs as Chief Financial Officer and
fixed Mr. Jacobs' compensation, subject to review and adjustment by mid-2007, as
follows: (1) base salary of $125,000; and (2) a stock option to purchase
200,000 shares of common stock at $2.98 per share, the closing price on first
day of employment, vesting over a 2 year period and exercisable over a period of
ten years.
19
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, 2006. 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, 2006 and 2005:
At December 31, 2005 At December 31, 2006
--------------------- ---------------------
Acquisition costs $ 44,548 $ 180,197
Evaluation costs 151,346 520,352
--------------------- ---------------------
Total $ 195,894 $ 700,549
===================== =====================
The carrying value of unevaluated oil and gas prospects includes $151,039 and
$480,532 expended for properties in South America at December 31, 2005 and
December 31, 2006, respectively. We are maintaining our interest in these
properties and development has or is anticipated to commence within the next
twelve months.
Subordinated Convertible Notes and Warrants - Derivative Financial Instruments.
The Subordinated Convertible Notes and Warrants issued during 2005 have been
accounted for in accordance with SFAS 133 and EITF No. 00-19, "Accounting for
Derivative Financial Instruments Indexed to, and Potentially Settled in, a
Company's Own Stock."
20
The Company identified the following instruments and derivatives requiring
evaluation and accounting under the relevant guidance applicable to financial
derivatives:
- Subordinated Convertible Notes
- Conversion feature
- Conversion price reset feature
- Company's optional redemption right
- Warrants
- Warrants exercise price reset feature
The Company identified the conversion feature; the conversion price reset
feature and the Company's optional early redemption right within the Convertible
Notes to represent embedded derivatives. These embedded derivatives were
bifurcated from their respective host debt contracts and accounted for as
derivative liabilities in accordance with EITF 00-19. The conversion feature,
the conversion price reset feature and the Company's optional early redemption
right within the Convertible Notes were bundled together as a single hybrid
compound instrument in accordance with SFAS No. 133 Derivatives Implementation
Group Implementation Issue No. B-15, "Embedded Derivatives: Separate Accounting
for Multiple Derivative Features Embedded in a Single Hybrid Instrument."
The Company identified the common stock warrant to be a detachable derivative.
The warrant exercise price reset provision is an embedded derivative within the
common stock warrant. The common stock warrant and the embedded warrant
exercise price reset provision were accounted for as a separate single hybrid
compound instrument.
The single compound embedded derivatives within Subordinated Convertible Notes
and the derivative liability for Warrants were recorded at fair value at the
date of issuance (May 4, 2005); and were marked-to-market each quarter with
changes in fair value recorded to the Company's income statement as "Net change
in fair value of derivative liabilities." The Company utilized a third party
valuation firm to fair value the single compound embedded derivatives under the
following methods: a layered discounted probability-weighted cash flow approach
for the single compound embedded derivatives within Subordinated Convertible
Notes; and the Black-Scholes model for the derivative liability for Warrants
based on a probability weighted exercise price.
The fair value of the derivative liabilities were subject to the changes in the
trading value of the Company's common stock. As a result, the Company's
financial statements were subject to fluctuations from quarter-to-quarter based
on factors, such as the price of the Company's stock at the balance sheet date,
the amount of shares converted by note holders and/or exercised by warrant
holders. Consequently, our financial position and results of operations varied
from quarter-to-quarter based on conditions other than our operating revenues
and expenses.
In May 2006, each of the Subordinated Convertible Notes and Warrants accounted
for as derivative financial instruments was converted or exercised. Accordingly,
for subsequent periods, we have no derivative financial instruments requiring
account under SFAS 133.
Stock-Based Compensation. We account for stock-based compensation in accordance
with the provisions of SFAS 123(R). We use the Black-Scholes option-pricing
model, which requires the input of highly subjective assumptions. These
assumptions include estimating the volatility of the Company's common stock
price over the vesting term, dividend yield, an appropriate risk-free interest
rate and the number of options that will ultimately not complete their vesting
requirements ("forfeitures"). Changes in the subjective assumptions can
materially affect the estimated fair value of stock-based compensation and
consequently, the related amount recognized on the Statements of Operations.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2006 COMPARED TO YEAR ENDED DECEMBER 31, 2005
Oil and Gas Revenues. Total oil and gas revenues increased $422,274, or 15.2%,
to $3,202,731 in fiscal 2006 compared to $2,780,457 in fiscal 2005. The
increase in revenue is due to (a) increased production resulting from the
development of the Colombian fields and (b) increases in oil prices, partially
offset by (y) decreased domestic natural gas production and (z) decreases in
natural gas prices. We had interests in 22 producing wells in Colombia
21
and 11 producing wells in North America during 2006 as compared to 17 producing
wells in Colombia and 14 producing wells in North America during 2005. Average
prices from sales were $55.55 per barrel of oil and $6.75 per mcf of gas during
2006 as compared to $47.89 per barrel of oil and $7.83 per mcf of gas during
2005. Following is a summary comparison, by region, of oil and gas sales for
the periods.
Colombia North America Total
---------- -------------- ----------
Year ended 2006
Oil sales $2,565,105 $ 95,363 $2,660,468
Gas sales 0 542,263 542,263
Year ended 2005
Oil sales $2,041,072 $ 75,115 $2,116,187
Gas sales 0 664,270 664,270
Consulting Revenues. The Company generated a one-time commission of $60,000 in
2005. No similar commissions were received in 2006.
Lease Operating Expenses. Lease operating expenses, excluding joint venture
expenses relating to our Colombia operations discussed below, increased 18% to
$1,017,440 in 2006 from $861,790 in 2005. The increase in lease operating
expenses was attributable to the increase in the number of wells operated during
2006 (33 wells as compared to 31 wells) partially offset by improved operating
efficiencies. Following is a summary comparison of lease operating expenses for
the years ended December 31, 2006 and 2005.
Colombia North America Total
--------- -------------- ----------
Year ended 2006 $ 819,273 $ 198,167 $1,017,440
Year ended 2005 782,248 79,542 861,790
Joint Venture Expenses. Joint venture expenses totaled $167,023 in 2006
compared to $61,500 in 2005. The joint venture expenses represent our allocable
share of the indirect field operating and region administrative expenses billed
by the operator of the Colombian concessions. The increase in joint venture
expenses was attributable to increased activities associated with acquiring new
concessions in Colombia.
Depreciation and Depletion Expense. Depreciation and depletion expense
increased by 144.5% to $887,911 in fiscal 2006 when compared to $363,196 in
2005. The increase in depreciation and depletion expense was primarily
attributable to the increased production from new wells coming on line during
2005 and 2006 and a reduction in proved reserves located in North America.
General and Administrative Expenses. General and administrative expense
increased by 47.3% to $1,231,079 during 2006 from $835,829 in 2005. The
increase in general and administrative expense was primarily attributable to (1)
compensation expense relating to the grant of stock options to a new director
and a new officer ($289,755), (2) an increase in officers salary and director
compensation relating to the hiring of a new officer, increase in the salary of
the Company's President and the payment of director fees ($168,410), (3) an
increase in travel and entertainment expense ($26,635), and (4) transfer agent
fees and fees relating to the listing of the Company's stock on the American
Stock Exchange ($88,611), partially offset by a reduction of legal and
professional fees of $155,153.
Other Income/Expense, Net. Other income/expense, net, consists of interest
income, net of financing costs in the nature of interest and deemed interest
associated with outstanding shareholder loans and convertible notes and warrants
issued in May 2005. Certain features of the convertible notes and warrants
resulted in the recording of a deemed derivative liability on the balance sheet
and periodic interest associated with the deemed derivative liabilities and
changes in the fair market value of those deemed liabilities.
Other income/expenses, net, totaled $99,263 of net income in 2006 compared to
$888,887 of net expenses in 2005. The improvement in other income/expense, net,
was attributable to interest earned on funds received from the 2006 private
placement, reduced interest on shareholder debt, derivative interest expense,
interest expense on convertible notes net changes in fair value of derivatives
partially offset by increases in financing costs, which charges primarily
related to retirement of the convertible notes and warrants. As a result of the
retirement of the shareholder loan and the convertible notes, the Company had no
substantial debt at December 31, 2006 and, accordingly, the Company will no
longer incur interest or derivative related charges associated with the loans,
notes and warrants.
22
Income Tax Expense. Income tax expense increased to $510,637 in 2006 from
$331,035 in 2005. The increase in income tax expense during 2006 is
attributable to the Company's estimated allocable share of Colombian income tax
relating to its interest in its Colombian venture. The Company recorded no U.S.
income tax liability in 2006 or 2005 and at December 31, 2006 had net operating
losses of approximately $195,696 and foreign tax credits of approximately
$842,000.
Operating and Net Income (Loss). Operating loss for 2006 totaled $(100,722) as
compared to operating income of $718,142 in 2005. Net loss totaled $512,096 in
fiscal 2006 as compared to net loss of $501,780 in 2005.
FINANCIAL CONDITION
Liquidity and Capital Resources. At December 31, 2006, we had a cash and cash
equivalent of $409,008 and working capital of $14,314,190 compared to a cash
balance of $1,724,100 and working capital of $1,771,772 at December 31, 2005.
The increase in working capital during the period was primarily attributable to
the receipt of $15,386,583 of net proceeds from the April 2006 private placement
of common stock as well as the receipt of $491,250 from the exercise of
warrants, partially offset by acquisitions of, and investments in, oil and gas
properties and the retirement of $900,000 of shareholder loans.
Derivative liabilities are $0 at December 31, 2006 as compared to $2,813,175 at
December 31, 2005 but are not considered in computing working capital. The
decrease in derivative liabilities was attributable to the conversion, during
2006, of the convertible notes and warrants into common stock and the
accompanying reclassification of the derivative liability in the amount of
$2,984,124 to additional paid in capital. The derivative liabilities
represented the deemed fair value of the embedded derivatives included in the
subordinated convertible notes and accompanying warrants that were issued during
2005 as measured at December 31, 2006 and December 31, 2005.
Cash Flows. Operating cash flows for 2006 totaled $1,239,446 as compared to
$694,581 during 2005. The increase in operating cash flow was primarily
attributable to increased oil and gas revenue and a decrease in receivables.
Investing activities used $17,507,371 during 2006 as compared to $1,589,594 used
during 2005. The increase in funds used in investing activities was primarily
attributable to a net investment in short-term marketable securities of
$14,000,000 and an increase in investments in lease acquisition, seismic
evaluation and drilling activities of $1,917,777.
Financing activities provided $14,952,833 during 2006 as compared to $1,897,500
provided during 2005. Cash flows from financing activities during 2006 related
to the private placement of common stock resulting in the receipt of net
proceeds of $15,361,583 and the receipt of $491,250 from the exercise of
warrants partially offset by the repayment of shareholder loans of $900,000.
Cash flows from financing activities during 2005 related to the private
placement of Subordinated Convertible Notes in the amount of $2,125,000
partially offset by a reduction in shareholder loans of $100,000.
Long-Term Liabilities. At December 31, 2006, we had long-term liabilities of
$38,816 as compared to $975,416 at December 31, 2005. Long-term liabilities at
December 31, 2006 consisted of a reserve for plugging costs. The change in
long-term debt was attributable to the retirement of shareholder loans of
$900,000 and the conversion of convertible notes into common stock.
Capital and Exploration Expenditures and Commitments. Our principal capital and
exploration expenditures relate to our ongoing efforts to acquire, drill and
complete prospects. With the receipt of additional financing in 2006 and prior
years, and the increase in our revenues, profitability and operating cash flows,
we expect that future capital and exploration expenditures will be funded
principally through funds on hand and funds generated from operations.
During 2006, we invested $3,507,371 for the acquisition and development of oil
and gas properties, primarily consisting of (1) drilling of 3 domestic wells
($361,392), (2) drilling 14 wells in Colombia ($1,872,179), and (3) seismic
activity in Colombia ($655,208).
At December 31, 2006, our only material contractual obligation requiring
determinable future payments on our part was our lease relating to our executive
offices.
23
The following table details our contractual obligations as of December 31, 2006:
Payments due by period
----------------------------------------------------------
Total 2007 2008 - 2009 2010 - 2011 Thereafter
-------- ------- ------------ ------------ -----------
Operating leases $420,996 $51,946 $ 161,521 $ 170,999 $ 36,530
-------- ------- ------------ ------------ -----------
Total $420,996 $51,946 $ 161,521 $ 170,999 $ 36,530
======== ======= ============ ============ ===========
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.
2007 Planned Drilling, Leasehold and Other Activities. As of December 31, 2006,
we planned to drill a total of 31 wells during 2007, of which 1 well is planned
to be drilled on our domestic exploration projects and 30 wells are planned to
be drilled on our Colombian exploration projects. The following table reflects
planned drilling activities during 2007:
Location Prospect Name # of Planned Wells
---------------------- --------------------- ------------------
Acadia Parish, LA Baronet #3 1
Llanos Basin, Colombia Cara Cara Concession 13
Llanos Basin, Colombia Dorotea Concession 1
Llanos Basin, Colombia Cabiona Concession 8
Llanos Basin, Colombia Las Garzas Concession 2
Llanos Basin, Colombia Leona Concession 2
Llanos Basin, Colombia Camarita Concession 4
Our planned drilling activity is subject to change from time to time without
notice.
We also plan to continue our investments in seismic to further delineate our
Colombian properties and plan to selectively evaluate and acquire interests in
additional drilling prospects.
At December 31, 2006, our acquisition and drilling budget for 2007 totaled
approximately $6,806,500, consisting of (1) $5,728,500 for drilling of 30 wells
in Colombia, (2) $945,000 for drilling of 1 domestic well, and (3) $133,000 for
seismic in Colombia. Our acquisition and drilling budget has historically been
subject to substantial fluctuation over the course of a year based upon
successes and failures in drilling and completion of prospects and the
identification of additional prospects during the course of a year.
Management anticipates that our current financial resources combined with our
increases in revenues over the past year will meet our anticipated objectives
and business operations, including our planned property acquisitions and
drilling activities, for at least the next 12 months without the need for
additional capital. Management continues to evaluate producing property
acquisitions as well as a number of drilling prospects. It is possible,
although not anticipated, that the Company may require and seek additional
financing if additional drilling prospects are pursued beyond those presently
under consideration.
OFF-BALANCE SHEET ARRANGEMENTS
We had no off-balance sheet arrangements or guarantees of third party
obligations at December 31, 2006.
24
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 accountant's 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 30 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") and chief financial officer ("CFO"). Based on this
evaluation, our management, including the CEO and CFO, concluded that our
disclosure controls and procedures were not effective at December 31, 2006.
During the year ended December 31, 2006, there were no changes in our internal
controls over financial reporting that materially affected, or are reasonably
likely to materially affect, internal controls over financial reporting.
In connection with the quarterly reviews and audit for the year ended December
31, 2006, 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 identified consisted of a lack of certain procedures to properly
account for non-routine transactions and preparation of certain financial
statement disclosures in accordance with U.S. GAAP. Additionally, the
independent registered public accounting firm identified, during its reviews
certain closing and adjusting entries that had not been made prior to the
reviews.
In addition to the weaknesses identified by our independent registered public
accounting firm, management notes that the Company continues to lack adequate
segregation of duties in our financial reporting process, as our CFO serves as
our only internal accounting and financial reporting personnel and, as such,
performs substantially all accounting and financial reporting functions with the
assistance of a part-time consultant. Accordingly, the preparation of financial
statements and the related monitoring controls surrounding this process were not
segregated.
The Company hired a full time CFO during 2006 and, under the direction of our
CFO, we plan to increase our emphasis on identification of, and accounting for,
non-routine transactions, in particular SFAS 123R accounting, and timely
preparation of closing and adjusting entries. Our CFO is also working with
outside consultants to assess the overall functioning of our controls and our
control environment and establish and implement appropriate additional controls.
The Company has no current plans, however, to add accounting or financial
reporting personnel and, accordingly, expects to continue to lack segregation of
accounting, financial reporting and oversight functions. As operations increase
in scope, the Company intends to evaluate hiring additional in-house accounting
personnel so as to provide for appropriate segregation of duties within the
accounting function.
ITEM 8B. OTHER INFORMATION
NA
25
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS;
COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT
The information required by this Item will be included in a definitive proxy
statement, pursuant to Regulation 14A, to be filed not later than 120 days after
the close of our fiscal year. Such information is incorporated herein by
reference.
EXECUTIVE OFFICERS
Our executive officers as of December 31, 2006, and their ages and positions as
of that date, are as follows:
Name Age Position
---------------- --- -----------------------------------------------
John Terwilliger 59 President, Chief Executive Officer and Chairman
Jay Jacobs 29 Chief Financial Officer
John F. Terwilliger has served as our President, CEO and Chairman 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. 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.
Jay Jacobs has served as our Chief Financial Officer since July 2006. From
April 2003 until joining the Company, Mr. Jacobs served as an Associate and as
Vice President - Energy Investment Banking at Sanders Morris Harris, Inc., an
investment banking firm, where he specialized in energy sector financing and
transactions. Previously, Mr. Jacobs was an Energy Finance Analyst at Duke
Capital Partners, LLC from June 2001 to April 2003 and a Tax Consultant at
Deloitte & Touch , LLP. Mr. Jacobs holds a Masters of Professional Accounting
from the University of Texas and is a Certified Public Accountant.
There are no family relationships among the executive officers and directors.
Except as otherwise provided in employment agreements, each of the executive
officers serves at the discretion of the Board.
ITEM 10. EXECUTIVE COMPENSATION
The information required by this Item will be included in a definitive proxy
statement, pursuant to Regulation 14A, to be filed not later than 120 days after
the close of our fiscal year. Such information is incorporated herein by
reference.
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The information required by this Item will be included in a definitive proxy
statement, pursuant to Regulation 14A, to be filed not later than 120 days after
the close of our fiscal year. Such information is incorporated herein by
reference.
Equity compensation plan information is set forth in Part II, Item 5 of this
Form 10-KSB.
26
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item will be included in a definitive proxy
statement, pursuant to Regulation 14A, to be filed not later than 120 days after
the close of our fiscal year. Such information is incorporated herein by
reference.
ITEM 13. EXHIBITS
Exhibit
Number Description of Exhibit
------- ----------------------
3.1 Certificate of Incorporation of Houston American Energy Corp. filed April 2, 2001
(incorporated by reference to Exhibit 3.1 to the Registration Statement on Form SB-2,
registration number 333-66638 (the "2001 Registration Statement"), filed with the SEC
on August 3, 2001).
3.2 Bylaws of Houston American Energy Corp. adopted April 2, 2001 (incorporated by
reference to Exhibit 3.3 to the 2001 Registration Statement filed with the SEC on
August 3, 2001).
3.3 Certificate of Amendment to the Certificate of Incorporation of Houston American
Energy Corp. filed September 25, 2001 (incorporated by reference to Exhibit 3.4 to
Amendment No. 1 to the 2001 Registration Statement filed with the SEC on
October 1, 2001).
4.1 Text of Common Stock Certificate of Houston American Energy Corp. (incorporated by
reference to Exhibit 4.1 to the 2001 Registration Statement filed with the SEC on
August 3, 2001).
10.1 Promissory Note of Houston American Energy Corp. in the amount of $390,000 dated
July 2, 2001, payable to John F. Terwilliger (incorporated by reference to Exhibit 10.11
to Amendment No. 4 to the 2001 Registration Statement filed with the SEC on
November 21, 2001).
10.2 Promissory Note of Houston American Energy Corp. in the amount of $285,000 dated
July 30, 2001, payable to John F. Terwilliger (incorporated by reference to Exhibit 10.12
to Amendment No. 4 to the 2001 Registration Statement filed with the SEC on
November 21, 2001).
10.3 Promissory Note, dated December 10, 2003, payable to John Terwilliger in the amount
of $724,658.67 (incorporated by reference to Exhibit 10.25 to the 2004 Registration
Statement).
10.4 Promissory Note, dated December 10, 2003, payable to John Terwilliger in the amount
of $275,341.33 (incorporated by reference to Exhibit 10.26 to the 2004 Registration
Statement).
10.5 Form of Purchase Agreement, dated May 4, 2005 relating to the sale of 8% Subordinated
Convertible Notes due 2010 (incorporated by reference to Exhibit 10.1 to the Current
Report on Form 8-K dated May 4, 2005 (the "May 2005 Form 8-K"), filed with the SEC
on May 10, 2005).
10.6 Form of 8% Subordinated Convertible Note due 2010, dated May 4, 2005 (incorporated
by reference to Exhibit 4.1 to the May 2005 Form 8-K).
10.7 Form of Placement Agent Warrant, dated May 4, 2005 (incorporated by reference to
Exhibit 4.2 to the May 2005 Form 8-K).
27
10.8 Form of Registration Rights Agreement, dated May 4, 2005 (incorporated by reference
to Exhibit 4.3 to the May 2005 Form 8-K).
10.9 Houston American Energy Corp. 2005 Stock Option Plan (incorporated by reference to
Exhibit 10.1 to the Current Report on Form 8-K dated August 12, 2005 (the "August
2005 Form 8-K"), filed with the SEC on August 16, 2005).
10.10 Form of Director Stock Option Agreement (incorporated by reference to Exhibit 10.2 to
the August 2005 Form 8-K).
10.11 Form of Placement Agent Warrant, dated April 28, 2006 (incorporated by reference to
Exhibit 4.1 to the Current Report on Form 8-K dated April 28, 2006 (the "April 28, 2006
Form 8-K"), filed with the SEC on April 28, 2006).
10.12 Form of Registration Rights Agreement, dated April 28, 2006 (incorporated by reference
to Exhibit 4.2 to the April 28, 2006 Form 8-K).
10.13 Form of Subscription Agreement, dated April 2006 relating to the sale of shares of
common stock (incorporated by reference to Exhibit 10.1 to the April 28, 2006 Form 8-K).
10.14 Form of Lock-Up Agreement, dated April 2006 (incorporated by reference to Exhibit
10.2 to the April 28, 2006 Form 8-K).
14.1 Code of Ethics for CEO and Senior Financial Officers (incorporated by reference to
Exhibit 14.1 to the 2003 Form 10-KSB)
23.1* Consent of Thomas Leger & Co. L.L.P.
31.1* Section 302 Certification of CEO
31.2* Section 302 Certification of CFO
32.1* Section 906 Certification of CEO
32.2* Section 906 Certification of CFO
99.1 Code of Business Ethics (incorporated by reference to Exhibit 99.1 to the Current Report
on Form 8-K dated July 6, 2006, filed with the SEC on July 7, 2006).
* Filed herewith.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item will be included in a definitive
proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days
after the close of our fiscal year. Such information is incorporated herein by
reference.
28
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 28, 2007
By: /s/ John F. Terwilliger
--------------------------------
John F. Terwilliger
President
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
Signature Title Date
-------------------------- ----------------------------------- --------------
/s/ John F. Terwilliger Chairman, Chief Executive Officer, March 28, 2007
-------------------------- President, Treasurer and Director
John F. Terwilliger (Principal Executive Officer)
/s/ O. Lee Tawes III Director March 28, 2007
--------------------------
O. Lee Tawes III
/s/ Edwin Broun III Director March 28, 2007
--------------------------
Edwin Broun III
/s/ Stephen Hartzell Director March 28, 2007
--------------------------
Stephen Hartzell
/s/ John Boylan Director March 28, 2007
--------------------------
John Boylan
/s/James J. Jacobs Chief Financial Officer March 28, 2007
-------------------------- (Principal Accounting Officer)
James J. Jacobs
29
HOUSTON AMERICAN ENERGY CORP.
INDEX TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . F-1
Balance Sheet as of December 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . F-2
Statements of Operations For the Years ended December 31, 2006 and 2005 . . . . . . F-3
Statements of Shareholders' Equity for the Years ended December 31, 2006 and 2005 . F-4
Statements of Cash Flows For the Years Ended December 31, 2006 and 2005 . . . . . . F-5
Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . F-6
30
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Houston American Energy Corp.
Houston, Texas
We have audited the accompanying balance sheet of Houston American Energy Corp.
as of December 31, 2006 and the related statements of operations, shareholders'
equity, and cash flows for the years ended December 31, 2006 and 2005. 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, 2006, and the results of its operations and its cash flows for
the years ended December 31, 2006 and 2005 in conformity with accounting
principles generally accepted in the United States of America.
Thomas Leger & Co., L.L.P.
March 26, 2007
Houston, Texas
F-1
HOUSTON AMERICAN ENERGY CORP.
BALANCE SHEET
DECEMBER 31, 2006
----------------------------------------------------------------------------
ASSETS
------
CURRENT ASSETS
Cash and cash equivalents $ 409,008
Marketable securities 14,000,000
Accounts receivable 325,436
------------
TOTAL CURRENT ASSETS 14,734,444
------------
PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties, full cost method
Costs subject to amortization 6,796,308
Costs not being amortized 700,549
Office equipment 11,878
------------
Total property, plant and equipment 7,508,735
Accumulated depreciation and depletion (2,260,463)
------------
PROPERTY, PLANT AND EQUIPMENT, NET 5,248,272
------------
OTHER ASSETS 3,167
------------
TOTAL ASSETS $19,985,883
============
LIABILITIES AND SHAREHOLDERS' EQUITY
------------------------------------
CURRENT LIABILITIES
Accounts payable $ 399,159
Accrued expenses 11,909
Foreign income taxes payable 121,216
------------
TOTAL CURRENT LIABILITIES 532,284
------------
LONG-TERM LIABILITIES
Reserve for plugging costs 38,816
------------
TOTAL LONG-TERM LIABILITIES 38,816
------------
SHAREHOLDERS' EQUITY
Common stock, par value $.001;
100,000,000 shares authorized, 27,920,172 shares outstanding 27,920
Additional paid-in capital 22,042,624
Treasury stock, at cost; 100,000 shares (85,834)
Accumulated deficit (2,569,927)
------------
TOTAL SHAREHOLDERS' EQUITY 19,414,783
------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $19,985,883
============
The accompanying notes are an integral part of these financial statements
F-2
HOUSTON AMERICAN ENERGY CORP.
STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005
----------------------------------------------------------------------------------
2006 2005
------------ ------------
Oil and gas revenue $ 3,202,731 $ 2,780,457
Consulting fees - 60,000
------------ ------------
Total revenue 3,202,731 2,840,457
------------ ------------
EXPENSES OF OPERATIONS
Lease operating expense and severance tax 1,017,440 861,790
Joint venture expense 167,023 61,500
Depreciation and depletion 887,911 363,196
General and administrative expense 1,231,079 835,829
------------ ------------
Total expenses 3,303,453 2,122,315
------------ ------------
INCOME (LOSS) FROM OPERATIONS (100,722) 718,142
------------ ------------
OTHER (INCOME) EXPENSE
Interest income (496,490) (34,191)
Interest expense-derivative 37,773 319,714
Net change in fair value of derivative liabilities 170,949 402,628
Interest expense 57,278 111,920
Interest expense on shareholder debt 20,440 72,000
Financing costs 110,787 16,816
------------ ------------
Total other (income) expense (99,263) 888,887
NET LOSS BEFORE TAXES (1,459) (170,745)
INCOME TAX EXPENSE 510,637 331,035
------------ ------------
NET LOSS $ (512,096) $ (501,780)
============ ============
BASIC AND DILUTED LOSS PER SHARE $ (0.02) $ (0.03)
============ ============
BASIC AND DILUTED WEIGHTED AVERAGE SHARES 25,087,847 19,970,553
============ ============
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, 2006 AND 2005
--------------------------------------------------------------------------------------------------------------------------------
-
Common Stock Treasury Stock
-------------------------------- ---------------------
Paid - in Accumulated
Shares Amount Capital Shares Amount Deficit Total
---------- ------- ----------- ---------- --------- ------------- ------------
Balance at December 31, 2004 19,968,089 $19,968 $ 2,800,027 (100,000) $(85,834) $ (1,556,051) $ 1,178,110
Stock issued for services 2,500 3 2,447 - - - 2,450
Stock options issued - - 49,447 - - - 49,447
Net loss - - - - - (501,780) (501,780)
---------- ------- ----------- ---------- --------- ------------- ------------
Balance at December 31, 2005 19,970,589 19,971 2,851,921 (100,000) (85,834) (2,057,831) 728,227
---------- ------- ----------- ---------- --------- ------------- ------------
Stock issued for -
Cash 5,533,333 5,533 15,356,050 - - - 15,361,583
Convertible notes 2,125,000 2,125 2,122,875 - - - 2,125,000
Warrant exercise 291,250 291 490,959 - - - 491,250
Options issued to director - - 70,200 - - - 70,200
Options issued to employee - - 219,555 - - - 219,555
Reclassification of derivative liabilities
and discount on convertible notes 931,064 931,064
Net loss - - - - - (512,096) (512,096)
---------- ------- ----------- ---------- --------- ------------- ------------
Balance at December 31, 2006 27,920,172 $27,920 $22,042,624 (100,000) $(85,834) $ (2,569,927) $19,414,783
========== ======= =========== ========== ========= ============= ============
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, 2006 AND 2005
------------------------------------------------------------------------------------------------
2006 2005
------------- ------------
CASH FLOW FROM OPERATING ACTIVITIES
Net Loss $ (512,096) $ (501,780)
ADJUSTMENTS TO RECONCILE NET LOSS
TO NET CASH FROM OPERATIONS
Depreciation and depletion 887,911 363,196
Stock-based compensation 289,755 51,895
Amortization of debt discount and deferred financing costs 148,557 336,530
Change in fair value of derivatives 170,949 402,628
Decrease (increase) in accounts receivable 247,786 (333,180)
Decrease in prepaid expense 9,965 79,983
(Decrease) increase in accounts payable and accrued liabilities (3,381) 295,309
------------- ------------
Net cash provided by operations 1,239,446 694,581
------------- ------------
CASH FLOW FROM INVESTING ACTIVITIES
Purchases of marketable securities (17,000,000) -
Sales of marketable securities 3,000,000 -
Acquisition of oil and gas properties and assets (3,507,371) (1,589,594)
------------- ------------
Net cash used in investing activities (17,507,371) (1,589,594)
------------- ------------
CASH FLOW FROM FINANCING ACTIVITIES
Sale of common stock - net of costs 15,361,583 -
Exercise of warrants 491,250 -
Repayment of shareholder loan (900,000) (100,000)
Issuance of debt - 1,997,500
------------- ------------
Net cash provided by financing 14,952,833 1,897,500
------------- ------------
DECREASE IN CASH (1,315,092) 1,002,487
Cash, beginning of year 1,724,100 721,613
------------- ------------
Cash, end of year $ 409,008 $ 1,724,100
============= ============
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid $ 77,718 $ 150,865
Taxes Paid $ 261,891 $ 74,907
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING
AND FINANCING ACTIVITIES
Conversion of convertible notes to common stock $ 2,445,345 $ -
Warrants issued for financing fees - 162,562
Exercise of warrants 610,719 -
The accompanying notes are an integral part of these financial statements
F-5
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2006
-------------------------------
NOTE 1 - NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL
-------
Houston American Energy Corp. (a Delaware Corporation) ("the Company") 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.
RECLASSIFICATION
----------------
Certain amounts for prior periods have been reclassified to conform to the
current presentation.
OIL AND GAS REVENUES
--------------------
The Company recognizes sales revenues based on the amount of gas, oil and
condensate sold to purchasers when delivery to the purchaser has occurred and
title has transferred. This occurs when production has been delivered to a
pipeline. Currently, the Company does not anticipate that the oil and gas sold
will be significantly different from the Company's production entitlement.
OIL AND GAS PROPERTIES AND EQUIPMENT
------------------------------------
The Company uses the full cost method of accounting for exploration and
development activities as defined by the SEC. Under this method of accounting,
the costs for unsuccessful, as well as successful, exploration and development
activities are capitalized as oil and gas properties. Capitalized costs include
lease acquisition, geological and geophysical work, delay rentals, costs of
drilling, completing and equipping the wells and any internal costs that are
directly related to acquisition, exploration and development activities but does
not include any costs related to production, general corporate overhead or
similar activities. Gain or loss on the sale or other disposition of oil and gas
properties is not recognized, unless the gain or loss would significantly alter
the relationship between capitalized costs and proved reserves of oil and
natural gas attributable to a country.
The Company categorizes its full costs pools as costs subject to amortization
and costs not being amortized. The sum of net capitalized costs subject to
amortization, including estimated future development and abandonment costs, are
amortized using the unit-of-production method.
Office equipment is stated at original cost and is depreciated on the
straight-line basis over the useful life of the assets, which ranges from three
to five years. Oil and gas properties and office equipment carrying values do
not purport to represent replacement or market values.
Depreciation expense for office equipment was $2,300 and $2,175 at December 31,
2006 and 2005, respectively and accumulated depreciation was $9,934 at December
31, 2006. Depletion and amortization for oil and gas properties was $885,611 and
$359,521 at December 31, 2006 and 2005, respectively and accumulated depletion
was $2,250,529 at December 31, 2006. Repairs and maintenance are expensed as
incurred.
F-6
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2006
-------------------------------
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 changes 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 are made by an independent reservoir engineer and a reservoir
engineer that is a shareholder and director of the Company. Revisions are
necessary year to year due to changes in assumptions based on, among other
things, reservoir performance, prices, economic conditions and governmental
restrictions. Decreases in prices, for example, may cause a reduction in some
proved reserves due to uneconomical conditions.
Unevaluated oil and gas properties not subject to amortization at December 31,
2006 include the following:
North South
America America Total
-------- -------- --------
Acquisition costs $180,197 $ - $180,197
Geological, geophysical and screening costs 40,200 480,152 520,352
-------- -------- --------
Total $220,397 $480,152 $700,549
======== ======== ========
F-7
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2006
-------------------------------
ASSET RETIREMENT OBLIGATIONS
----------------------------
The Company has adopted Statement of Financial Accounting Standards ("SFAS") No.
143, "Accounting for Asset Retirement Obligations," which addresses accounting
and reporting for obligations associated with the retirement of tangible
long-lived assets and the associated asset retirement costs. For the Company,
asset retirement obligations ("ARO") represent the systematic, monthly accretion
and depreciation of future abandonment costs of tangible assets such as
platforms, wells, service assets, pipelines, and other facilities. SFAS 143
requires that the fair value of a liability for an asset's retirement obligation
be recorded in the period in which it is incurred if a reasonable estimate of
fair value can be made, and that the corresponding cost is capitalized as part
of the carrying amount of the related long-lived asset. The liability is
accreted to its then present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. If the liability is
settled for an amount other than the recorded amount, an adjustment is made to
the full cost pool, with no gain or loss recognized, unless the adjustment would
significantly alter the relationship between capitalized costs and proved
reserves. The Company's normal domestic operation is to assign depleted wells to
a salvager, for abandonment obligations, before the wells have reached their
economic limits. The company has risk adjusted the domestic abandonment
obligation to zero. Therefore the abandonment costs will have no effect on
future income from domestic operations. Under the company's previous accounting
method, the company included estimated future costs of abandonment and
dismantlement in the full cost amortization base and amortized these costs as a
component of depletion expense. Subsequent to adoption of SFAS 143, the ARO
assets, which are carried on the balance sheet as part of the full cost pool,
have been included in our amortization base for the purposes of calculating
depreciation, depletion and amortization expense. For the purposes of
calculating the ceiling test, the future cash outflows associated with settling
the ARO liability have been included in the computation of the discounted
present value of estimated future net revenues.
The following table describes changes in our asset retirement liability during
each of the years ended December 31, 2006 and 2005. The ARO liability in the
table below includes amounts classified as both current and long-term at
December 31, 2006 and 2005.
Years Ended December 31
----------------------------
2006 2005
------------- -------------
ARO liability at January 1 $ 41,249 $ 39,952
Accretion expense 3,300 4,504
Liabilities incurred from drilling 11,077 20,505
Liabilities incurred - assets acquired - 3,501
Liabilities settled - assets abandoned - (17,423)
Changes in estimates (16,810) (9,790)
------------- -------------
ARO liability at December 31, $ 38,816 $ 41,249
============= =============
JOINT VENTURE EXPENSE
---------------------
Joint venture expense reflects the indirect field operating and regional
administrative expenses billed by the operator of the Columbian concessions.
INCOME TAXES
------------
Deferred income taxes are provided on a liability method whereby deferred tax
assets and liabilities are established for the difference between the financial
reporting and income tax basis of assets and liabilities as well as operating
loss and tax credit carry forwards. Deferred tax assets are reduced by a
valuation allowance when, in the opinion of management, it is more likely than
not that some portion or all of the deferred tax assets will not be realized.
Deferred tax assets and liabilities are adjusted for the effects of changes in
tax laws and rates on the date of enactment.
F-8
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2006
-------------------------------
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.
CASH AND CASH EQUIVALENTS
-------------------------
Cash and cash equivalents consist of demand deposits and cash investments with
initial maturity dates of less than three months.
MARKETABLE SECURITIES
---------------------
Holdings of marketable securities qualify as available-for-sale or trading
securities and are recorded at fair value. Marketable securities consist of
asset-backed securities, corporate bonds, and municipal bonds with original
maturities beyond 90 days. As the Company views all securities as representing
the investment of funds available for current operations, the short-term
investments are classified as current assets. The Company's policy is to
protect the value of its investment portfolio and minimize principal risk by
earning returns based on current interest rates. All of the Company's
marketable securities are classified as available-for-sale securities in
accordance with the provisions of SFAS No. 115, "Accounting For Certain
Investments in Debt and Equity Securities" and are carried at fair market value
with unrealized gains and losses, net of taxes, reported as a separate component
of stockholders' equity. Realized gains and losses and declines in value of
securities judged to be other then temporary are included in interest income,
net, based on the specific identification method. There were no unrealized
gains or losses associated with these marketable securities at December 31,
2006. At December 31, 2006 the Company held $14,000,000 in marketable
securities.
NET LOSS PER SHARE
------------------
Pursuant to SFAS No. 128, "Earnings Per Share," basic net income per share is
computed by dividing the net income attributable to common shareholders by the
weighted-average number of common shares outstanding during the period. Diluted
net income per share is computed by dividing the net income attributable to
common shareholders by the weighted-average number of common and common
equivalent shares outstanding during the period. Common share equivalents
included in the diluted computation represent shares issuable upon assumed
exercise of stock options, warrants, and convertible notes using the treasury
stock and "if converted" method. Our securities do not have a contractual
obligation to share in the losses in any given period. As a result these
securities were not allocated any losses in the periods of net losses.
For the year ended December 31, 2006, 309,000 options and 315,000 warrants to
purchase common stock were excluded from the calculation of diluted net loss per
share because they were anti-dilutive. For the year ended December 31, 2005,
2,125,000 shares of common stock issuable upon conversion of convertible notes,
89,000 options and 191,250 warrants to purchase common stock were excluded from
the calculation of diluted net loss per share because they were anti-dilutive.
CONCENTRATION OF RISK
---------------------
The Company is dependent upon the industry skills and contacts of John F.
Terwilliger, the 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 its concessions in the
South American country of Colombia, the Company is dependent on the personnel,
management and resources of that entity to operate efficiently and effectively.
As a non-operating joint interest owner, the Company has a right of investment
refusal on specific projects and the right to examine and contest its division
of costs and revenues determined by the project operator.
The Company currently has interests in 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
F-9
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2006
-------------------------------
short period of time. In the event of a significant negative change in
political and economic stability in the vicinity of the Company's Colombian
operations, the Company may be forced to abandon or suspend their efforts.
Either of such events could be harmful to the Company expected business
prospects.
At December 31, 2006, 67% of the Company's net oil and gas property investment
and 80% of its revenue was with or derived from the company managing the
Columbian properties.
The majority of oil production for 2006 from the Company's mineral interests was
sold to an international integrated oil company (96%). The gas production was
sold to U.S. natural gas marketing companies based on the highest bid. There
were no other product sales of more than 10% to a single buyer.
CONCENTRATION OF CREDIT RISK
----------------------------
Financial instruments that potentially subject the Company to a concentration of
credit risk include cash, cash equivalent and marketable securities. The
Company had cash deposits of approximately $152,000 in excess of FDIC insured
limits at the period end. The Company has not experienced any losses on its
deposits of cash and cash equivalents, and its short-term investments.
RESTATEMENT OF INTERIM QUARTERS
-------------------------------
During 2006, the Company determined that its original accounting for the
Subordinated Convertible Notes ("Convertible Notes") and Warrants ("2005
Warrants") issued on May 4, 2005, were not reported in accordance with generally
accepted accounting principles. The Company determined that the Convertible
Notes and Warrants contain detachable and embedded derivatives. The Company
revised its accounting for the Convertible Notes and Warrants, and filed
amendments to its previously filed Forms 10-QSB for the three and six months
ended June 30, 2005, and the three and nine months ended September 30, 2005.
SUBORDINATED CONVERTIBLE NOTES AND WARRANTS- DERIVATIVE FINANCIAL INSTRUMENTS
-----------------------------------------------------------------------------
The Convertible Notes and the 2005 Warrants were accounted for in accordance
with EITF No. 00-19, "Accounting for Derivative Financial Instruments Indexed
to, and Potentially Settled in, a Company's Own Stock," EITF 05-02 "Meaning of
'Conventional Convertible Debt Instrument' in Issue No. 00-19", and EITF 05-04
"The Effect of a Liquidated Damages Clause on a Freestanding Financial
Instrument Subject to Issue No. 00-19".
The Company identified the following instruments and derivatives:
Convertible Notes
Conversion feature
Conversion price reset feature
Company's optional redemption right
Warrants
Warrants exercise price reset feature
The Company identified the conversion feature; the conversion price reset
feature and the Company's optional early redemption right within the Convertible
Notes to represent embedded derivatives. These embedded derivatives were
bifurcated from their respective host debt contracts and accounted for as
derivative liabilities because they were subject to a registration rights
agreement. The conversion feature, the conversion price reset feature and the
Company's optional early redemption right within the Convertible Notes were
bundled together as a single hybrid compound instrument in accordance with SFAS
No. 133 Derivatives Implementation Group Implementation Issue No. B-15,
"Embedded Derivatives: Separate Accounting for Multiple Derivative Features
Embedded in a Single Hybrid Instrument."
The Company identified the common stock warrant as a detachable derivative. The
warrant exercise price reset provision is an embedded derivative within the
common stock warrant. The common stock warrant and the embedded warrant
exercise price reset provision were accounted for as a separate single hybrid
compound instrument.
F-10
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2006
-------------------------------
The Single Compound Embedded Derivatives within Convertible Notes and the
Derivative Liability for Warrants were recorded at fair value at the date of
issuance (May 4, 2005) and marked-to-market each quarter with changes in fair
value recorded to the Company's income statement as "Net change in fair value of
derivative liabilities." The Company utilized a third party valuation firm to
fair value both single compound embedded derivatives under the following
methods: a layered discounted probability-weighted cash flow approach for the
Single Compound Embedded Derivatives within Convertible Notes; and the
Black-Scholes model for the Derivative Liability for Warrants based on a
probability weighted exercise price.
The fair value of the derivative liabilities was subject to the changes in the
trading value of the Company's common stock. As a result, the Company's
financial statements fluctuated from quarter-to-quarter based on factors, such
as the price of the Company's stock at the balance sheet date, the amount of
shares converted by note holders and/or exercised by warrant holders.
Consequently, our financial position and results of operations varied from
quarter-to-quarter based on conditions other than our operating revenues and
expenses.
In May 2006, the Convertible Notes were converted to common stock and the 2005
Warrants were exercised resulting in the reclassification of all derivative
liabilities associated with the Convertible Notes and 2005 Warrants. See "Note
2 - Notes Payable - Subordinated Convertible Notes" and "- 2005 Warrants."
STOCK-BASED COMPENSATION
-------------------------
Effective January 1, 2006, the Company adopted the provisions of SFAS 123R
"Share Based Payment" for its stock based compensation plans, using the modified
prospective transition method, and as a result did not retroactively adjust
results from prior periods. The Company previously accounted for these plans
under the recognition and measurement principles of Accounting Principles Board
("APB") Opinion No. 25, "Accounting for Stock Issued to Employees," and related
interpretations and disclosure requirements established by SFAS 123, "Accounting
for Stock-Based Compensation."
Under APB 25, the Company recognized stock based compensation using the
intrinsic value method and, thus, generally no compensation expense was
recognized for stock options as they were generally granted at the market value
on the date of grant. The pro forma effects on net income due to stock based
compensation were disclosed in the notes to the consolidated financial
statements. SFAS 123R eliminates the use of APB 25 and the intrinsic value
method of accounting, and requires companies to recognize the cost of employee
services received in exchange for awards of equity instruments, based on the
grant date fair value of those awards, in the financial statements over the
requisite service period.
RECENT ACCOUNTING DEVELOPMENTS
--------------------------------
In February 2006, the FASB issued Statement of Financial Accounting Standards
No. 155 (SFAS 155) "Accounting for Certain Hybrid Instruments - an amendment of
FASB Statements No. 133 and 140." SFAS 155 amends SFAS 133 to permit fair value
measurement for certain hybrid financial instruments that contain an embedded
derivative, provides additional guidance on the applicability of SFAS 133 and
SFAS 140 to certain financial instruments and subordinated concentrations of
credit risk. SFAS 155 is effective for the first fiscal year that begins after
September 15, 2006. This did not have any impact on the Company's financial
statements.
In July 2006, the Financial Accounting Standards Board issued FASB
Interpretation No. 48 "Accounting for Uncertainty in Income Taxes--an
Interpretation of FASB Statement 109" (FIN 48), which clarifies the accounting
for uncertainty in tax positions taken or expected to be taken in a tax return,
including issues relating to financial statement recognition and measurement.
FIN 48 provides that the tax effects from an uncertain tax position can be
recognized in the financial statements only if the position is
"more-likely-than-not" of being sustained if the position were to be challenged
by a taxing authority. The assessment of the tax position is based solely on the
technical merits of the position, without regard to the likelihood that the tax
position may be challenged. If an uncertain tax position meets the
"more-likely-than-not" threshold, the largest amount of tax benefit that is
greater than 50 percent likely of being recognized upon ultimate settlement with
the taxing authority, is recorded. The provisions of FIN 48 are effective for
fiscal years beginning after December 15, 2006, with the cumulative effect of
the change in accounting principle recorded as an adjustment to opening retained
earnings. The Company is currently evaluating the impact of FIN 48 on the
financial statements.
F-11
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2006
-------------------------------
In September 2006 the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 157 "Fair Value Measurements" (SFAS 157),
which provides expanded guidance for using fair value to measure assets and
liabilities. SFAS 157 establishes a hierarchy for data used to value assets and
liabilities, and requires additional disclosures about the extent to which a
company measures assets and liabilities at fair value, the information used to
measure fair value, and the effect of fair value measurements on earnings.
Implementation of SFAS 157 is required on January 1, 2008. The Company is
currently evaluating the impact of adopting SFAS 157 on the financial
statements.
On September 29, 2006, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 158 "Employers' Accounting for Defined
Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements
No. 87, 88, 106, and 132(r)" (SFAS 158). The Statement requires the recognition
of the overfunded or underfunded status of a defined benefit postretirement plan
as an asset or liability on the balance sheet and the recognition of the changes
of the funded status in the year in which the changes occur through
comprehensive income. Implementation of SFAS 158 is required as of the end of
the fiscal year ending after December 15, 2006. The adoption of SFAS 158 did not
have an impact on the Company's financial statements because the Company does
not currently have any defined benefit pension or other postretirement benefit
plans.
On September 13, 2006 the SEC issued Staff Accounting Bulletin No. 108 (SAB
108), which establishes an approach that requires quantification of financial
statement errors based on the effects of the error on each of the company's
financial statements and the related disclosures. SAB 108 requires the use of a
balance sheet and an income statement approach to evaluate whether either of
these approaches results in quantifying a misstatement that, when all relevant
quantitative and qualitative factors are considered, is material. The adoption
of SAB 108 did not have an impact on the Company's financial statements.
NOTE 2 - NOTES PAYABLE AND RELATED DERIVATIVE LIABILITIES
NOTE PAYABLE - SHAREHOLDER
-----------------------------
Shareholder loans, in the principal amount of $900,000, were repaid in full from
the proceeds of the April 2006 private placement.
SUBORDINATED CONVERTIBLE NOTES
------------------------------
On May 4, 2005, the Company entered into purchase agreements with multiple
investors pursuant to which the Company sold $2,125,000 of 8% subordinated
convertible notes due 2010.
The notes bear interest at 8%, provide for semi-annual interest payments and had
a maturity date of May 1, 2010. The notes were convertible, at the option of
the holders, into common stock of the Company at a price of $1.00 per share,
subject to standard anti-dilution provisions relating to splits, reverse splits
and other transactions plus a reset provision whereby the conversion price could
be adjusted downward to a lower price per share if the Company issued its common
stock to others below the stated conversion price. The notes were subject to
automatic conversion in the event the Company conducted an underwritten public
offering of its common stock from which the Company received at least $5 million
and the public offering price was at least 150% of the then applicable
conversion price. The Company had the right to cause the notes to be converted
into common stock after May 1, 2006 if the price of the Company's common stock
exceeded 200% of the then applicable conversion price on the date of conversion
and for at least 20 trading days over the preceding 30 trading days. The
Company had the right to repurchase the Notes after May 1, 2007 at 103% of the
face amount during 2007, 102% of the face amount during 2008, 101% of the face
amount during 2009 and 100% of the face amount thereafter. The notes were
unsecured general obligations of the Company and were subordinated to all other
indebtedness of the Company unless the other indebtedness was expressly made
subordinate to the notes. The conversion feature, the conversion price, reset
provision and the Company's optional early redemption right in the Convertible
Notes were bundled together as a single compound embedded derivative liability,
and using a layered discounted probability-weighted cash flow approach, were
initially fair valued at $2,368,485 at May 4, 2005. The fair value model
comprises multiple probability-weighted scenarios under various assumptions
reflecting the economics of the Convertible Notes, such as the risk-free
interest rate, expected Company stock price and volatility, likelihood of
conversion and or redemption, and likelihood of default
F-12
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2006
-------------------------------
and timely registration. At inception, the fair value of this single compound
embedded derivative was bifurcated from the host debt contract and recorded as a
derivative liability which resulted in a reduction of the initial notional
carrying amount of the Convertible Notes (as unamortized discount which was
being amortized over a five-year period under the effective interest method).
At inception the excess of the unamortized discount over the notional amount of
the Convertible Note in the amount of $285,547 was charged to expense in the
Company's statement of operations. For the period from inception of the
Convertible Notes (May 4, 2005) through December 31, 2005, the amortization of
unamortized discount on the Convertible Notes was $34,167, which was classified
as interest expense in the accompanying statement of operation. The mark to
market adjustment to increase the derivative liability for the period from
inception to December 31, 2005 was $15,561.
On May 2, 2006, the Convertible Notes were satisfied in full in May 2006 upon
the conversion of the same to common stock. See Note 6. As a result of
conversion of the Convertible Notes, the compound embedded derivative liability
of $2,373,405 at that date was reclassified as additional paid in capital, and
the unamortized discount, in the amount of $2,053,060, was credited as a
reduction of additional paid in capital for the year ended December 31, 2006.
The mark to market adjustment to decrease the derivative liability from December
31, 2005 to the conversion date was $10,640.
2005 WARRANTS
-------------
On May 4, 2005, in connection with the issuance of the Convertible Notes, the
Company entered into the 2005 Warrants, three year warrant agreements, with nine
parties whereby 191,250 warrants were issued at an exercise price of $1.00 per
share, subject to a reset provision whereby the exercise price would be adjusted
downward in the event the Company issued its common stock to others at a price
below the initial warrant exercise price. This reset provision represents an
embedded derivative, which was not bifurcated from the host warrant contract (as
both were derivatives) and was a derivative liability at its fair value at date
of inception utilizing the Black-Scholes method with a probability weighted
exercise price. This fair value model comprised multiple probability-weighted
scenarios under various assumptions reflecting the economics of the warrants,
such as risk free interest rate, expected Company stock price and volatility,
likelihood of exercise, and timely registration. The assumptions used at
December 31, 2005 were a risk-free interest rate of 3.08%, volatility of 40%,
expected term of 2.3 years, dividend yield of 0.00% and a probability weighted
exercise price of $.983. The common stock warrants and the embedded warrant
price reset provision were initially fair valued at $42,063 at May 4, 2005 and
charged to expense in the Company's statement of operations. The mark to market
adjustment for the period from inception to December 31, 2005 was $387,067.
The 2005 Warrants were exercised in full in May 2006. See Note 6. As a result
of exercise of the warrants, the derivative liability associated with the
warrants, in the amount of $610,719, was reclassified as additional paid in
capital for the year ended December 31, 2006. The mark to market adjustment to
increase the liability from December 31, 2005 to the date of exercise was
$181,589.
NOTE 3 - RELATED PARTIES
In conjunction with the Company's efforts to secure oil and gas prospects,
financing and services, in lieu of salary or other forms of compensation, during
2005, the Company granted to John F. Terwilliger, Chief Executive Officer, and
Orrie L. Tawes, a principal shareholder and Director, overriding royalty
interests in select mineral properties of the Company. During 2006 and 2005,
Mr. Terwilliger received royalty payments relating to those properties totaling
$37,333 and $38,109, respectively, and Mr. Tawes received royalty payments
relating to those properties totaling $23,343 and $24,939, respectively.
John Terwilliger periodically loaned funds to support the Company's operations.
At December 31, 2005, loans from Mr. Terwilliger totaled $904,400, including
accrued interest. Loans from Mr. Terwilliger accrued interest at 7.2% and were
due January 1, 2007. The loans from Mr. Terwilliger were repaid in full in May
2006. Interest paid to Mr. Terwilliger totaled $20,440 during 2006 and $72,000
during 2005.
In May 2005, Northeast Securities, Inc. acted as placement agent in connection
with the Company's offer and sale of $2,125,000 of Subordinated Convertible
Notes for which Northeast Securities, and its affiliates, received commissions
totaling $127,500 and the 2005 Warrants to purchase 191,250 shares of common
stock at $1.00 per share. Orrie L. Tawes is Executive Vice President, head of
Investment Banking and a Director of Northeast Securities.
F-13
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2006
-------------------------------
NOTE 4 - INCOME TAXES
The following table sets forth a reconciliation of the statutory federal income
tax for the year ended December 31, 2006 and 2005.
2006 2005
Loss before income taxes $ (1,459) $(170,745)
========= ===========
Income tax computed at statutory rates $ (496) $ (58,053)
Derivative expense 70,982 245,596
Effect of foreign tax provision, before effect of changes in tax rate,
on the total tax provision 173,616 140,014
Permanent differences, nondeductible expenses 40,330 1,934
Increase (decrease) in valuation allowance 219,567 (4,932)
Other 6,638 6,476
--------- ----------
Tax provision $510,637 $ 331,035
========= ==========
Current provision
United States $ - $ -
Foreign 510,637 331,035
Deferred provision - -
--------- ----------
Total provision $510,637 $ 331,035
========= ==========
No federal income taxes have been paid since the inception of the Company. The
Company has a net operating loss carry forward of approximately $195,696 which
will expire in 2018. In addition, the Company has approximately $842,000 of
foreign tax credit carry forwards which will expire in 2015 and 2016. The
Company's net operating loss carry forwards may be subject to annual
limitations, which could reduce or defer the utilization of the loss as a result
of an ownership change as defined in section 382 of the Internal Revenue Code.
The tax effects of the temporary differences between financial statement income
and taxable income are recognized as a deferred tax asset and liability.
Significant components of the deferred tax asset and liability as of December
31, 2006 are set out below.
2006 2005
---------- ----------
Deferred tax asset:
Net operating loss carry forwards $ 66,536 $ 398,888
Foreign tax credit carry forward 841,642 331,035
Asset retirement obligation 13,197 15,115
Valuation allowance (731,851) (512,284)
Book over tax depreciation, depletion
and capitalization methods on oil
and gas properties (189,524) (234,250)
Book over tax accrued interest payments - 1,496
---------- ----------
Net deferred tax asset $ - $ -
========== ==========
F-14
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2006
-------------------------------
FOREIGN INCOME TAXES
----------------------
The Company owns an interest in a Limited Liability Company that operates the
activities in Columbia. Colombia's tax rate is 38.5%. Based on information
provided by the manager of the LLC the company has determined their share of the
Columbia tax liability for 2006 will be $510,637. This amount has been accrued
during the year and will be funded by withholdings from the 2006 revenue and
from revenue received in 2007.
The Company has reclassified $91,834 from severance taxes to foreign income
taxes for the year ended December 31, 2005. The reclassification had no effect
on the net loss or loss per share for the year ended December 31, 2005.
NOTE 5 - STOCK BASED COMPENSATION
On August 12, 2005, the Company's Board of Directors adopted the Houston
American Energy Corp. 2005 Stock Option Plan (the "Plan"). The terms of the
Plan allow for the issuance of up to 500,000 options to purchase 500,000 shares
of the Company's common stock. Persons eligible to participate in the Plan are
key employees, consultants and directors of the Company. During 2006 the Company
granted 20,000 options to the members of the Board of Directors and 200,000 to a
key employee.
The fair value of the options granted to the director was valued on the date of
the grant using the Black-Scholes option-pricing model with the following
weighted average assumptions, risk-free interest rate 4.82%, expected life in
years 10, expected stock volatility 81%, expected dividends 0.0%. Using this
model yielded a value of $70,200 which was charged to expense in 2006.
The fair value of the options granted to a key employee was valued on the date
of the grant using the Black-Scholes option-pricing model with the following
weighted average assumptions, risk-free interest rate 5.24%, expected life in
years 10, expected stock volatility 77%, expected dividends 0.0%. The total
value of the options was $494,000. The options are being expensed over the
vesting period. During 2006, $219,555 was expensed as employee compensation.
Prior to January 1, 2006, the Company accounted for employee stock option grants
using the intrinsic method in accordance with APB 25 "Accounting for Stock
Issued to Employees." As such, no compensation cost was recognized for employee
stock options that had exercise prices equal to the fair market value of our
common stock at the date of granting the option. The Company also complied with
the pro forma disclosure requirements of SFAS No. 123 "Accounting for Stock
Based Compensation," and SFAS No. 148 "Accounting for Stock-Based Compensation
-Transition and Disclosure."
SFAS 123R requires the Company to present pro forma information for the
comparative periods prior to the adoption as if the Company had accounted for
all employee stock options under the fair value method of the original SFAS 123.
The following table illustrates the effect on net income and net income per
common share if the Company had applied the fair value recognition provisions of
SFAS 123 to stock-based employee compensation in 2005:
Net loss, as reported $(501,780)
Less: Total stock-based compensation
expense determined using fair value
method, net of taxes (69,600)
----------
Pro forma net loss (571,380)
==========
Net loss per share - as reported $ (.03)
Net loss per share - pro forma $ (.03)
F-15
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2006
-------------------------------
Option activity during 2006 is as follows:
Weighted
Average
Weighted Remaining
Average Contractual
Exercise Term (in Aggregate
Options Price Years) Intrinsic Value
------- --------- ------------ ----------------
Outstanding at beginning of year 89,000 $ 2.42 8.72 $ 439,660
Granted 220,000 3.08 9.44 941,600
Exercised - - - -
Forfeited - - - -
------- --------- ------------ ----------------
Outstanding at end of year 309,000 $ 2.89 8.92 $ 1,381,260
======= ========= ============ ================
The aggregate intrinsic value in the table above represents the total pretax
intrinsic value (the difference between our closing stock price on December 31,
2006 and the exercise price, multiplied by the number of in-the-money options)
that would have been received by the option holders had all option holders
exercised their options on December 31, 2006. This amount changes based on the
fair market value of our stock. Total intrinsic value of options exercised for
the year ended December 31, 2006 was zero. As of December 31, 2006, total
unrecognized stock-based compensation expense related to non-vested stock
options was $275,000. As of December 31, 2006 there were 191,000 shares of
common stock available for issuance pursuant to future stock option grants.
Additional information regarding options outstanding as of December 31, 2006 is
as follows:
Options Outstanding Options Exercisable
--------------------------------------------------- ------------------------------
Number Weighted Weighted Number
Range of Outstanding at Average Average Outstanding at Weighted
Exercise December 31, Remaining Exercise December 31, Average
Price 2006 Contractual Life Price 2006 Exercise Price
--------- ------------------- ------------------- --------- -------------- --------------
$ 2.00 60,000 8.62 $ 2.00 60,000 $ 2.00
$ 2.98 200,000 9.51 $ 2.98 66,667 $ 2.98
$ 3.30 29,000 8.87 $ 3.30 29,000 $ 3.30
$ 4.10 20,000 9.37 $ 4.10 20,000 $ 4.10
NOTE 6 - COMMON STOCK
APRIL 2006 PRIVATE PLACEMENT
-------------------------------
On April 28, 2006, the Company entered into Subscription Agreements (the
"Purchase Agreements") with multiple investors pursuant to which the Company
sold 5,533,333 shares of common stock (the "Shares") for $16,599,999.
The Shares were offered and sold in a private placement transaction pursuant to
the exemption from registration provided by Section 4(2) of the Securities Act
of 1933 and Rule 506 promulgated thereunder. Each investor was an "accredited
investor" as defined in Rule 501 promulgated under the Securities Act.
Pursuant to the terms of the Subscription Agreements, the Company and the
investors entered into Registration Rights Agreements under which the Company
agreed to file with the Securities and Exchange Commission, within 60 days, a
registration statement covering the Shares. In conjunction with the placement
of the Shares, John Terwilliger, O. Lee Tawes III and Edwin Broun III each
entered into lock-up agreements pursuant to which each agreed not to offer or
sell any shares of the Company's common stock until the earlier of the effective
date of the registration statement relating to the Shares or one year from the
sale of the Shares.
Sanders Morris Harris Inc. acted as placement agent in connection with the offer
and sale of the Shares. For its services as placement agent, Sanders Morris
Harris Inc. received commissions totaling $1,162,000 and a warrant (the
"Placement Agent Warrant") to purchase 415,000 shares of common stock at $3.00
per share. The Registration
F-16
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2006
-------------------------------
Rights Agreements provide that the shares of common stock underlying the
Placement Agent Warrant are to be included in the registration statement to be
filed.
CONVERSION OF 8% SUBORDINATED CONVERTIBLE NOTES
-----------------------------------------------
On May 2, 2006, the Company notified the holders of its Convertible Notes of its
election to convert the Convertible Notes into shares of the Company's common
stock. As a result of such election, the full principal amount of the
Convertible Notes of $2,125,000 was satisfied by conversion of the same into
2,125,000 shares of common stock.
The shares of common stock issued on conversion of the Convertible Notes were
offered and issued pursuant to the exemption from registration provided by
Section 4(2) of the Securities Act of 1933. Each of the investors is an
"accredited investor", as defined in Rule 501 promulgated under the Securities
Act.
EXERCISE OF WARRANTS
--------------------
In May 2006, the holders of the 2005 Warrants exercised all 191,250 warrants and
were issued an aggregate of 191,250 shares of common stock for aggregate
consideration of $191,250.
The shares of common stock issued on exercise of the warrants were offered and
issued pursuant to the exemption from registration provided by Section 4(2) of
the Securities Act of 1933. Each of the investors is an "accredited investor",
as defined in Rule 501 promulgated under the Securities Act.
In December 2006, Sanders Morris Harris exercised 100,000 of the 415,000
Placement Agent Warrants, and Sanders Morris Harris was issued 100,000 shares
for an aggregate consideration of $300,000. At December 31, 2006, the Company
had the remaining 315,000 warrants outstanding with a remaining contractual life
of 4.25 years.
The weighted average exercise price for all warrants exercised during the year
ended December 31, 2006 was $1.69.
NOTE 7 - COMMITMENTS AND CONTINGENCIES
LEASE COMMITMENT - The Company leases office facilities under an operating lease
----------------
agreement which expires May 31, 2012. The lease agreement requires future
payments as follows:
Year Amount
--------- --------
2007 $ 51,946
2008 79,576
2009 81,945
2010 84,315
2011 86,684
2012 36,530
--------
Total $420,996
========
Total rental expense in 2006 was $43,704 and $41,014 in 2005. The Company does
not have any capital leases or other operating lease commitments.
LEGAL CONTINGENCIES - The Company is subject to legal proceedings, claims and
-------------------
liabilities that arise in the ordinary course of its business. The Company
accrues for losses associated with legal claims when such losses are probable
and can be reasonably estimated. These accruals are adjusted as further
information develops or circumstances change. During the twelve months ended
December 31, 2005, the Company was named as defendant in a suit filed in the
United States Bankruptcy Court for the Southern District of Texas. The Company
settled the bankruptcy litigation. The Company paid the $25,000 to settle the
case.
F-17
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2006
-------------------------------
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.
EMPLOYMENT ARRANGEMENTS - Prior to October 1, 2004, the Company paid no salary
-----------------------
or other compensation to any of its officers. In lieu of direct salary or
compensation, the Company, periodically, granted overriding royalty interests
with respect to certain properties to its Chief Executive Officer and to two
shareholders that subsequently were elected as directors of the Company.
In October 2004, the Company began paying an annual salary of $180,000 to its
Chief Executive Officer. Effective June 1, 2006, the salary of the Chief
Executive Officer was increased to $300,000 annually.
In July 2006, the Company appointed James "Jay" Jacobs as Chief Financial
Officer and fixed Mr. Jacobs' compensation as follows: (1) base salary of
$125,000; and (2) a stock option to purchase 200,000 shares of common stock at
$2.98 per share, the closing price on first day of employment, vesting over a 2
year period and exercisable over a period of ten years. The Company has agreed,
by the end of the 2nd quarter of 2007, to retain the services of an outside
compensation consulting firm to review and make recommendations with respect to
the compensation of Mr. Jacobs and each of the Company's executive officers and
directors.
NOTE 8 - SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND
PRODUCTION ACTIVITIES (UNAUDITED)
This footnote provides unaudited information required by Statement of Financial
Accounting Standards No. 69, "Disclosures about Oil and gas Producing
Activities".
GEOGRAPHICAL DATA - The following table shows the Company's oil and gas revenues
-----------------
and lease operating expenses, which includes the joint venture expenses incurred
in South America, by geographic area:
2006 2005
---------- ----------
Revenues
North America $ 637,625 $ 739,384
South America 2,565,106 2,041,072
---------- ----------
$3,202,731 $2,780,456
========== ==========
Production Cost
North America $ 198,167 $ 79,542
South America 819,273 782,248
---------- ----------
$1,017,440 $ 861,790
========== ==========
F-18
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2006
-------------------------------
CAPITAL COSTS - Capitalized costs and accumulated depletion relating to the
-------------
Company's oil and gas producing activities as of December 31, 2006, 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 $ 220,396 $ 480,153 $ 700,549
Properties being amortized 2,283,361 4,512,947 6,796,308
Accumulated depreciation, depletion and
Amortization (1,326,529) (911,195) (2,237,724)
------------ ----------- ------------
Total capitalized costs $ 1,177,228 $4,081,905 $ 5,259,133
============ =========== ============
AMORTIZATION RATE
-----------------
The amortization rate per unit based on barrel equivalents was $26.71 for North
America and $10.47 for South America.
ACQUISITION, EXPLORATION AND DEVELOPMENT COSTS INCURRED - Costs incurred in oil
-------------------------------------------------------
and gas property acquisition, exploration and development activities for
December 31, 2006 and 2005 is summarized below:
2006
------------------------------
North America South America
-------------- --------------
Property acquisition costs:
Proved $ 888,057 $ 355,000
Unproved 182,197 -
Exploration costs 1,292,226 3,914,171
Development 141,277 723,929
-------------- --------------
Total costs incurred $ 2,503,757 $ 4,993,100
============== ==============
2005
------------------------------
North America South America
-------------- --------------
Property acquisition costs:
Proved $ 733,719 $ 355,000
Unproved 44,548 -
Exploration costs 954,916 1,508,388
Development costs 71,950 324,398
-------------- --------------
Total costs incurred $ 1,805,133 $ 2,187,786
============== ==============
RESERVE INFORMATION AND RELATED STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET
--------------------------------------------------------------------------------
CASH FLOWS -
-----------
The supplemental unaudited presentation of proved reserve quantities and related
standardized measure of discounted future net cash flows provides estimates only
and does not purport to reflect realizable values or fair market values of the
Company's reserves. Volumes reported for proved reserves are based on reasonable
estimates. These estimates are consistent with current knowledge of the
characteristics and production history of the reserves. The Company emphasizes
that reserve estimates are inherently imprecise and that estimates of new
discoveries are more imprecise than those of producing oil and gas properties.
Accordingly, significant changes to these estimates can be expected as future
information becomes available.
F-19
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2006
-------------------------------
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.
These estimates are made by an independent reservoir engineer and a reservoir
engineer that is a shareholder and director of the Company. Reserve definitions
and pricing requirements prescribed by the Securities and Exchange Commission
were used. Total estimated proved developed and undeveloped reserves by product
type and the changes therein are set forth below for the years indicated.
North America South America Total
-------------------------------------------------------------------
Gas (mcf) Oil (bbls) Gas (mcf) Oil (bbls) Gas (mcf) Oil (bbls)
-------------------------------------------------------------------
Total proved reserves
Balance December 31, 2004 202,420 11,590 - 295,700 202,420 307,290
Extensions and discoveries 270,536 424 - 146,109 270,536 146,533
Revisions of prior estimates 456,656 (7,810) - (128,290) 456,656 (136,100)
Production (78,962) (1,404) - (42,898) (78,962) (44,302)
--------- ---------- --------- ---------- --------- ----------
Balance December 31, 2005 850,650 2,800 - 270,621 850,650 273,421
========= ========== ========= ========== ========= ==========
Extensions and discoveries 3 141 - 277,151 3 277,292
Revisions of prior estimates (346,807) 1,666 - (110,269) (346,807) (108,603)
Production (78,096) (1,687) - (48,057) (78,096) (49,744)
--------- ---------- --------- ---------- --------- ----------
Balance December 31, 2006 425,750 2,920 - 389,446 425,750 392,366
========= ========== ========= ========== ========= ==========
Proved developed reserves
at December 31, 2005 364,970 560 - 200,437 364,970 200,997
========= ========== ========= ========== ========= ==========
at December 31, 2006 85,890 2,240 - 283,500 85,890 285,740
========= ========== ========= ========== ========= ==========
F-20
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2006
-------------------------------
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.
Standard measure of discounted future net cash flows at December 31, 2006
North America South America Total
--------------- --------------- ------------
Future net cash flow 2,927,620 18,479,216 21,406,836
Future production cost (1,303,900) (6,993,899) (8,297,799)
Future income tax - (2,862,863) (2,862,863)
--------------- --------------- ------------
Future net cash flow 1,623,720 8,622,454 10,246,174
10% annual discount for timing of cash flow 567,170 1,596,667 2,163,837
--------------- --------------- ------------
Standard measure of discounted future net
cash flow relating to proved oil and gas reserves $ 1,056,550 $ 7,025,787 $ 8,082,337
=============== =============== ============
Changes in standardized measure:
Change due to current year operations
Sales, net of production costs $(2,185,290)
Change due to revisions in standardized variables:
Income taxes 727,245
Accretion of discount 637,560
Net change in sales and transfer price, net of production costs 2,426,491
Revision and others (3,672,014)
Discoveries 4,590,226
Changes in production rates and other (817,481)
------------
Net 1,706,737
Beginning of year 6,375,600
------------
End of year $ 8,082,337
============
F-21
HOUSTON AMERICAN ENERGY CORP.
NOTES TO THE FINANCIAL STATEMENTS
DECEMBER 31, 2006
-------------------------------
Standard measure of discounted future net cash flows at December 31, 2005
North America South America Total
--------------- --------------- ------------
Future net cash flow 7,838,800 13,738,632 21,577,432
Future production cost (3,596,700) (5,281,244) (8,877,944)
Future income tax (413,513) (3,608,140) (4,021,653)
--------------- --------------- ------------
Future net cash flow 3,828,587 4,849,248 8,677,835
10% annual discount for timing of cash flow 1,217,161 1,085,074 2,302,235
--------------- --------------- ------------
Standard measure of discounted future net
cash flow relating to proved oil and gas reserves $ 2,611,426 $ 3,764,174 $ 6,375,600
=============== =============== ============
Changes in standardized measure:
Change due to current year operations
Sales, net of production costs $(1,918,666)
Change due to revisions in standardized variables:
Income taxes (2,530,084)
Accretion of discount 517,721
Net change in sales and transfer price, net of production costs 1,332,704
Revision and others (1,374,796)
Discoveries 4,865,019
Changes in production rates and other 1,478,078
------------
Net 2,369,976
Beginning of year 4,005,624
------------
End of year $ 6,375,600
============
F-22