SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(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, 2007
[ ] 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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(Exact name of registrant specified 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 1425, 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 registered pursuant to Section 12(b) of the Act:
Name of each exchange on which
Title of each class each is registered
------------------------------ ------------------------------
Common Stock, $0.001 par value The Nasdaq Stock Market LLC
Securities registered pursuant to Section 12(g) of the Act:
None
--------------------------------
(Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer,
as defined in Rule 405 of the Securities Act.
[ ] Yes [X] No
Indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or 15(d) of the Exchange Act.
[ ] Yes [X] No
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 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.
[X] Yes [ ] No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
[X]
Indicate by check mark whether the registrant is a large accelerated
filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See definition of "accelerated filer," "large accelerated filer," and
"smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one)
Large accelerated filer [ ] Accelerated filer [ ] Non-accelerated filer [ ]
Smaller reporting company [X]
Indicate by check mark whether the registrant is a shell company (as
defined in Rule 12b-2 of the Exchange Act).
[ ] Yes [X] No
The aggregate market value of the voting and non-voting common equity
held by non-affiliates of the registrant on June 29, 2007, based on the closing
sales price of the registrant's common stock on that date, was approximately
$59,142,658. Shares of common stock held by each current executive officer and
director and by each person known by the registrant to own 5% or more of the
outstanding common stock have been excluded from this computation in that such
persons may be deemed to be affiliates.
The number of shares of the registrant's common stock, $0.001 par value,
outstanding as of February 29, 2008 was 27,920,172.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Company's Proxy Statement for its 2008 Annual Meeting are
incorporated by reference into Part III of this Report.
1
TABLE OF CONTENTS
Page
----
PART I
Item 1. Business 3
Item 1A. Risk Factors 10
Item 1B. Unresolved Staff Comments 16
Item 2. Properties 16
Item 3. Legal Proceedings 16
Item 4. Submission of Matters to a Vote of Security Holders 16
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities 17
Item 6. Selected Financial Data 17
Item 7. Management's Discussion and Analysis of Financial Conditions and
Results of Operations 18
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 24
Item 8. Financial Statements and Supplementary Data 24
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure 25
Item 9A. Controls and Procedures 25
Item 9B. Other Information 26
PART III
Item 10. Directors, Executive Officers and Corporate Governance 27
Item 11. Executive Compensation 27
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters 27
Item 13. Certain Relationships and Related Transactions, and Director Independence 27
Item 14. Principal Accountant Fees and Services 27
PART IV
Item 15. Exhibits and Financial Statement Schedules 28
2
FORWARD-LOOKING STATEMENTS
This annual report on Form 10-K 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-K.
As used in this annual report on Form 10-K, 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. 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 executive
officers, particularly John F. Terwilliger and James Jacobs, 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, 2007 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 on the South Sibley Prospect, was completed in May 2005 with
multiple pay sands 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. Between 2004 and 2005, the Hoffpauer #1
(formerly the Baronet #1) and the Baronet #2 wells were drilled and commenced
production. The Baronet #2 was reworked in 2006 and in 2007; both the Hoffpauer
#1 and the Baronet #2 were plugged and abandoned. The Baronet #3, a replacement
well for the Baronet #2, was drilled in the second quarter of 2007 and
commercial production began in July 2007. We own a 17.5% working interest and
13.125% net revenue interest in the Baronet #3 well.
CADDO PARISH, LOUISIANA. In Caddo Parish, Louisiana, we hold a 33.5% working
interest, subject to payment of 35% of the costs of the initial well, and a
25.125% net revenue interest in the 640-acre Caddo Lake Prospect with options to
additional leases covering 4,400 acres. After payout, we will own a 27.25%
working interest and 20.4375% net revenue interest in the initial well and any
additional wells. In November 2007, we drilled a 10,000-foot test well on the
Caddo Lake Prospect. At December 31, 2007, the well was awaiting a pipeline
connection prior to testing.
VERMILION PARISH, LOUISIANA. In Vermilion 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. The Weil #2 was drilled as a dry hole during 2007.
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,
2007, the DDD-Evans #1 was producing, but at non-commercial levels.
- COLOMBIAN EXPLORATION PROPERTIES:
LLANOS BASIN, COLOMBIA. In the Llanos Basin, Colombia, at December 31, 2007, we
held 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. See
"-Possible Sale of Cara Cara Concession."
Our interest in each of the described concessions and contracts in Colombia is
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 1.116% 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 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.
4
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 2007, Hupecol drilled (1) 18 wells on the Cara Cara concession with
production commencing on 13 wells and 5 of the wells being dry holes, (2) 5
wells on the Dorotea and Cabiona concessions with production commencing on 2
wells and 3 of the wells being dry holes, (3) 1 dry hole on the Las Garzas
concession, (4) 1 producing well on the Leona concession, and (5) 1 dry hole on
the Camarita concession.
2008 DRILLING PLANS
As of January 1, 2008, we plan to drill a total of 15 wells during 2008, of
which 1 well is planned to be drilled on our domestic exploration projects and
14 wells are planned to be drilled on our Colombian exploration projects. The
following table reflects planned drilling activities during 2008:
Location Prospect Name # of Planned Wells
---------------------- --------------- ----------------------
Caddo Parish, LA Caddo Lake Prospect 1
Llanos Basin, Colombia Cara Cara Concession 1
Llanos Basin, Colombia Dorotea Concession 7
Llanos Basin, Colombia Cabiona Concession 3
Llanos Basin, Colombia Las Garzas Concession 1
Llanos Basin, Colombia Leona Concession 1
Llanos Basin, Colombia Camarita Concession 1
Our planned drilling activity is subject to change from time to time without
notice. Additional wells are expected to be drilled at locations to be
determined based on the results of the planned drilling projects. See "-Possible
Sale of Cara Cara Concession."
OTHER HOLDINGS
In addition to our principal exploration projects, we hold various interests in
producing wells in Vermilion Parish, Louisiana, Plaquemines Parish, Louisiana,
Matagorda 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, 2007:
Acres Leased or Under Option at
December 31, 2007(1)
--------------------------------------------
Project
Project Area Project Gross Project Net Company Net Interest
------------------------------ ------------- --------------- ------------ -----------
TEXAS:
Jim Hogg County 340.00 340.0 14.89 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%
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%
------------- --------------- ------------
Texas Sub-Total 3,531.32 3,531.32 468.24
LOUISIANA:
Webster Parish 6,244.00 4,457.00 334.28 7.50%
Caddo Parish 5,040.00 5,040.00 1,373.40 27.25%
Vermilion Parish
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 13,034.00 11,247.00 1,750.36
OKLAHOMA
Jenny #1-14 160.00 160.00 3.78 2.36%
------------- --------------- ------------
Oklahoma Sub-Total 160.00 160.00 3.78
COLOMBIA
Cara Cara Concession 232,050.00 232,500.00 2,594.70 1.116%
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 783,457.00 783,457.00 67,200.70
------------- --------------- ------------
Total 800,182.32 798,395.32 69,423.08
============= =============== ============
(1) Project Gross Acres refers to the number of acres within a project. Project
Net Acres refers to leaseable acreage by tract. Company Net Acres are
either leased or under option in which we own an undivided interest.
Company Net Acres were determined by multiplying the Project Net Acres
leased or under option by 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 2007, we drilled 3 domestic wells and 26 wells in Colombia, consisting of 11
exploratory and 18 developmental wells of which 18 were completed and 11 were
dry holes.
The following table sets forth certain information regarding the actual drilling
results for each of the years 2007 and 2006 as to wells drilled in each such
individual year:
Exploratory Wells (1) Developmental Wells (1)
======================= =========================
Gross Net Gross Net
---------- ----------- --------- --------------
2007
----
Productive 4 0.53366 14 0.43392
Dry 7 0.56607 4 0.15848
2006
----
Productive 3 0.350 7 0.111
Dry 7 0.816 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, 2007, one well was being drilled in Colombia.
SEISMIC ACTIVITY
During 2007, we conducted no seismic operations.
PRODUCTIVE WELL SUMMARY
The following table sets forth certain information regarding our ownership as of
December 31, 2007 of productive gas and oil wells in the areas indicated:
Gas Oil
-------------- --------------
Gross Net Gross Net
----- ------- ----- -------
Texas 2 0.07875 1 0.10
Louisiana 5 0.56300 0 0
Oklahoma 1 0.02360 0 0
Colombia 0 0 39 1.00444
----- ------- ----- -------
Total 8 0.66535 40 1.10444
===== ======= ===== =======
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,
------------------------
2007 2006
---------- ------------
Net Production:
Gas (Mcf):
North America 44,250 78,096
South America 0 0
Oil (Bbls):
North America 2,078 1,687
South America 69,127 48,058
Average sales price:
Gas ($per Mcf) 6.90 6.75
Oil ($per Bbl) 65.61 55.55
Average production expense and Taxes ($per Bbls):
North America 13.80 9.52
South America 24.75 17.04
NATURAL GAS AND OIL RESERVES
The following table summarizes the estimates of our historical net proved
reserves as of December 31, 2007 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:
At December 31,
-----------------------
2007 2006
----------- ----------
Net proved reserves (1):
Natural gas (Mcf) 135,649 425,750
Oil (Bbls) 1,285,239 392,356
Standardized measure of discounted future
net cash flows (2) $70,107,827 $8,082,337
(1) At December 31, 2007, net proved reserves, by region, consisted of
1,281,227 barrels of oil in South America and 4,012 barrels of oil in North
America; all natural gas reserves were in North America.
(2) The standardized measure of discounted future net cash flows represents the
present value of future net revenues after income tax discounted at 10% per
annum and has been calculated in accordance with SFAS No. 69, "Disclosures
About Oil and Gas Producing Activities" (see Note 7 - Supplemental
Information on Oil and Gas Exploration, Development and Production
Activities (Unaudited)) and in accordance with current SEC guidelines, and
does not include estimated future cash inflows from hedging. The
standardized measure of discounted future net cash flows attributable to
our reserves was prepared using prices in effect at the end of the
respective periods presented, discounted at 10% per annum on a pre-tax
basis.
8
In accordance with applicable requirements of the Securities and Exchange
Commission, we estimate our proved reserves and future net cash flows using
sales prices and costs estimated to be in effect as of the date we make the
reserve estimates. We hold the estimates constant throughout the life of the
properties, except to the extent a contract specifically provides for
escalation. Gas prices, which have fluctuated widely in recent years, affect
estimated quantities of proved reserves and future net cash flows. Any
estimates of natural gas and oil reserves and their values are inherently
uncertain, including many factors beyond our control. The reserve data
contained in this 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, 2007, 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 1,210.38 51.30 0 0 2,320.94 416.94
Louisiana 3,670.00 313.08 0 0 9,364.00 1437.28
Oklahoma 160.00 3.78 0 0 0 0
Colombia 12,160.00 281.42 2,240.00 134.28 769,057.00 66,785.00
--------- -------- --------- --------- ---------- ---------
Total 17,200.38 649.58 2,240.00 134.28 780,741.94 68,639.22
========= ======== ========= ========= ========== =========
During 2007, we acquired interests in the 640 acre Caddo Lake Prospect in Caddo
Parish, Louisiana with an option to acquire additional leases covering 4,400
acres. During 2007, we relinquished interests in various leases in Texas
covering approximately 664 gross acres and 80 net acres and leases in Louisiana
covering approximately 425 gross acres and 35 net acres. Also during 2007, a
30% interest in our Cara Cara Concession reverted to Ecopetrol pursuant to the
terms of the concession, reducing our interest in the concession from
approximately 1.59% to 1.116% and resulting in an approximately 1,094 acre
reduction in our net acreage in Colombia.
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, 2008, we had no contractual agreements to sell our gas and oil
production and all production was sold on spot markets.
9
POSSIBLE SALE OF CARA CARA CONCESSION
On July 17, 2007, our management was advised that Hupecol LLC had retained an
investment bank for purposes of evaluating a possible transaction involving the
monetization of Hupecol assets. Pursuant to that engagement, in March 2008,
Hupecol Caracara LLC, as owner/operator under the Caracara Association Contract,
entered into a Purchase and Sale Agreement to sell all of its interest in the
Caracara Association Contract and related assets for a sale price of $920
million, subject to certain closing adjustments based on oil price fluctuations
and operations between the effective date of the sale, January 1, 2008, and the
closing date. Pursuant to our investment in Hupecol Caracara LLC, we hold a
1.594674% interest in the Caracara assets being sold and will receive our
proportionate interest in the net sale proceeds after deduction of commissions
and transaction expenses.
Completion of the sale of the Caracara assets is subject to satisfaction of
various conditions set out in the Purchase and Sale Agreement, including the
granting of all consents and approvals of the Colombian governmental authorities
required for the transfer of the assets to the purchaser.
EMPLOYEES
As of March 1, 2008, 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 1A. RISK FACTORS
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.
10
A SUBSTANTIAL PERCENTAGE OF OUR PROPERTIES ARE UNDEVELOPED; THEREFORE THE RISK
ASSOCIATED WITH OUR SUCCESS IS GREATER THAN WOULD BE THE CASE IF THE MAJORITY OF
OUR PROPERTIES WERE CATEGORIZED AS PROVED DEVELOPED PRODUCING.
Because a substantial percentage of our properties are unproven 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 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
11
oil and natural gas prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds. Therefore, estimates of oil and
natural gas reserves are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable oil
and natural gas reserves most likely will vary from our estimates. Any
significant variance could materially affect the estimated quantities and
present value of our reserves. In addition, we may adjust estimates of proved
reserves to reflect production history, results of exploration and development,
prevailing oil and natural gas prices and other factors, many of which are
beyond our control.
You should not assume that the present value of future net revenues from our
proved reserves, as reported from time to time, is the current market value of
our estimated oil and natural gas reserves. In accordance with SEC requirements,
we generally base the estimated discounted future net cash flows from our proved
reserves on prices and costs on the date of the estimate. Actual future prices
and costs may differ materially from those used in the present value estimate.
If future values decline or costs increase it could negatively impact our
ability to finance operations, and individual properties could cease being
commercially viable, affecting our decision to continue operations on producing
properties or to attempt to develop properties. All of these factors would have
a negative impact on earnings and net income, and most likely the trading price
of our securities.
WE ARE DEPENDENT UPON THIRD PARTY OPERATORS OF OUR OIL AND GAS PROPERTIES.
Under the terms of the Operating Agreements related to our oil and gas
properties, third parties act as the operator of our oil and gas wells and
control the drilling activities to be conducted on our properties. Therefore, we
have limited control over certain decisions related to activities on our
properties, which could affect our results of operations. Decisions over which
we have limited control include:
- the timing and amount of capital expenditures;
- the timing of initiating the drilling and recompleting of wells;
- the extent of operating costs; and
- the level of ongoing production.
PROSPECTS THAT WE DECIDE TO DRILL MAY NOT YIELD OIL OR NATURAL GAS IN
COMMERCIALLY VIABLE QUANTITIES.
Our prospects are properties on which we have identified what we believe, based
on available seismic and geological information, to be indications of oil or
natural gas. Our prospects are in various stages of evaluation, ranging from a
prospect that is ready to drill to a prospect that will require substantial
additional seismic data processing and interpretation. There is no way to
predict in advance of drilling and testing whether any particular prospect will
yield oil or natural gas in sufficient quantities to recover drilling or
completion costs or to be economically viable. This risk may be enhanced in our
situation, due to the fact that a significant percentage 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.
12
Any of these risks could adversely affect our ability to conduct operations or
result in substantial losses to our company. We may elect not to obtain
insurance if we believe that the cost of available insurance is excessive
relative to the risks presented. In addition, pollution and environmental risks
generally are not fully insurable. If a significant accident or other event
occurs and is not fully covered by insurance, then it could adversely affect us.
WE ARE SUBJECT TO COMPLEX LAWS THAT CAN AFFECT THE COST, MANNER OR FEASIBILITY
OF DOING BUSINESS.
Exploration, development, production and sale of oil and natural gas are subject
to extensive federal, state, local and international regulation. We may be
required to make large expenditures to comply with governmental regulations.
Matters subject to regulation include:
- discharge permits for drilling operations;
- drilling bonds;
- reports concerning operations;
- the spacing of wells;
- unitization and pooling of properties; and
- taxation.
Under these laws, we could be liable for personal injuries, property damage and
other damages. Failure to comply with these laws also may result in the
suspension or termination of our operations and subject us to administrative,
civil and criminal penalties. Moreover, these laws could change in ways that
substantially increase our costs. Any such liabilities, penalties, suspensions,
terminations or regulatory changes could materially adversely affect our
financial condition and results of operations.
OUR OPERATIONS MAY INCUR SUBSTANTIAL LIABILITIES TO COMPLY WITH THE
ENVIRONMENTAL LAWS AND REGULATIONS.
Our oil and natural gas operations are subject to stringent federal, state and
local laws and regulations relating to the release or disposal of materials into
the environment or otherwise relating to environmental protection. These laws
and regulations may require the acquisition of a permit before drilling
commences, restrict the types, quantities and concentration of substances that
can be released into the environment in connection with drilling and production
activities, limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas, and impose substantial
liabilities for pollution resulting from our operations. Failure to comply with
these laws and regulations may result in the assessment of administrative, civil
and criminal penalties, incurrence of investigatory or remedial obligations or
the imposition of injunctive relief. Changes in environmental laws and
regulations occur frequently, and any changes that result in more stringent or
costly waste handling, storage, transport, disposal or cleanup requirements
could require us to make significant expenditures to maintain compliance, and
may otherwise have a material adverse effect on our results of operations,
competitive position or financial condition as well as the industry in general.
Under these environmental laws and regulations, we could be held strictly liable
for the removal or remediation of previously released materials or property
contamination regardless of whether we were responsible for the release or if
our operations were standard in the industry at the time they were performed.
OUR OPERATIONS IN COLOMBIA ARE SUBJECT TO RISKS RELATING TO POLITICAL AND
ECONOMIC INSTABILITY.
We currently have interests in multiple oil and gas concessions in Colombia and
anticipate that operations in Colombia will constitute a substantial element of
our strategy going forward. The political climate in Colombia is unstable and
could be subject to radical change over a very short period of time. In the
event of a significant negative change in the political or economic climate in
Colombia, we may be forced to abandon or suspend our operations in Colombia.
OUR OPERATIONS IN COLOMBIA ARE CONTROLLED BY HUPECOL WHICH MAY CARRY OUT
TRANSACTIONS AFFECTING OUR COLOMBIAN ASSETS AND OPERATIONS WITHOUT OUR CONSENT.
We are an investor in Hupecol and our interest in the assets and operations of
Hupecol represent all of our assets and operations in Colombia and are our
principal assets and operations. On July 17, 2007, Hupecol advised us that it
had retained an investment bank for purposes of evaluating a possible
transaction involving monetization of Hupecol's assets. In March 2008, Hupecol
Caracara LLC, as owner/operator of the Caracara Association Contract, entered
into a Purchase and Sale Agreement to sell all of its interest in the Caracara
prospect. If that transaction is completed, we will receive our proportionate
interest in the net sale proceeds and will relinquish
13
all of our interest in the Caracara prospect. There is no assurance as to when,
or if, the planned sale of the Caracara prospect will be completed. If the
planned sale is completed there is no assurance that we will be able to reinvest
the proceeds received in a manner that will adequately replace the revenues
generated by, and the reserves attributable to, the Caracara prospect. Further,
it is possible that Hupecol will carry out similar sales in the future. Our
management intends to closely monitor the nature and progress of future
transactions by Hupecol in order to protect our interests. However, we have no
effective ability to alter or prevent a transaction and are unable to predict
whether or not any such transactions will in fact occur or the nature or timing
of any such transaction.
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.
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.
14
WE MAY NEED ADDITIONAL FINANCING TO SUPPORT OPERATIONS AND FUTURE CAPITAL
COMMITMENTS.
While we presently believe that our operating cash flows and funds on hand will
support our ongoing operations and anticipated future capital requirements, a
number of factors could result in our needing additional financing, including
reductions in oil and natural gas prices, declines in production, unexpected
developments in operations that could decrease our revenues, increase our costs
or require additional capital contributions and commitments to new acquisition
or drilling programs. We have no commitments to provide any additional
financing, if needed, and may be limited in our ability to obtain the capital
necessary to support operations, complete development, exploitation and
exploration programs or carry out new acquisition or drilling programs. We have
not thoroughly investigated whether this capital would be available, who would
provide it, and on what terms. If we are unable, on acceptable terms, to raise
the required capital, our business may be seriously harmed or even terminated.
COMPETITION IN THE OIL AND NATURAL GAS INDUSTRY IS INTENSE, WHICH MAY ADVERSELY
AFFECT OUR ABILITY TO COMPETE.
We operate in a highly competitive environment for acquiring properties,
marketing oil and natural gas and securing trained personnel. Many of our
competitors possess and employ financial, technical and personnel resources
substantially greater than ours, which can be particularly important in the
areas in which we operate. Those companies may be able to pay more for
productive oil and natural gas properties and exploratory prospects and to
evaluate, bid for and purchase a greater number of properties and prospects than
our financial or personnel resources permit. Our ability to acquire additional
prospects and to find and develop reserves in the future will depend on our
ability to evaluate and select suitable properties and to consummate
transactions in a highly competitive environment. Also, there is substantial
competition for capital available for investment in the oil and natural gas
industry. We may not be able to compete successfully in the future in acquiring
prospective reserves, developing reserves, marketing hydrocarbons, attracting
and retaining quality personnel and raising additional capital.
THE PRICE OF OUR COMMON STOCK MAY FLUCTUATE SIGNIFICANTLY, AND THIS MAY MAKE IT
DIFFICULT FOR YOU TO RESELL COMMON STOCK WHEN YOU WANT OR AT PRICES YOU FIND
ATTRACTIVE.
The price of our common stock 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
15
availability of shares of common stock for future sale, will have on the trading
price of our common stock.
OUR CHARTER AND BYLAWS, AS WELL AS PROVISIONS OF DELAWARE LAW, COULD MAKE IT
DIFFICULT FOR A THIRD PARTY TO ACQUIRE OUR COMPANY AND ALSO COULD LIMIT THE
PRICE THAT INVESTORS ARE WILLING TO PAY IN THE FUTURE FOR SHARES OF OUR COMMON
STOCK.
Delaware corporate law and our charter and bylaws contain provisions that could
delay, deter or prevent a change in control of our company or our management.
These provisions could also discourage proxy contests and make it more difficult
for our stockholders to elect directors and take other corporate actions without
the concurrence of our management or board of directors. These provisions:
- authorize our board of directors to issue "blank check" preferred
stock, which is preferred stock that can be created and issued by our
board of directors, without stockholder approval, with rights senior
to those of our common stock;
- provide for a staggered board of directors and three-year terms
for directors, so that no more than one-third of our directors could
be replaced at any annual meeting;
- provide that directors may be removed only for cause; and
- establish advance notice requirements for submitting nominations
for election to the board of directors and for proposing matters that
can be acted upon by stockholders at a meeting.
We are also subject to anti-takeover provisions under Delaware law, which could
also delay or prevent a change of control. Taken together, these provisions of
our charter and bylaws, Delaware law may discourage transactions that otherwise
could provide for the payment of a premium over prevailing market prices of our
common stock and also could limit the price that investors are willing to pay in
the future for shares of our common stock.
OUR MANAGEMENT OWNS A SIGNIFICANT AMOUNT OF OUR COMMON STOCK, GIVING THEM
INFLUENCE OR CONTROL IN CORPORATE TRANSACTIONS AND OTHER MATTERS, AND THEIR
INTERESTS COULD DIFFER FROM THOSE OF OTHER SHAREHOLDERS.
At March 1, 2008, our directors and executive officers owned approximately 46.5
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.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable
ITEM 2. PROPERTIES
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.
Business."
ITEM 3. LEGAL PROCEEDINGS
We may from time to time be a party to lawsuits incidental to our business. As
of March 1, 2008, 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
Not applicable
16
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed on the Nasdaq Capital Market ("Nasdaq") under the
symbol "HUSA." From July 28, 2006 until July 5, 2007, our common stock traded
on the American Stock Exchange and prior to July 28, 2006 traded on the
over-the-counter electronic bulletin board. The following table sets forth the
range of high and low sale prices of our common stock for each quarter during
the past two fiscal years.
High Low
----- -----
Calendar Year 2007 Fourth Quarter $4.44 $2.46
Third Quarter 6.10 2.29
Second Quarter 6.14 4.71
First Quarter 7.35 3.23
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
At February 29, 2008, the closing price of the common stock on Nasdaq was $4.27.
As of February 29, 2008, 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, 2007 with respect to
the shares of our common stock that may be issued under our existing equity
compensation plans.
NUMBER OF SECURITIES NUMBER OF SECURITIES
TO BE ISSUED UPON WEIGHTED-AVERAGE REMAINING AVAILABLE FOR
EXERCISE OF EXERCISE PRICE OF FUTURE ISSUANCE UNDER
OUTSTANDING OPTIONS, OUTSTANDING OPTIONS, EQUITY COMPENSATION PLANS
WARRANTS AND WARRANTS AND (EXCLUDING SECURITIES
PLAN CATEGORY RIGHTS (A) RIGHTS (B) REFLECTED IN COLUMN (A))
---------------------------------- --------------------- --------------------- --------------------------
Equity compensation plans
approved by security holders (1) 339,000 3.12 161,000
Equity compensation plans not
approved by security holders - - -
--------------------- --------------------- --------------------------
Total 339,000 3.12 161,000
===================== ===================== ==========================
(1) Consists of 500,000 shares reserved for issuance under the Houston American
Energy Corp. 2005 Stock Option Plan. The stock option plan was adopted by
the board of directors in August 2005 and approved by shareholders in
January 2006.
ITEM 6. SELECTED FINANCIAL DATA
Not applicable
17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
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 over 30 years. In the fourth quarter 2002, we initiated
international efforts through a Colombian joint venture more fully described
below. Domestically and internationally, the strategy is to be a non-operating
partner with exploration and production companies that have much larger
resources and operations.
OVERVIEW OF OPERATIONS
Our operations are exclusively devoted to natural gas and oil exploration and
production.
Our focus, to date and for the foreseeable future, is the identification of oil
and gas drilling prospects and participation in the drilling and production of
prospects. We typically identify prospects and assemble various drilling
partners to participate in, and fund, drilling activities. We may retain an
interest in a prospect for our services in identifying and assembling prospects
without any contribution on our part to drilling and completion costs or we may
contribute to drilling and completion costs based on our proportionate interest
in a prospect.
We derive our revenues from our interests in oil and gas production sold from
prospects in which we own an interest, whether through royalty interests,
working interest or other arrangements. Our revenues vary directly based on a
combination of production volumes from wells in which we own an interest, market
prices of oil and natural gas sold and our percentage interest in each prospect.
Our well operating expenses vary depending upon the nature of our interest in
each prospect. We may bear no interest or a proportionate interest in the costs
of drilling, completing and operating prospects on which we own an interest.
Other than well drilling, completion and operating expenses, our principal
operating expenses relate to our efforts to identify and secure prospects,
comply with our various reporting obligations as a publicly held company and
general overhead expenses.
BUSINESS DEVELOPMENTS DURING 2007
Drilling Activities
During 2007, we drilled 26 international wells in Colombia, as follows:
- 8 wells were drilled on concessions in which we hold a 12.5%
working interest, of which 1 was in production as of December 31,
2007, 2 were temporarily shut in due to mechanical problems or weather
conditions and 5 were either dry holes or were ultimately abandoned,
including 1 well that was converted to a water disposal well.
- 18 wells were drilled on concessions in which we hold a 1.116%
working interest, of which 13 were in production as of December 31,
2007 and 5 were dry holes.
During 2007, we drilled three domestic wells, of which 1 was in production as of
December 31, 2007, 1 was a dry hole and 1 was awaiting a pipeline connection
before testing and completion.
At December 31, 2007, we had 1 well in Colombia being drilled and no domestic
wells being drilled.
Leasehold Activity
During 2007, we acquired an interest in a 640-acre prospect known as the Caddo
Lake Prospect in Caddo Parish, Louisiana with a right to participate in drilling
on an additional 4,400 acres. We paid 35% of the costs of the initial well
drilled on the Caddo Lake Prospect and have a 33.5% Working Interest (25.125%
Net Revenue Interest) until well payout. After well payout, we will own a 27.25%
Working Interest and 20.4375% Net Revenue Interest. On all additional well costs
after the initial well and on all additional lease costs, we will have a 27.25%
Working Interest with a 20.4375% Net Revenue Interest.
18
During 2007, we relinquished interests in various leases in Texas covering
approximately 664 gross acres and 80 net acres and leases in Louisiana covering
approximately 425 gross acres and 35 net acres. Also during 2007, a 30%
interest in our Cara Cara Concession reverted to Ecopetrol pursuant to the terms
of the concession, reducing our interest in the concession from approximately
1.59% to 1.116% and resulting in an approximately 1,094 acre reduction in our
net acreage in Colombia.
Seismic Activity
During 2007, we conducted no new seismic activity.
Possible Sale of Cara Cara Concession
On July 17, 2007, our management was advised that Hupecol LLC had retained an
investment bank for purposes of evaluating a possible transaction involving the
monetization of Hupecol assets. Pursuant to that engagement, in March 2008,
Hupecol Caracara LLC, as owner/operator under the Caracara Association Contract,
entered into a Purchase and Sale Agreement to sell all of its interest in the
Caracara Association Contract and related assets for a gross sale price of $920
million, subject to certain closing adjustments based on oil price fluctuations
and operations between the effective date of the sale, January 1, 2008, and the
closing date. Pursuant to our investment in Hupecol Caracara LLC, we hold a
1.594674% interest in the Caracara assets being sold and will receive our
proportionate interest in the net sale proceeds after deduction of commissions
and transaction expenses.
Completion of the sale of the Caracara assets is subject to satisfaction of
various conditions set out in the Purchase and Sale Agreement, including the
granting of all consents and approvals of the Colombian governmental authorities
required for the transfer of the assets to the purchaser.
Hupecol Tax Allocation Credits
In August 2007, we were advised that Hupecol would be adjusting the division of
interests among the members of the various Hupecol entities to reflect revised
Colombian tax allocations among the various Hupecol entities. Specifically,
Hupecol advised that Colombian tax attributes were allocated among the Hupecol
entities without taking into account the specific contributions of each
individual entity resulting in an improper shifting of tax expenses and benefits
among the Hupecol entities and, in turn, the members of each of the Hupecol
entities, including our company.
As a result of the adjustment by Hupecol, during 2007, we received a net credit
from Hupecol for excess Colombian taxes allocated to us in the amount of
$662,688. The credit is reflected in our financial statements as a credit to
income tax expense.
Corporate Developments
During 2007, our compensation committee engaged a compensation consultant, as
called for by the terms of employment of our chief financial officer, to review
the compensation arrangements of our senior executives with a view to adjusting
such compensation to reflect industry compensation practices. Following that
review, the compensation committee approved increases in base salary of our
chief executive officer and our chief financial officer, the payment of one-time
cash bonuses to each and the grant of shares of restricted stock to each, which
grants are subject to approval of the same by our shareholders.
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. 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
19
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, 2007. 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 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, 2007 and 2006:
At December 31, 2007 At December 31, 2006
===================== =====================
Acquisition costs $ 192,843 $ 180,197
Evaluation costs 719,102 520,352
Retention costs 86,861 0
--------------------- ---------------------
Total $ 998,806 $ 700,549
===================== =====================
The carrying value of unevaluated oil and gas prospects include $13,330 and
$480,532 expended for properties in South America at December 31, 2007 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."
We 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
We identified the conversion feature; the conversion price reset feature and our
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 our 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."
20
We identified the common stock warrant to be a detachable derivative. The
warrant exercise price reset provision was identified as 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 our income statement as "Net change in fair
value of derivative liabilities." We 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 was subject to the changes in the
trading value of our common stock. As a result, our financial statements were
subject to fluctuations from quarter-to-quarter based on factors, such as the
price of our 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 our 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, 2007 COMPARED TO YEAR ENDED DECEMBER 31, 2006
Oil and Gas Revenues. Total oil and gas revenues increased $1,774,441, or
55.4%, to $4,977,172 in fiscal 2007 compared to $3,202,731 in fiscal 2006. The
increase in revenue is due to (a) increased production resulting from the
development of the Colombian fields and (b) increases in oil and natural gas
prices, partially offset by declines in U.S. production. We had interests in 39
producing wells in Colombia and 7 producing wells in North America during 2007
as compared to 22 producing wells in Colombia and 11 producing wells in North
America during 2006. Average prices from sales were $65.61 per barrel of oil
and $6.90 per mcf of gas during 2007 as compared to $55.55 per barrel of oil and
$6.75 per mcf of gas during 2006. Following is a summary comparison, by region,
of oil and gas sales for the periods.
North
Colombia America Total
---------- -------- ----------
Year ended 2007
Oil sales $4,531,640 $140,313 $4,671,953
Gas sales 0 305,219 305,219
Year ended 2006
Oil sales $2,565,105 $ 95,363 $2,660,468
Gas sales 0 542,263 542,263
Lease Operating Expenses. Lease operating expenses, excluding joint venture
expenses relating to our Colombia operations discussed below, increased 81% to
$1,841,119 in 2007 from $1,017,440 in 2006. The increase in lease operating
expenses was attributable to the increase in the number of wells operated during
2007 (46 wells as compared to 33 wells) partially offset by improved operating
efficiencies. Additionally operations have increased in workovers as well as in
the Dorotea and Cabiona areas where we have a higher working interest (12.5%),
which increased the amount of operating expense we incurred during the period.
21
Following is a summary comparison of lease operating expenses for the years
ended December 31, 2007 and 2006.
North
Colombia America Total
---------- -------- ----------
Year ended 2007 $1,710,689 $130,430 $1,841,119
Year ended 2006 819,273 198,167 1,017,440
Joint Venture Expenses. Joint venture expenses totaled $149,200 in 2007
compared to $167,023 in 2006. 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 decrease in
joint venture expenses was attributable to the operator reducing the personnel
working on undrilled contract areas.
Depreciation and Depletion Expense. Depreciation and depletion expense
increased by 23.9% to $1,099,826 in fiscal 2007 when compared to $887,911 in
2006. The increase in depreciation and depletion expense was primarily
attributable to increases in Colombian production and an 82% increase in the
depletable cost pool.
Impairment Expense. During 2007, we recorded a provision for impairments of
$348,019, all of which was attributable to our North American properties.
Impairments related to the termination, during 2007, of operations of seven
wells in the U.S. and the fact that, as of December 31, 2007, well testing had
not yet been conducted on, and no reserves had been attributed to, the well
drilled during 2007 on our Caddo Lake Prospect.
General and Administrative Expenses. General and administrative expense
(excluding stock based compensation) increased by 31.0% to $1,233,020 during
2007 from $941,324 in 2006. The increase in general and administrative expense
was primarily attributable to an increase in salary to our president in
mid-2006, payment of a full year's salary to our chief financial officer hired
during 2006, increases in base salary of our president and chief financial
officer during the third quarter of 2007 and payment of bonuses to our president
and chief financial officer during 2007.
Stock based compensation expense included in general and administrative expenses
increased by 15.7% to $335,208 in 2007 as compared to 289,755 in 2006. The
increase in stock-based compensation expense was attributable to the 2006 grant
of stock options in connection with the hiring of our chief financial officer
and the grants of options to our directors during 2007.
Other Income, Net. Other income, 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 and outstanding during part of 2006. 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, net, totaled $649,792 in 2007 compared to $99,263 in 2006. The
improvement in other income, net, was attributable to interest earned on funds
received from the 2006 private placement and the absence of interest expense,
financing fees and derivative related expense during 2007 attributable to the
retirement or conversion during 2006 of all outstanding shareholder loans and
convertible notes.
Income Tax Expense (Benefit). Income tax expense decreased to $127,116 in 2007
from $510,637 in 2006. The decrease in income tax expense during 2007 was
attributable to the gain of $662,668 associated with the reallocation of the
Hupecol tax credits discussed above, partially offset by an increase in revenue
and an effective tax rate increase in Colombia. Income tax expense during 2007
and 2006 was entirely attributable to operations in Colombia. We recorded no
U.S. income tax liability in 2007 or 2006. At December 31, 2007, we had net
operating loss carry forward of approximately $832,821 and foreign tax credits
of approximately $875,873.
FINANCIAL CONDITION
Liquidity and Capital Resources. At December 31, 2007, we had a cash balance of
$417,818 and working capital of $10,358,502 compared to a cash balance of
$409,008 and working capital of $14,314,190 at December 31, 2006. The changes
in cash and working capital during the period were primarily attributable to the
payment of drilling costs.
Cash Flows. Operating cash flows for 2007 totaled $1,801,481 as compared to
$1,239,446 during 2006. The increase in operating cash flow was primarily
attributable to increased revenues from oil and gas sales partially
22
offset by increased lease operating expenses and general and administrative
expenses and reductions in payables and accrued expenses.
Investing activities used $1,792,672 during 2007 as compared to $17,507,371 used
during 2006. The decrease in cash flows used by investing activities during
2007 was primarily attributable to the temporary net investment of $14,000,000
in marketable securities during 2006 as compared to the sale of $7,500,000 of
those marketable securities during 2007, offset by the purchase of $3,150,000 of
marketable securities in 2007 and investments in oil and gas acquisition and
drilling activities of $6,142,672 during 2007 as compared to $3,507,371 in 2006.
Financing activities provided $0 during 2007 as compared to $14,952,833 during
2006. 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.
Long-Term Liabilities. At December 31, 2007, we had long-term liabilities of
$135,267 as compared to $38,816 at December 31, 2006. Long-term liabilities at
December 31, 2007 and December 31, 2006 consisted of a reserve for plugging
costs and deferred rent liability.
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 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 2007, we invested $6,142,672 for the acquisition and development of oil
and gas properties, primarily consisting of (1) drilling of 3 domestic wells
($1,799,792), (2) drilling 26 wells in Colombia ($4,247,009), and (3) lease
retention payments on domestic properties ($95,871).
At December 31, 2007, our only material contractual obligation requiring
determinable future payments on our part was our lease relating to our executive
offices.
The following table details our contractual obligations as of December 31, 2007:
Payments due by period
-----------------------------------------------------
Total 2008 2009 - 2010 2011 - 2012 Thereafter
------- ------ ----------- ----------- ----------
Operating leases 369,050 79,576 166,260 123,214 0
------- ------ ----------- ----------- ----------
Total 369,050 79,576 166,260 123,214 0
======= ====== =========== =========== ==========
In addition to the contractual obligations requiring that we make fixed
payments, in conjunction with our efforts to secure oil and gas prospects,
financing and services, we have, from time to time, granted overriding royalty
interests (ORRI) in various properties, and may grant ORRIs in the future,
pursuant to which we will be obligated to pay a portion of our interest in
revenues from various prospects to third parties.
2008 Planned Drilling, Leasehold and Other Activities. As of December 31, 2007,
we planned to drill a total of 15 wells during 2008, of which 1 well is planned
to be drilled on our domestic exploration projects and 14 wells are planned to
be drilled on our Colombian exploration projects. The following table reflects
planned drilling activities during 2008:
Location Prospect Name # of Planned Wells
---------------------- --------------------- ------------------
Caddo Parish, LA Caddo Lake Prospect 1
Llanos Basin, Colombia Cara Cara Concession 1
Llanos Basin, Colombia Dorotea Concession 7
Llanos Basin, Colombia Cabiona Concession 3
Llanos Basin, Colombia Las Garzas Concession 1
Llanos Basin, Colombia Leona Concession 1
Llanos Basin, Colombia Camarita Concession 1
23
Additional wells are expected to be drilled at locations to be determined based
on the results of the planned drilling projects. Our planned drilling activity
is subject to change from time to time without notice. In particular, we cannot
predict the impact on our planned drilling activities in Colombia of ongoing
efforts by Hupecol to monetize assets.
We also plan to selectively evaluate and acquire interests in additional
drilling prospects.
At December 31, 2007, our acquisition and drilling budget for 2008 totaled
approximately $6,270,000, consisting of (1) $4,090,000 for drilling of 14 wells
in Colombia, (2) $545,000 for drilling of 1 domestic well, (3) $385,000 for
seismic operations in Colombia, and (4) $1,250,000 for road construction and
facilities 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 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, 2007.
INFLATION
We believe that inflation has not had a significant impact on our operations
since inception.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY PRICE RISK
The price we receive for our oil and gas production heavily influences our
revenue, profitability, access to capital and future rate of growth. Crude 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 gas have been volatile, and these markets
will likely continue to be volatile in the future. The prices we receive for
production depends on numerous factors beyond our control.
We have not historically entered into any hedges or other transactions designed
to manage, or limit exposure to oil and gas price volatility.
INTEREST RATE RISK
We invest funds in excess of projected short-term needs in interest rate
sensitive securities, primarily fixed maturity securities. While it is generally
our intent to hold our fixed maturity securities to maturity, we have classified
a majority of our fixed maturity portfolio as available-for-sale. In accordance
with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity
Securities," our available-for-sale fixed maturity securities are carried at
fair value on the balance sheet with unrealized gains or losses reported net of
tax in accumulated other comprehensive income.
Increases and decreases in prevailing interest rates generally translate into
decreases and increases in fair values of fixed maturity securities.
Additionally, fair values of interest rate sensitive instruments may be affected
by the creditworthiness of the issuer, prepayment options, relative values of
alternative investments, the liquidity of the instrument and other general
market conditions. Because of the short-term nature of the interest bearing
investments, the quality of the issuers and the intent to hold those investments
to maturity, we do not believe we face any material interest rate risk with
respect to such investments.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our financial statements appear immediately after the signature page of this
report. See "Index to Financial Statements" on page 30 of this report.
24
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Previously disclosed. See Form 8-K, filed April 19, 2007.
ITEM 9A(T). CONTROLS AND PROCEDURES
CORPORATE DISCLOSURE CONTROLS
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures are controls and other procedures of a
registrant designed to ensure that information required to be disclosed by the
registrant in the reports that it files or submits under the exchange Act is
properly recorded, processed, summarized, and reported, within the time periods
specified in the Securities and Exchange Commission's ("SEC") rules and forms.
Disclosure controls and procedures are performed under the supervision and with
the participation of our Chief Executive Officer and Chief Financial Officer to
allow for timely decisions regarding required disclosures.
We evaluated the effectiveness of the design and operation of our disclosure
controls and procedures as of December 31, 2007, as required by Rule 13a-15 of
the Exchange Act. As described below, under "Management's Report on Internal
Control Over Financial Reporting," material weaknesses were identified in our
internal control over financial reporting as of December 31, 2007, relating to
segregation of duties and review and approval of bank reconciliations. Based on
the evaluation described above, our Chief Executive Officer and Chief Financial
Officer have concluded that, as of December 31, 2007, our disclosure controls
and procedures were not effective in ensuring that the information required to
be disclosed by us in reports filed under the Securities Exchange Act of 1934 is
recorded, processed, summarized and reported within the time periods specified
in the rules and forms of the SEC. To address the material weakness, we
performed additional analysis in an effort to ensure our consolidated financial
statements included in this annual report have been prepared in accordance with
generally accepted accounting principles. Accordingly, management believes that
the financial statements included in this report fairly present in all material
respects our financial condition, results of operations and cash flows for the
periods presented.
Management's Report on Internal Control over Financial Reporting
As of December 31, 2007, Houston American Energy Corporation does not meet the
definition of "accelerated filer," as described by Rule 12b-2 of the Exchange
Act. We are required by the Sarbanes-Oxley Act of 2002 to include an assessment
of our internal control over financial reporting for the year ended December 31,
2007. Our management is responsible for establishing and maintaining adequate
internal control over financial reporting as that term is defined in Exchange
Act Rule 13a-15(f). Our internal control over financial reporting is a process
designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of our financial statements for external reporting
purposes in accordance with generally accepted accounting principles ("GAAP").
Our internal control over financial reporting includes those policies and
procedures that (i) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect our transactions and dispositions of our
assets; (ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of our financial statements in accordance with
GAAP, and that our receipts and expenditures are being made only in accordance
with authorizations of our management and directors; and (iii) provide
reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use or disposition of our assets that could have a material effect
on our financial statements.
Internal control over financial reporting cannot provide absolute assurance of
achieving financial reporting objectives because of its inherent limitations.
Internal control over financial reporting is a process that involves human
diligence and compliance and is subject to lapses in judgment and breakdowns
resulting from human failures. Internal control over financial reporting also
can be circumvented by collusion or improper management override. Because of
such limitations, there is a risk that material misstatements may not be
prevented or detected on a timely basis by internal control over financial
reporting. However, these inherent limitations are known features of the
financial reporting process. Therefore, it is possible to design into the
process safeguards to reduce, though not eliminate, this risk. In addition,
projections of any evaluation of effectiveness to future periods are subject to
the risk that controls may become inadequate because of changes in conditions or
that the degree of compliance with the policies or procedures may deteriorate.
In order to evaluate the effectiveness of our internal control over financial
reporting as of December 31, 2007, as required by Section 404 of the
Sarbanes-Oxley Act of 2002, our management conducted an assessment, including
25
testing, based on the criteria set forth in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (the "COSO Framework"). A material weakness is a control deficiency,
or a combination of control deficiencies, that results in more than a remote
likelihood that a material misstatement of our annual or interim financial
statements will not be prevented or detected. In assessing the effectiveness of
our internal control over financial reporting, management identified the
following two material weaknesses in internal control over financial reporting
as of December 31, 2007:
1. Deficiencies in Segregation of Duties. 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. There is a risk that a material
misstatement of the financial statements could be caused, or at least
not be detected in a timely manner, due to insufficient segregation of
duties.
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.
2. Deficiencies in the Company's treasury process controls. We did
not consistently review bank reconciliations prepared by the part-time
consultant. The Company failed to perform certain control procedures
designed to ensure that the bank reconciliations were accurate and
timely. There is a risk that a material misstatement of the financial
statements could be caused, or at least not be detected in a timely
manner, by this failure to review the bank reconciliation. We plan to
implement a formal process for timely review and approval of bank
reconciliations. The Company will monitor the effectiveness of this
action and will make any other changes and take such other actions as
management determines to be appropriate.
Based on the material weaknesses described above and the criteria set forth by
the COSO Framework, we have concluded that our internal control over financial
reporting at December 31, 2007, was not effective.
Changes in Internal Control over Financial Reporting
No change in our internal control over financial reporting (as defined in Rule
13a-15(f) under the Securities Exchange Act of 1934) occurred during the fourth
quarter of fiscal 2007 that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
Not applicable
26
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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, 2007, and their ages and positions as
of that date, are as follows:
Name Age Position
---- --- --------
John Terwilliger 60 President, Chief Executive Officer and Chairman
Jay Jacobs 30 Chief Financial Officer
John F. Terwilliger has served as our President, CEO and Chairman since our
inception in April 2001.
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 11. 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 12. 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.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
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 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.
27
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
1. Financial statements. See "Index to Financial Statements" on page
30 of this report.
2. Exhibits
INCORPORATED BY REFERENCE
----------------------------
EXHIBIT FILED
NUMBER EXHIBIT DESCRIPTION FORM DATE NUMBER HEREWITH
------- --------------------------------------------------------- ------- -------- --------- --------
3.1 Certificate of Incorporation of Houston American Energy
Corp. filed April 2, 2001 SB-2 8/3/01 3.1
3.2 Amended and Restated Bylaws of Houston American
Energy Corp. adopted November 26, 2007 8-K 11/29/07 3.1
3.3 Certificate of Amendment to the Certificate of
Incorporation of Houston American Energy Corp. filed
September 25,2001 SB-2 10/01/01 3.4
4.1 Text of Common Stock Certificate of Houston American
Energy Corp. SB-2 8/3/01 4.1
10.1 Form of Registration Rights Agreement, dated May 4, 2005 8-K 5/10/05 4.3
10.2 Houston American Energy Corp. 2005 Stock Option Plan* 8-K 8/16/05 10.1
10.3 Form of Director Stock Option Agreement* 8-K 8/16/05 10.2
10.4 Form of Placement Agent Warrant, dated April 28, 2006 8-K 4/28/06 4.1
10.5 Form of Registration Rights Agreement, dated April
28,2006 8-K 4/28/06 4.2
10.6 Form of Subscription Agreement, dated April 2006 relating
to the sale of shares of common stock 8-K 4/28/06 10.1
10.7 Form of Lock-Up Agreement, dated April 2006 8-K 4/28/06 10.2
14.1 Code of Ethics for CEO and Senior Financial Officers 10-KSB 3/26/04 14.1
23.1 Consent of Thomas Leger & Co. L.L.P. X
23.2 Consent of Malone & Bailey, P.C. X
31.1 Section 302 Certification of CEO X
31.2 Section 302 Certification of CFO X
32.1 Section 906 Certification of CEO X
32.2 Section 906 Certification of CFO X
99.1 Code of Business Ethics 8-K 7/7/06 99.1
* Compensatory plan or arrangement.
28
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
HOUSTON AMERICAN ENERGY CORP.
Dated: March 27, 2008
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 27, 2008
John F. Terwilliger President, Treasurer and Director
(Principal Executive Officer)
/s/ O. Lee Tawes III Director March 27, 2008
O. Lee Tawes III
/s/ Edwin Broun III Director March 27, 2008
Edwin Broun III
/s/ Stephen Hartzell Director March 27, 2008
Stephen Hartzell
/s/ John P. Boylan Director March 27, 2008
John P. Boylan
/s/ James J. Jacobs Chief Financial Officer March 27, 2008
James J. Jacobs (Principal Accounting and
Financial Officer
29
HOUSTON AMERICAN ENERGY CORP.
INDEX TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm. . . . . . . . . . . F-1
Report of Independent Registered Public Accounting Firm. . . . . . . . . . . F-2
Balance Sheets as of December 31, 2007 and December 31, 2006. . . . . . . . F-3
Statements of Operations For the Years ended December 31, 2007 and 2006. . . F-4
Statements of Shareholders' Equity for the Years ended December 31, 2007 and
2006. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-5
Statements of Cash Flows For the Years Ended December 31, 2007 and 2006. . . F-6
Notes to Financial Statements. . . . . . . . . . . . . . . . . . . . . . . . F-7
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, 2007 and the related statements of operations, shareholders'
equity, and cash flows for the year ended December 31, 2007. 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. The Company is not
required to have, nor were we engaged to perform, an audit of its internal
control over financial reporting. Our audit included consideration of internal
control over financial reporting as a basis for designing audit procedures that
are appropriate in the circumstances, but not for purposes of expressing an
opinion on the effectiveness of the Company's internal control over financial
reporting. Accordingly, we express no such opinion. 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 overall 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, 2007, and the results of its operations and its cash flows
for the year ended December 31, 2007, in conformity with accounting principles
generally accepted in the United States of America.
/s/ Malone & Bailey, PC
www.malone-bailey.com
Houston, Texas
March 27, 2008
F-1
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 year ended December 31, 2006. 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 year ended December 31, 2006 in conformity with accounting principles
generally accepted in the United States of America.
/s/ Thomas Leger & Co., L.L.P.
Thomas Leger & Co., L.L.P.
March 26, 2007
Houston, Texas
F-2
HOUSTON AMERICAN ENERGY CORP.
BALANCE SHEETS
ASSETS
------
December 31,
----------------------------
CURRENT ASSETS 2007 2006
-------------- ------------
Cash $ 417,818 $ 409,008
Marketable securities 9,650,000 14,000,000
Accounts receivable - Oil and gas sales 577,512 325,436
Prepaid expenses and other current assets 49,255 -
-------------- ------------
TOTAL CURRENT ASSETS 10,694,585 14,734,444
-------------- ------------
PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties, full cost method
Costs subject to amortization 12,714,669 6,796,308
Costs not being amortized 998,806 700,549
Office equipment 11,878 11,878
-------------- ------------
Total 13,725,353 7,508,735
Accumulated depreciation and amortization oil and gas properties (3,708,308) (2,260,463)
-------------- ------------
PROPERTY, PLANT AND EQUIPMENT, NET 10,017,045 5,248,272
-------------- ------------
OTHER ASSETS 3,167 3,167
-------------- ------------
TOTAL ASSETS $ 20,714,797 $19,985,883
============== ============
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 260,222 $ 399,159
Accrued expenses 1,720 11,909
Foreign income taxes payable 74,141 121,216
-------------- ------------
TOTAL CURRENT LIABILITIES 336,083 532,284
-------------- ------------
LONG-TERM DEBT
Reserve for plugging and abandonment costs 115,061 38,816
Deferred rent obligation 20,206 -
-------------- ------------
TOTAL LONG-TERM DEBT 135,267 38,816
-------------- ------------
SHAREHOLDERS' EQUITY
Common stock, par value $.001;
100,000,000 shares authorized, 27,920,172 shares
issued and outstanding 27,920 27,920
Additional paid-in capital 22,377,832 22,042,624
Treasury stock, at cost; 100,000 shares (85,834) (85,834)
Accumulated deficit (2,076,470) (2,569,927)
-------------- ------------
TOTAL SHAREHOLDERS' EQUITY 20,243,447 19,414,783
-------------- ------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 20,714,797 $19,985,883
============== ============
The accompanying notes are an integral part of these financial statements
F-3
HOUSTON AMERICAN ENERGY CORP.
STATEMENT OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006
2007 2006
------------ ------------
Oil and gas revenue $ 4,977,172 $ 3,202,731
------------ ------------
EXPENSES OF OPERATIONS
Lease operating expense and severance tax 1,841,119 1,017,440
Joint venture expense 149,200 167,023
Depreciation and depletion 1,099,826 887,911
Impairment of oil and gas properties 348,019 -
General and administrative expense 1,568,228 1,231,079
------------ ------------
Total expenses 5,006,392 3,303,453
------------ ------------
INCOME (LOSS) FROM OPERATIONS (29,220) (100,722)
------------ ------------
OTHER (INCOME) EXPENSE
Interest income (649,792) (496,490)
Interest expense-derivative - 37,773
Loss on change in fair value of derivative
liabilities - 170,949
Interest expense - 57,278
Interest expense - related party - 20,440
Financing costs - 110,787
------------ ------------
Total other (income) expense (649,792) (99,263)
NET INCOME (LOSS) BEFORE TAXES 620,572 (1,459)
INCOME TAX EXPENSE 127,116 510,637
------------ ------------
NET INCOME (LOSS) $ 493,456 $ (512,096)
============ ============
BASIC NET INCOME (LOSS) PER SHARE $ 0.02 $ (0.02)
============ ============
DILUTED NET INCOME (LOSS) PER SHARE $ 0.02 $ (0.02)
============ ============
BASIC WEIGHTED AVERAGE SHARES 27,920,172 25,087,847
============ ============
DILUTED WEIGHTED AVERAGE SHARES 28,132,375 25,087,847
============ ============
The accompanying notes are an integral part of these financial statements
F-4
HOUSTON AMERICAN ENERGY CORP.
STATEMENT OF SHAREHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006
------------------------------------------------------------------------------------------------------------------
Common Stock Treasury Stock Accumulated
------------------- -----------------------
Paid - in Equity
Shares Amount Capital Shares Amount (Deficit) Total
---------- ------- ----------- --------- ---------- ------------- ------------
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 note - 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
========== ======= =========== ========= ========== ============= ============
Stock issued for -
Options issued
to director - - 143,100 - - - 143,100
Options issued
to employee - - 192,108 - - - 192,108
Net Income - - - - - 493,456 493,456
---------- ------- ----------- --------- ---------- ------------- ------------
Balance at
December 31, 2007 27,920,172 27,920 22,377,832 (100,000) (85,834) (2,076,471) 20,243,447
========== ======= =========== ========= ========== ============= ============
The accompanying notes are an integral part of these financial statements
F-5
HOUSTON AMERICAN ENERGY CORP.
STATEMENT OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2007 AND 2006
-----------------------------------------------------------------------------------------------
2007 2006
------------ -------------
CASH FLOW FROM OPERATING ACTIVITIES
Net income (loss) $ 493,456 $ (512,096)
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS)
TO NET CASH FROM OPERATIONS
Depreciation and depletion 1,099,826 887,911
Non-cash expenses
Stock based compensation 335,208 289,755
Impairment of oil and gas properties 348,019 -
Amortization of debt discount and deferred financing costs - 148,557
Change in fair value of derivatives - 170,949
Amortization of asset retirement obligation 2,299 -
Amortization of deferred rent 20,206 -
Decrease (increase) in accounts receivable (281,401) 247,786
Decrease in prepaid expense (19,931) 9,965
(Decrease) increase in accounts payable and accrued liability (196,201) (3,381)
------------ -------------
Net cash provided by operations 1,801,481 1,239,446
------------ -------------
CASH FLOW FROM INVESTING ACTIVITIES
Purchases of marketable securities (3,150,000) (17,000,000)
Sales of marketable securities 7,500,000 3,000,000
Acquisition of oil and gas properties and assets (6,142,672) (3,507,371)
------------ -------------
Net cash used in investing activities (1,792,672) (17,507,371)
------------ -------------
CASH FLOW FROM FINANCING ACTIVITIES
Sale of common stock - net of costs - 15,361,583
Exercise of warrants - 491,250
Repayment of debt - (900,000)
------------ -------------
Net cash provided by financing - 14,952,833
------------ -------------
INCREASE (DECREASE) IN CASH 8,809 (1,315,092)
Cash, beginning of period 409,008 1,724,100
------------ -------------
Cash, end of period $ 417,817 $ 409,008
============ =============
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid - $ 77,718
Taxes paid $ 849,586 $ 261,891
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING
AND FINANCING ACTIVITIES
Conversion of convertible notes to common stock - $ 2,445,345
Exercise of warrants - 610,719
The accompanying notes are an integral part of these financial statements
F-6
NOTE 1 - NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL
-------
Houston American Energy Corp. (a Delaware Corporation) ("the Company" or "HUSA")
was incorporated on April 2, 2001. The Company is engaged, as a non-operating
joint owner, in the exploration, development, and production of natural gas,
crude oil, and condensate from properties located principally in the Gulf Coast
area of the United States and international locations with proven production,
which to date has focused on Colombia, 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, determination of proved reserves of oil
and gas and asset retirement obligations. 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, net of royalties and net profits
interests, 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. These sales may result
in more or less than the Company's share of prorata production from certain
wells. When natural gas sales volumes exceed the Company's entitled share and
the accumulated overproduced balance exceeds the Company's share of the
remaining estimated proved natural gas reserves for a given property, the
Company will record a liability. Historically, sales volumes have not
materially differed from the Company's entitled share of natural gas production.
OIL AND GAS PROPERTIES
----------------------
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.
Depletion and amortization for oil and gas properties was $1,097,882 and
$885,611 at December 31, 2007 and 2006, respectively and accumulated
amortization was $3,348,411 at December 31, 2007.
F-7
FURNITURE AND EQUIPMENT
-----------------------
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.
Depreciation expense for office equipment was $1,944 and $2,300 at December 31,
2007 and 2006, respectively and accumulated depreciation was $11,878 at December
31, 2007.
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 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.
Unevaluated oil and gas properties not subject to amortization at December 31,
2007 include the following:
North South
America America Total
------- ------- --------
Leasehold acquisition costs 191,477 1,366 $192,843
Geological, geophysical, screening and evaluation costs 707,138 11,964 719,102
Leasehold retention costs 86,861 - 86,861
------- ------- --------
Total 985,476 13,330 $998,806
======= ======= ========
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. Although the Company's domestic policy with respect to ARO is to
assign depleted wells to a salvager for the assumption of abandonment
obligations before the wells have reached their economic limits, as required
under SFAS No. 143, the Company has estimated its future ARO obligation with
respect to its 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
F-8
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, 2007 and 2006. The ARO liability in the
table below includes amounts classified as both current and long-term at
December 31, 2007 and 2006.
North America South America
Years Ended December 31 Years Ended December 31
2007 2006 2007 2006
------------ ------------ ------------- -------------
ARO liability at January 1 $ 0 $ - $ 38,816 $ 41,249
Accretion expense - - 2,299 3,300
Liabilities incurred from drilling 7,360 - 32,006 11,077
Liabilities incurred - assets acquired - - - -
Liabilities settled - assets abandoned - - (4,641) -
Changes in estimates 16,678 - 22,543 (16,810)
------------ ------------ ------------- -------------
ARO liability at December 31, $ 24,038 $ - $ 91,023 $ 38,816
============ ============ ============= =============
JOINT VENTURE EXPENSE
---------------------
Joint venture expense reflects the indirect field operating and regional
administrative expenses billed by the operator of the Colombian concessions.
INCOME TAXES
------------
Deferred income taxes are provided on a liability method whereby deferred tax
assets and liabilities are established for the difference between the financial
reporting and income tax basis of assets and liabilities as well as operating
loss and tax credit carry forwards. Deferred tax assets are reduced by a
valuation allowance when, in the opinion of management, it is more likely than
not that some portion or all of the deferred tax assets will not be realized.
Deferred tax assets and liabilities are adjusted for the effects of changes in
tax laws and rates on the date of enactment.
PREFERRED STOCK
---------------
The Company has authorized 10,000,000 shares of preferred stock with a par value
of $.001. The Board of Directors shall determine the designations, rights,
preferences, privileges and voting rights of the preferred stock as well as any
restrictions and qualifications thereon. No shares of preferred stock have been
issued.
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. The Company's marketable securities
consist of asset-backed securities 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
F-9
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, 2007. At December 31, 2007 the
Company held $9,650,000 in marketable securities.
NET INCOME (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. The Company's 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, 2007, 339,000 options and 315,000 warrants to
purchase common stock resulted in weighted average diluted shares outstanding of
28,132,375 based upon the treasury stock method, which resulted in $0.02 diluted
earnings per share. 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.
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 ("Hupecol") and its
concessions in the South American country of Colombia, the Company is dependent
on the personnel, management and resources of Hupecol 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 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 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.
During 2007, the Company was advised that Hupecol had retained an investment
bank for purposes of evaluating a possible transaction involving the
monetization of Hupecol assets. Pursuant to that engagement, in March 2008,
Hupecol Caracara LLC, as owner/operator under the Caracara Association Contract,
entered into a Purchase and Sale Agreement to sell all of its interest in the
Caracara Association Contract and related assets for a sale price of $920
million, subject to certain closing adjustments based on oil price fluctuations
and operations between the effective date of the sale, January 1, 2008, and the
closing date. Pursuant to our investment in Hupecol Caracara LLC, we hold a
1.594674% interest in the Caracara assets being sold and will receive our
proportionate interest in the net sale proceeds after deduction of commissions
and transaction expenses. The Company's Caracara assets subject to the proposed
sale had a net book value of $2,087,777 at December 31, 2007.
Completion of the sale of the Caracara assets is subject to satisfaction of
various conditions set out in the Purchase and Sale Agreement, including the
granting of all consents and approvals of the Colombian governmental authorities
required for the transfer of the assets to the purchaser.
F-10
At December 31, 2007, 67.9% of the Company's net oil and gas property investment
and 91% of its revenue was with or derived from Hupecol.
The majority of the oil production for 2007 from the Company's mineral interests
was sold to an international integrated oil company (97%). The gas production is
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.
The Company reviews accounts receivable balances when circumstances indicate a
balance may not be collectible. Historically, the Company has not experienced
any uncollectible accounts receivable. Based upon the Company's review, no
allowance for uncollectible accounts was deemed necessary at December 31, 2007
and 2006, respectively.
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 $175,793 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.
SUBORDINATED CONVERTIBLE NOTES AND WARRANTS- DERIVATIVE FINANCIAL INSTRUMENTS
-----------------------------------------------------------------------------
The convertible subordinated notes (the "Convertible Notes") and warrants (the
"Warrants") issued in May 2005 were accounted for in accordance with Emerging
Issues Task Force ("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 EIFT 05-04 "The Effect of a Liquidated Damages Clause on a
Freestanding Financial Instrument Subject to Issue No. 00-19".
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.
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.
F-11
In May 2006, the Convertible Notes were converted to common stock and the
Warrants were exercised resulting in the reclassification of all derivative
liabilities associated with the Convertible Notes and Warrants. See "Note 2 -
Notes Payable - Subordinated Convertible Notes" and "- 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. 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," (APB 25) 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 July 2006, the FASB issued FASB Interpretation No. 48 "Accounting for
Uncertainty in Income Taxes--an Interpretation of FASB Statement 109", 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 has evaluated the impact of FIN 48 and concluded that no
adjustments to retained earnings were needed.
In September 2006, the FASB issued Statement of Financial Accounting Standards
No. 157 "Fair Value Measurements", 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.
In February 2007, the FASB issued SFAS No. 159, "the Fair Value Option for
Financial Assets and Financial Liabilities-including an amendment of FASB
Statement No. 115". SFAS No. 159 permits entities to choose to measure many
financial instruments and certain other items at fair value. Unrealized gains
and losses on items for which the fair value option has been elected will be
recognized in earnings at each subsequent reporting date. SFAS 159 is effective
for the Company January 1, 2008. The adoption of SFAS No. 159 will not have a
material impact on the Company's consolidated financial position or results of
operations.
In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in
Consolidated Financial Statements". SFAS 160 establishes accounting and
reporting standards for ownership interests in subsidiaries held by parties
other than the parent, the amount of consolidated net income attributable to the
parent and to the noncontrolling interest, changes in a parent's ownership
interest and the valuation of retained noncontrolling equity investments when a
subsidiary is deconsolidated. SFAS 160 also establishes reporting requirements
that provide sufficient disclosures that clearly identify and distinguish
between the
F-12
interests of the parent and the interests of the noncontrolling owners. This
standard is effective for fiscal years beginning after December 15, 2008. The
Company is currently evaluating the effect, if any, that SFAS No. 160 will have
on the financial statements.
NOTE 2 - NOTES PAYABLE AND RELATED DERIVATIVE LIABILITIES
NOTE PAYABLE - RELATED PARTY
--------------------------------
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 Convertible Notes provided for interest at 8% with 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.
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 upon the conversion
of the same to common stock. 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.
WARRANTS
--------
On May 4, 2005, in connection with the issuance of the Convertible Notes, the
Company entered into the 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 represented 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
F-13
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 Warrants were exercised in full in May 2006. 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 2007 and 2006,
Mr. Terwilliger received royalty payments relating to those properties totaling
$50,580 and $37,333, respectively, and Mr. Tawes received royalty payments
relating to those properties totaling $48,528 and $23,343, 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.
NOTE 4 - INCOME TAXES
The following table sets forth a reconciliation of the statutory federal income
tax for the year ended December 31, 2007 and 2006.
2007 2006
Income/Loss before income taxes $ 620,572 $ (1,459)
========== =========
Income tax computed at statutory rates 210,994 $ (496)
Derivative expense - 70,982
Effect of foreign taxes - 173,616
Permanent differences, nondeductible expenses 1,828 40,330
Current Colombian tax expense 788,724 -
Refund of prior Colombian taxes (662,688) -
Increase (decrease) in valuation allowance 621,378 219,567
Return to Accrual Items (833,833) -
State 713 -
Other - 6,638
---------- ---------
Tax provision $ 127,116 $510,637
========== =========
Current provision
United States 1,080 $ -
Foreign 126,036 510,637
---------- ---------
Total provision $ 127,116 $510,637
========== =========
F-14
The Company has a net operating loss carry forward of approximately $832,821
which will expire in 2023. In addition, the Company has approximately $875,873
of foreign tax credit carry forwards which will expire in 2015, 2016, and 2017.
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, 2007 are set out below.
2007 2006
----------- ----------
Non-Current Deferred tax assets:
Net operating loss carryforwards $ 283,159 $ 66,536
Foreign tax credit carryforwards 875,873 841,642
Asset retirement obligation 13,197 13,197
Deferred State Tax 61,369 -
Stock Compensation 113,971 -
Other 353,027 -
Colombia Future Tax Obligations 173,616
----------- ----------
Total Non-Current Deferred tax assets 1,874,212 921,375
Non-Current Deferred tax liabilities:
Book over tax depreciation, depletion
and capitalization methods on oil
and gas properties (256,789) (189,524)
Colombian deductions in excess of book - -
----------- ----------
Total Non-Current tax liabilities (256,789) (189,524)
Valuation Allowance (1,617,423) (731,851)
----------- ----------
Net deferred tax liability $ - $ -
=========== ==========
FOREIGN INCOME TAXES
----------------------
The Company owns an interest in four limited liability companies that operate
the activities in Colombia, and various entities controlled by Hupecol.
Colombia's tax rate is 34%. Based on information provided by the manager of
Hupecol, the Company has determined its share of the Colombia tax liability for
2007 will be $788,724. This amount has been accrued during the year and will be
funded by withholdings from the 2007 revenue and from revenue received in 2008.
In 2007, the Company was advised that Hupecol would be adjusting the division of
interests among the members of the various Hupecol entities to reflect revised
Colombian tax allocations among the various Hupecol entities. Specifically,
Hupecol advised that Colombian tax attributes were allocated among the Hupecol
entities without taking into account the specific contributions of each
individual entity resulting in an improper shifting of tax expenses and benefits
among the Hupecol entities and, in turn, the members of each of the Hupecol
entities, including the Company.
As a result of the adjustment by Hupecol, during 2007, the Company received a
net credit from Hupecol for excess Colombian taxes allocated to it in the amount
of $662,688. This credit has been reflected in the financial statements as a
credit to income tax expense.
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 2007 the Company
granted 30,000 options to the members of the Board of Directors and 66,667
previously granted options vested to company employees.
F-15
The options granted to the directors were 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 88%, expected dividends 0.0%. Using this model yielded a value
of $143,100 which was charged to expense in 2007.
The options granted to employees were 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
2007, $192,108 was expensed as employee compensation.
Option activity during 2007 is as follows:
Weighted
Average
Weighted Remaining
Average Contractual Aggregate
Exercise Term (in Intrinsic
Options Price Years) Value
------- --------- ------------ ----------
Outstanding at beginning of year 309,000 $ 2.89 8.27 $ 77,000
Granted 30,000 5.45 9.39 0
Exercised - - - -
Forfeited - - - -
------- --------- ------------ ----------
Outstanding at end of year 339,000 $ 3.12 8.37 $ 77,000
======= ========= ============ ==========
No options were exercised for the year ended December 31, 2007. As of December
31, 2007, total unrecognized stock-based compensation expense related to
non-vested stock options was $82,332. As of December 31, 2007 there were
161,000 shares of common stock available for issuance pursuant to future stock
option grants.
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 SEC, 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.
The Company paid commissions totaling $1,162,000 and issued a warrant (the
"Placement Agent Warrant") to the placement agent in the offering to purchase
415,000 shares of common stock at $3.00 per share. The Registration Rights
Agreements provide that the shares of common stock underlying the Placement
Agent Warrant are to be included in the registration statement, which was filed
and declared effective on June 16, 2006.
F-16
CONVERSION OF 8% SUBORDINATED CONVERTIBLE NOTES
-----------------------------------------------
During 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
--------------------
During 2006, the holders of the 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.
During 2006, the placement agent exercised 100,000 of the 415,000 Placement
Agent Warrants, and was issued 100,000 shares for an aggregate consideration of
$300,000. At December 31, 2007, the Company had the remaining 315,000 warrants
outstanding with a remaining contractual life of 3.33 years.
The weighted average exercise price for all remaining outstanding warrants was
$3.00. No warrants were exercised during the year ended December 31, 2007.
NOTE 7 - COMMITMENTS AND CONTINGENCIES
LEASE COMMITMENT
----------------
The Company leases office facilities under an operating lease agreement that
expires May 31, 2012. The lease agreement requires future payments as follows:
Year Amount
----- -------
2008 79,576
2009 81,945
2010 84,315
2011 86,684
2012 36,530
-------
Total 369,050
=======
Total rental expense was $76,578 in 2007 and $43,704 in 2006. 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.
ENVIRONMENTAL CONTINGENCIES
---------------------------
The Company's 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
F-17
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 the Company to make significant
expenditures to maintain compliance, and may otherwise have a material adverse
effect on its results of operations, competitive position or financial condition
as well as the industry in general. Under these environmental laws and
regulations, the Company could be held strictly liable for the removal or
remediation of previously released materials or property contamination
regardless of whether the Company was responsible for the release or if its
operations were standard in the industry at the time they were performed. The
Company maintains insurance coverage, which it believes is customary in the
industry, although the Company is not fully insured against all environmental
risks
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
-----------------------
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.
During 2007, the Company's compensation committee engaged a compensation
consultant, as called for by the terms of employment of the Company's chief
financial officer, to review the compensation arrangements of the Company's
senior executives with a view to adjusting such compensation to reflect industry
compensation practices. Following that review, the compensation committee
approved increases in base salary of the Company's chief executive officer to
$315,000 annually and chief financial officer to $150,000 annually, the payment
of one-time cash bonuses of $50,000 to the Company's chief executive officer and
$30,000 to the chief financial officer and the grant of 41,700 shares of
restricted stock to the Company's chief executive officer and 13,900 shares to
the chief financial officer, which grants are subject to approval of the same by
the Company's shareholders.
NOTE 8 - GEOGRAPHICAL INFORMATION
The Company currently has operations in two geographical areas, the United
States and Colombia. Revenues for the twelve months ended December 31, 2007 and
Long Lived Assets as of December 31, 2007 attributable to each geographical area
are presented below:
Years Ended December 31, 2007 Years Ended December 31, 2006
--------------------------------- ---------------------------------
Long Lived Long Lived
Revenues Assets, Net Revenues Assets, Net
---------------- --------------- --------------- ----------------
North America $ 445,532 $ 2,182,857 $ 637,625 $ 1,164,423
South America 4,531,640 7,834,188 2,565,106 4,081,905
---------------- --------------- --------------- ----------------
Total $ 4,977,172 $ 10,017,045 $ 3,202,731 $ 5,246,328
F-18
NOTE 9 - 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:
2007 2006
---------- -----------
Revenues
North America $ 445,532 $ 637,625
South America 4,531,640 2,565,106
---------- -----------
$4,977,172 $ 3,202,731
========== ===========
Production Cost
North America $ 130,430 $ 198,167
South America 1,710,689 819,273
---------- -----------
$1,841,119 $1,017,,440
========== ===========
CAPITAL COSTS
-------------
Capitalized costs and accumulated depletion relating to the Company's oil and
gas producing activities as of December 31, 2007, all of which are onshore
properties located in the United States and Colombia, South America are
summarized below:
North South
America America Total
------------ ------------ ------------
Unproved properties not being amortized 985,476 13,330 998,806
Properties being amortized 3,424,994 9,289,675 12,714,669
Accumulated depreciation, depletion and amortization (2,227,613) (1,468,817) (3,696,430)
------------ ------------ ------------
Total capitalized costs $ 2,182,857 $ 7,834,188 $10,017,045
============ ============ ============
During 2007, the Company recorded a provision for impairments of $348,019, all
of which was attributable to North American properties. Impairments related to
the termination, during 2007, of operations of seven wells in the U.S. and the
fact that, as of December 31, 2007, well testing had not yet been conducted on,
and no reserves had been attributed to, the well drilled on the Company's Caddo
Lake Prospect.
AMORTIZATION RATE
-----------------
The amortization rate per unit based on barrel equivalents was $57.15 for North
America and $8.07 for South America.
F-19
ACQUISITION, EXPLORATION AND DEVELOPMENT COSTS INCURRED
-------------------------------------------------------
Costs incurred in oil and gas property acquisition, exploration and development
activities as of December 31, 2007 and 2006 are summarized below:
2007
------------------------------
North America South America
-------------- --------------
Property acquisition costs:
Proved $ 880,779 $ 355,000
Unproved 191,477 -
Exploration costs 2,249,679 -
Development 1,088,535 8,948,005
-------------- --------------
Total costs incurred $ 4,410,470 $ 9,303,005
============== ==============
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 costs 141,277 723,929
-------------- --------------
Total costs incurred $ 2,503,757 $ 4,933,100
============== ==============
F-20
RESERVE INFORMATION AND RELATED STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET
--------------------------------------------------------------------------------
CASH FLOWS
-----------
The supplemental unaudited presentation of proved reserve quantities and related
standardized measure of discounted future net cash flows provides estimates only
and does not purport to reflect realizable values or fair market values of the
Company's reserves. Volumes reported for proved reserves are based on
reasonable estimates. These estimates are consistent with current knowledge of
the characteristics and production history of the reserves. The Company
emphasizes that reserve estimates are inherently imprecise and that estimates of
new discoveries are more imprecise than those of producing oil and gas
properties. Accordingly, significant changes to these estimates can be expected
as future information becomes available.
Proved reserves are those estimated reserves of crude oil (including condensate
and natural gas liquids) and natural gas that geological and engineering data
demonstrate with reasonable 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 engineers. Reserve
definitions and pricing requirements prescribed by the SEC 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, 2005 850,650 2,800 - 270,621 850,650 273,421
Extensions and discoveries 3 141 - 277,155 3 277,296
Revisions of prior estimates (346,807) 1,656 - (110,273) (346,807) (108,617)
Production (78,096) (1,687) - (48,057) (78,096) (49,744)
--------- ---------- -------- ---------- --------- ----------
Balance December 31, 2006 425,750 2,910 - 389,446 425,750 392,356
========= ========== ======== ========== ========= ==========
Extensions and discoveries 1 13 - 1,121,765 1 1,121,778
Revisions of prior estimates (245,853) 3,158 - (160,857) (245,853) (157,699)
Production (44,249) (2,079) - (69,127) (44,249) (71,206)
--------- ---------- -------- ---------- --------- ----------
Balance December 31, 2007 135,649 4,012 - 1,281,227 135,649 1,285,239
========= ========== ======== ========== ========= ==========
Proved developed reserves
at December 31, 2006 85,890 2,240 - 283,500 85,890 285,740
========= ========== ======== ========== ========= ==========
at December 31, 2007 135,649 4,012 - 761,959 135,649 765,971
========= ========== ======== ========== ========= ==========
F-21
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, 2007
North South
America America Total
----------- ------------- -------------
Future net cash flow $1,312,392 $111,909,478 $113,221,870
Future production cost (530,096) (18,540,428) (19,070,524)
Future income tax - (23,577,248) (23,577,248)
----------- ------------- -------------
Future net cash flow 782,296 69,791,802 70,574,098
10% annual discount for timing of cash flow (172,260) (14,450,335) (14,622,595)
----------- ------------- -------------
Standard measure of discounted future net
cash flow relating to proved oil and gas reserves $ 610,036 $ 55,341,467 $ 55,951,503
=========== ============= =============
Changes in standardized measure:
Change due to current year operations
Sales, net of production costs (3,136,053)
Change due to revisions in standardized variables:
Income taxes (13,727,868)
Accretion of discount 1,045,246
Net change in sales and transfer price, net of
production costs 14,313,855
Revision and others 9,549,895
Discoveries 59,728,838
Changes in production rates and other (804,957)
-------------
Net 47,869,166
Beginning of year 8,082,337
End of year $ 55,951,503
=============
F-22
Standard measure of discounted future net cash flows at December 31, 2006
North South
America 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-23