Edgar Filing: HOUSTON AMERICAN ENERGY CORP

form10ka.htm

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

(Amendment No. 2)

(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.
	(Exact name of registrant specified in its charter)

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

	801 Travis Street, Suite 1425, Houston, Texas 77002
	(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:

	Title of each class		Name of each exchange on which 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 £ No x

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 £ No x

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.

Yes x 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 o

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 £ No x

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.

EXPLANATORY NOTE

This Amendment No. 2 to the Annual Report on Form 10-K of Houston American Energy Corp. (the "Company") amends the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2007 (the "Original Filing"), which was filed with the Securities and Exchange Commission on March 28, 2008. The Company is filing this Amendment No. 2 for the purpose of correcting certain disclosures under (1) Item 1. Business – Natural Gas and Oil Reserves, (2) Item 9A. Controls and Procedures, and (3) Note 1 – Nature of Company and Summary of Significant Accounting Policies – Marketable Securities, in the financial statements.

Except as described above, this Amendment No. 2 does not amend any other information set forth in the Original Filing and the Company has not updated disclosures contained therein to reflect any events that occurred at a date subsequent to the date of the Original Filing.

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

SIGNATURES

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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.

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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.

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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.

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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 Area	Project Gross		Project Net		Company Net		Project 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.

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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

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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		78,905
South America		0		0
Oil (Bbls):
North America		2,078		7,673
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)	$	55,951,503	$	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.

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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.

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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.

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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 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.

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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.

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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 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.

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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.

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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 availability of shares of common stock for future sale, will have on the trading price of our common stock.

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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

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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.

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)		Weighted-average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities 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

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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.

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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.

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 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.

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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 $151,039 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.”

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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.

	Colombia		North 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.

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Following is a summary comparison of lease operating expenses for the years ended December 31, 2007 and 2006.

	Colombia		North 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 $57,196 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 $224,750.

Financial Condition

Liquidity and Capital Resources. At December 31, 2007, we had a cash balance of $417,818 and working capital of $10,428,422 compared to a cash balance of $409,008 and working capital of $14,202,160 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 offset by increased lease operating expenses and general and administrative expenses and reductions in payables and accrued expenses.

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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

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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.

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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

Under the supervision and the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation as of December 31, 2007 of the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2007.

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 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:

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.

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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.

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.

This annual report does not include an attestation report of the company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.

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

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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 & Touché, 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

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

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

Item 14.

Principal Accountant Fees and Services

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PART IV

Item 15.

Exhibits and Financial Statement Schedules

Financial statements. See “Index to Financial Statements” on page 30 of this report.

Exhibits

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Date	Number	Filed 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.	10-K/A	6/20/08	23.1

23.2	Consent of Malone & Bailey, P.C.	10-K/A	6/20/08	23.2

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.

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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: October 2, 2008

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

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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

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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 26, 2008

F-1

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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.

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

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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		4,221			121,216

TOTAL CURRENT LIABILITIES		266,163			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		(2,006,551	)		(2,569,927	)

TOTAL SHAREHOLDERS' EQUITY		20,313,367			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

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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		57,196			510,637

Net income (loss)	$	563,376		$	(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

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HOUSTON AMERICAN ENERGY CORP.

STATEMENT OF SHAREHOLDERS' EQUITY

For the Years Ended December 31, 2007 and 2006

	Common Stock						Treasury Stock						Accumulated
	Shares		Amount		Paid - in Capital		Shares			Amount			Equity (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		-		-		-		-			-			563,376			(512,096	)

Balance at December 31, 2007		27,920,172		27,920		22,377,832		(100,000	)		85,834			(2,006,551	)		20,313,367

The accompanying notes are an integral part of these financial statements

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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)	$	563,376		$	(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		(266,121	)		(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	)
Funds in excess of prospect costs

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		-		$	2,125,000
Exercise of warrants		-			491,250

The accompanying notes are an integral part of these financial statements

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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 pro−rata 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.

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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 America		South 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 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.

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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 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.

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At December 31, 2007, the Company’s available for sale securities of $9,650,000 consisted of (1) $900,000 in AAA rated asset-backed auction rate notes maturing December 2032, and (2) $8,750,000 in AAA rated municipal bonds maturing December 2032. Each of these investments paid interest monthly and had regular roll-over or auction dates at which time the interest rates were reset or the securities were redeemed for cash. There were no unrealized gains or losses associated with these marketable securities at December 31, 2007.

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.

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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.

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

In May 2006, the Convertible Notes were converted to common stock and the 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.

xxvi) 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.

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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 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.

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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 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		525,086			173,616
Permanent differences, nondeductible expenses		1,828			40,330
Increase (decrease) in valuation allowance		96,292			219,567
Return to Accrual Items		(115,029	)
State		713
Other					6,638

Tax provision	$	719,884		$	510,637

Current provision
United States		1,080		$	-
Foreign		137,601			510,637
Deferred provision- Foreign		581,203			-
Total provision	$	719,884		$	510,637

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The Company has a net operating loss carry forward of approximately $832,821 which will expire in 2023. In addition, the Company has approximately $224,750 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		224,750			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		1,223,089			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		(581,202	)		-
Total Non-Current tax liabilities		(837,991	)		(189,524	)
Valuation Allowance		(966,300	)		(731,851	)
Net deferred tax liability	$	(581,202	)	$	-

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 $137,601. 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.

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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:

	Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in Years)		Aggregate Intrinsic 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.

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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.

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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 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.

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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

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 America			South America			Total

Unproved properties not being amortized		85,476			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.

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Amortization Rate

The amortization rate per unit based on barrel equivalents was $57.15 for North America and $8.07 for South America.

Acquisition, Exploration and Development Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities for December 31, 2007 and 2006 is 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

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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

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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 America			South 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

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Standard measure of discounted future net cash flows at December 31, 2006

	North America			South America			Total

Future net cash flow		2,927,620			18,479,216			21,406,836
Future production cost		(1,303,900	)		(6,993,899	)		(8,297,799	)
Future income tax		-			(2,862,863	)		(2,862,863	)
Future net cash flow		1,623,720			8,622,454			10,246,174
10% annual discount for timing of cash flow		567,170			1,596,667			2,163,837

Standard measure of discounted future net cash flow relating to proved oil and gas reserves	$	1,056,550		$	7,025,787		$	8,082,337

Changes in standardized measure:

Change due to current year operations
Sales, net of production costs							$	(2,185,290	)
Change due to revisions in standardized variables:
Income taxes								727,245
Accretion of discount								637,560
Net change in sales and transfer price, net of production costs								2,426,491
Revision and others								(3,672,014	)
Discoveries								4,590,226
Changes in production rates and other								(817,481	)
Net								1,706,737
Beginning of year								6,375,600

End of year							$	8,082,337

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