HOUSTON AMERICAN ENERGY CORP - Annual Report: 2008 (Form 10-K)

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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the Fiscal Year Ended December 31, 2008

For the transition period from                      to                     

Commission File No. 1-32955

HOUSTON AMERICAN ENERGY CORP.

(Exact name of registrant specified in its charter)

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:

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  x    Non-accelerated filer  ¨    Smaller reporting company  ¨

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 30, 2008, based on the closing sales price of the registrant’s common stock on that date, was approximately $167,656,443. 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 28, 2009 was 28,000,772.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company’s Proxy Statement for its 2009 Annual Meeting are incorporated by reference into Part III of this Report.

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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

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.

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Our principal exploration projects as of December 31, 2008 consisted of 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 640 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.

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, which was scheduled for a re-work as of December 31, 2008 after the well sanded up and ceased production.

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. During the fourth quarter of 2008, pipeline construction and connection to the well was completed and several completion attempts in the Cotton Valley formation were not successful. Currently a Bossier Shale test is planned subject to a unit and permit being granted.

Iberville Parish, Louisiana. In Iberville Parish, Louisiana, we hold a 4.81% working interest in the Home Run Prospect and a 24.12% working interest in the West Klondike prospect. We plan to drill both of these prospects during calendar year 2009.

Vermillion Parish, Louisiana. In Vermillion Parish, Louisiana, we hold a 10% working interest in the North Jade and Northwest Jade prospects. We plan to drill these prospects in the 4^th quarter of 2009 and the 1^st quarter of 2010.

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 340 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, 2008, 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, 2008, we held interests in (1) the Tambaqui Association Contract covering 4,400 acres in the State of Casanare, Colombia, (2) two concessions, the Dorotea Contract and the Cabiona Contract, totaling over 137,000 acres, (3) the Surimena concession covering approximately 69,000 acres, (4) the Las Garzas concession covering approximately 103,000 acres, (5) the Leona concession covering approximately

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70,343 acres, (6) the Camarita concession covering approximately 166,000 acres, and (7) the La Cuerva Contract covering approximately 48,000 acres. See “—Sale of Caracara Assets.”

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 Surimena concession, the Tambaqui Association Contract and the La Cuerva Contract. We hold a 6.25% working interest in the Surimena concession, a 12.6% working interest, with an 11.31% net revenue interest, in the Tambaqui Association Contract and a 1.594674% working interest in the La Cuerva Contract.

Our working interest in the Tambaqui Association Contract is 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 and 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.

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.

- Other Holdings

In addition to our principal exploration projects, we hold various interests in producing wells in 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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Summary Leasehold Information

The following table sets forth certain information about our oil and gas holdings at December 31, 2008:

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Sale of Caracara Assets

In June 2008, we, through Hupecol Caracara LLC as owner/operator under the Caracara Association Contract, sold all of our interest in the Caracara Association Contract and related assets. Pursuant to our investment in Hupecol Caracara LLC, we held a 1.594674% interest in the Caracara assets, covering approximately 232,500 acres, representing our principal, and initial, Colombian prospect. At December 31, 2007, the estimated proved reserves associated with these assets totaled 787,742 barrels of oil, which represented 60.37% of our estimated proved oil and natural gas reserves.

As a result of the sale of the Caracara assets, we received net proceeds, after deduction of fees and expenses of the transaction, of $11,546,510 (before amounts placed in escrow as discussed below), realized a gain on the sale of $7,615,236 and eliminated from oil and gas properties costs subject to amortization associated with the Caracara assets totaling $3,977,907.

Pursuant to the terms of the sale of the Caracara assets, on the closing date of the sale, a portion of the purchase price was deposited in escrow to settle post-closing adjustments under the purchase and sale agreement. The funds deposited in escrow will be released to us, or to the purchaser, based on post-closing adjustments 12 months following closing. Our proportionate interest in the escrow deposit, totaling $1,673,551, has been recorded as Other Current Assets. The net proceeds and the gain realized from the sale of the Caracara assets may be adjusted based on post-closing adjustments.

Production from the Caracara prospect accounted for $3,005,140 and $3,703,739 of our revenues during 2008 and 2007, respectively.

Drilling Activities

In 2008, we drilled 1 domestic well and 15 wells in Colombia, consisting of 9 exploratory and 7 developmental wells of which 11 were completed and 5 were dry holes.

The following table sets forth certain information regarding the actual drilling results for each of the years 2008 and 2007 as to wells drilled in each such individual year:

At December 31, 2008, two wells were being drilled in Colombia and one well was being drilled in the U.S.

Seismic Activity

During 2008, our operator in Colombia (1) acquired approximately 65 miles of additional seismic and geological data relating primarily to prospects in which we hold a 12.5% working interest, (2) acquired additional seismic data on the La Cuerva prospect and (3) shot 32.824 square miles of combined seismic on the Las Garzas and Leona contracts.

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Productive Well Summary

The following table sets forth certain information regarding our ownership as of December 31, 2008 of productive gas and oil wells in the areas indicated:

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:

Natural Gas and Oil Reserves

The following table summarizes the estimates of our historical net proved reserves as of December 31, 2007 and 2008, and the present value attributable to these reserves at these dates. The reserve data and present values were prepared by Aluko & Associates, Inc. and Lonquist & Co. LLC, independent petroleum engineering consultants for 2007 and 2008, respectively:

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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. Oil and 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, 2008, 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:

During 2008, we acquired, through our 1.594674% interest in Hupecol Caracara LLC, an interest in the La Cuerva Contract covering approximately 48,000 acres in Colombia.

During 2008, we also acquired interests in two additional prospects in South Louisiana for which we advanced leasehold costs and delay rentals of approximately $231,403. We sold our interest in one of the prospects—the North Henry Bayou prospect—during 2008, retaining a 4.5% carried interest in the prospect, for which we received $60,301 and sold our interest in the second prospect—the Home Run prospect—during 2008 for which we received $213,395.

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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.

2009 Drilling and Operating Plans

As a result of the continued depressed commodity price environment in the first quarter of 2009, Hupecol, the operator of our Colombian properties, made the determination in early March to temporarily shut-in production from the majority of our wells in Colombia. During the first quarter of 2009, most of our Colombian wells remained profitable to operate; however, the Hupecol managing partners chose not to continue to produce what they considered valuable oil reserves at these low levels of profitability.

On March 14th, the Company was notified by Hupecol that the majority of its productive wells will be immediately restored to production.

As of January 1, 2009, we planned to drill a total of 11 wells during 2009, of which three wells are planned to be drilled on our domestic exploration projects and eight wells are planned to be drilled on our Colombian exploration projects. The following table reflects planned drilling activities during 2009:

Our planned drilling activity is subject to change from time to time without notice. In particular, the recent sharp decline in oil and gas prices may result in delays in, or abandonment of, planned drilling operations. Additional wells are expected to be drilled at locations to be determined based on the results of the planned drilling projects and prevailing market conditions.

Marketing

At January 1, 2009, we had no contractual agreements to sell our gas and oil production and all production was sold on spot markets.

Employees

As of March 1, 2009, we had 3 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.

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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:

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.

We May Be Affected by General Economic Conditions

The disruption experienced in U.S. and global credit markets during second half of 2008 has resulted in projected decreases in demand for oil and natural gas, resulting in a sharp drop in energy prices, and has affected the availability and cost of capital. Prolonged negative changes in domestic and global economic conditions or disruptions of either or both of the financial and credit markets may have a material adverse effect on our results of operations, financial condition and liquidity. At this time, it is unclear whether and to what extent the actions taken by the U.S. government, including, without limitation, the passage of the Emergency Economic Stabilization Act of 2008 and other measures currently being implemented or contemplated, will mitigate the effects of the crisis. With respect to Houston American Energy, while we have no immediate need to access the credit markets in the foreseeable future, the impact of the current crisis on our ability to obtain financing in the future, if needed, and the cost and terms of same, is unclear. From an operating standpoint, the current crisis has resulted in a steep decline in the price of oil and natural gas, a marked decline in the value of our reserves, a determination in March 2009 to temporarily shut-in production from our Colombian wells

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and will result in reduced revenues and reduced profitability and, if prices continue to decline, may result in deterioration of our financial position.

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. At December 31, 2008, approximately 58.1% of our proved reserves were producing. 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:

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

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prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we have and may be required to further write down the carrying value of our oil and natural gas properties. A write-down could constitute a non-cash charge to earnings. It is likely the cumulative effect of a write-down could also negatively impact the trading price of our securities.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this report.

In order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. During the years ended December 31, 2007 and 2008, revisions to prior estimates resulted in significant negative revisions to our proved reserves. Negative revisions during fiscal year 2007 amounted to 57.7% of prior year-end proved natural gas reserves and 40.2% of prior year-end proved oil reserves. Product sales and negative revisions during fiscal year 2008 amounted to 86.2% of prior year-end proved gas reserves and 83.4% of prior year-end proved oil reserves.

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:

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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:

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:

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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. During 2008, Hupecol sold its interest in the Caracara Association Contract, the largest single prospect in terms of reserves and revenues in which we then held an interest. Also, during 2008, Hupecol acquired an interest in the La Cuerva Contract. In early March 2009, Hupecol determined to temporarily shut-in production from our Colombian properties. It is possible that Hupecol will carry out similar sales or acquisitions of prospects or make similar decisions in the future. Our management intends to closely

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monitor the nature and progress of future transactions by Hupecol in order to protect our interests. However, we have no effective ability to alter or prevent a transaction and are unable to predict whether or not any such transactions will in fact occur or the nature or timing of any such transaction.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and income.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and, therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. If we are unable to develop, exploit, find or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of sustaining commercial production.

Our success depends on our management team and other key personnel, the loss of any of whom could disrupt our business operations.

Our success will depend on our ability to retain John F. Terwilliger, our principal executive officer, and James Jacobs, our chief financial 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 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.

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We may operate in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or natural gas have several adverse affects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.

We may need additional financing to support operations and future capital commitments.

While we presently believe that our operating cash flows and funds on hand will support our ongoing operations and anticipated future capital requirements, a number of factors could result in our needing additional financing, including reductions in oil and natural gas prices, declines in production, unexpected developments in operations that could decrease our revenues, increase our costs or require additional capital contributions and commitments to new acquisition or drilling programs. We have no commitments to provide any additional financing, if needed, and may be limited in our ability to obtain the capital necessary to support operations, complete development, exploitation and exploration programs or carry out new acquisition or drilling programs. We have not thoroughly investigated whether this capital would be available, who would provide it, and on what terms. If we are unable, on acceptable terms, to raise the required capital, our business may be seriously harmed or even terminated.

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to compete.

We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

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:

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In addition, in recent years, the stock market in general has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons often unrelated to their operating performance. These broad market fluctuations may adversely affect our stock price, regardless of our operating results.

The sale of a substantial number of shares of our common stock may affect our stock price.

Future sales of substantial amounts of our common stock or equity-related securities in the public market or privately, or the perception that such sales could occur, could adversely affect prevailing trading prices of our common stock and could impair our ability to raise capital through future offerings of equity or equity-related securities. No prediction can be made as to the effect, if any, that future sales of shares of common stock or the availability of shares of common stock for future sale, will have on the trading price of our common stock.

Our charter and bylaws, as well as provisions of Delaware law, could make it difficult for a third party to acquire our company and also could limit the price that investors are willing to pay in the future for shares of our common stock.

Delaware corporate law and our charter and bylaws contain provisions that could delay, deter or prevent a change in control of our company or our management. These provisions could also discourage proxy contests and make it more difficult for our stockholders to elect directors and take other corporate actions without the concurrence of our management or board of directors. These provisions:

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.

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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, 2009, our directors and executive officers owned approximately 46.6% of our outstanding common stock. As a result, our current directors and executive officers 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.

Not applicable

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.”

We may from time to time be a party to lawsuits incidental to our business. As of March 1, 2009, 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.

Not applicable

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PART II

Market Information

Our common stock is listed on the Nasdaq Global Market (“Nasdaq”) under the symbol “HUSA.” 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.

At March 12, 2009, the closing price of the common stock on Nasdaq was $2.33.

Holders

As of March 4, 2009, there were approximately 947 shareholders of record of our common stock.

Dividends

Commencing in the third quarter of 2008 and continuing in the fourth quarter of 2008, we declared and paid a quarterly cash dividend of $0.02 per share on our common stock.

The payment of future cash dividends will depend upon, among other things, our financial condition, funds from operations, the level of our capital and development expenditures, our future business prospects, contractual restrictions and any other factors considered relevant by the Board of Directors.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 2008 with respect to the shares of our common stock that may be issued under our existing equity compensation plans.

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Performance Graph

The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.

The following performance graph compares the change in the cumulative total return of Houston American Energy’s common stock, the Dow Jones U.S. Exploration and Production Index, and the S&P 500 Index for the five years ended December 31, 2008. The graph assumes that $100 was invested in the Company’s common stock and each index on December 31, 2003.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN AMONG

HOUSTON AMERICAN ENERGY CORPORATION, THE S&P 500 INDEX

AND DJ U.S. EXPL & PROD. INDEX

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The following table sets forth a summary of selected historical financial information for each of the years in the five-year period ended December 31, 2008. This information is derived from our Financial Statements and the notes thereto. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data.”

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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 2008 and 2009

Drilling Activity

During 2008, we drilled 15 international wells in Colombia, as follows:

During 2008, one domestic well, (the N. Bayou Henry Prospect) was drilled and was deemed a dry hole.

The Caddo Lake prospect was drilled during the fourth quarter of 2007. During the fourth quarter of 2008, pipeline construction and connection to the well was completed and several completion attempts in the Cotton Valley formation were not successful. Currently a Bossier Shale test is planned subject to a unit and permit being granted.

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At December 31, 2008, two wells were being drilled in Colombia and one well was being drilled in the U.S.

Sale of Caracara Assets

In June 2008, we, through Hupecol Caracara LLC as owner/operator under the Caracara Association Contract, sold all of our interest in the Caracara Association Contract and related assets. Pursuant to our investment in Hupecol Caracara LLC, we held a 1.594674% working interest in the Caracara assets, covering approximately 232,500 acres, representing our principal, and initial, Colombian prospect. At December 31, 2007, the estimated proved reserves associated with these assets totaled 787,742 barrels of oil, which represented 60.37% of our estimated proved oil and natural gas reserves.

As a result of the sale of the Caracara assets, we received net proceeds, after deduction of fees and expenses of the transaction, of $11,546,510, realized a gain on the sale of $7,615,236 and eliminated from oil and gas properties costs subject to amortization associated with the Caracara assets totaling $3,977,907.

Pursuant to the terms of the sale of the Caracara assets, on the closing date of the sale, a portion of the purchase price was deposited in escrow to settle post-closing adjustments under the purchase and sale agreement. The funds deposited in escrow will be released to us, or to the purchaser, based on post-closing adjustments 12 months following closing. Our proportionate interest in the escrow deposit, totaling $1,673,551, has been recorded as Other Current Assets. The net proceeds and the gain realized from the sale of the Caracara assets may be adjusted based on post-closing adjustments.

Colombian taxes attributable to the sale of the Caracara assets, totaling $4,394,575, were recorded and paid at the time of closing.

Production from the Caracara prospect accounted for $3,005,140 and $3,703,739 of our revenues during 2008 and 2007, respectively.

Lease operating expense from the Caracara prospect accounted for $458,240 and $641,583 of our lease operating expense during 2008 and 2007, respectively.

Leasehold Activity

During 2008, we acquired, through our 1.594674% interest in Hupecol Caracara LLC, an interest in the La Cuerva Contract covering approximately 48,000 acres in Colombia.

During 2008, we acquired interests in two additional prospects in South Louisiana for which we advanced leasehold costs and delay rentals of approximately $231,403. We sold our interest in one of the prospects—the North Henry Bayou prospect—during 2008, retaining a 4.5% carried interest in the prospect, for which we received $60,301 and sold our interest in the second prospect—the Home Run prospect—during 2008 for which we received $213,395.

Seismic Activity

During 2008, our operator in Colombia acquired approximately 65 miles of additional seismic and geological data. The additional data relates primarily to prospects in which we hold a 12.5% working interest. Our share of the costs of such data acquisition was $309,061. The operator also acquired additional seismic data on the La Cuerva prospect. Our share of this cost was $41,030.

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During 2008 we shot an additional 32.824 square miles combined of seismic on the Las Garzas and Leona contracts.

Executive Compensation—Restricted Stock, Stock Options and Bonus Payments

During 2008, we recognized compensation expense, in addition to salaries, to our two executive officers consisting of (1) $400,320 attributable to grants of 55,600 shares of restricted stock, (2) payment of cash bonuses totaling $750,000, which bonuses were contingent on the completion of the sale of the Caracara assets and were paid in June 2008, and (3) $670,045 attributable to grants of stock options.

Dividends

During the third and fourth quarters of 2008, we declared and paid cash dividends to our shareholders of $0.02 per share, or an aggregate of $1,122,031.

Macroeconomic Impact on Oil and Natural Gas Prices

Late in the third quarter of 2008 and accelerating during the fourth quarter of 2008, the United States and global economies suffered a severe disruption in credit and financial markets that have been accompanied by economic contraction and a sharp drop in the price of oil and natural gas due to a projected decline in demand for oil and natural gas. We have not historically entered into hedging transactions to reduce our exposure to commodity price risks. As a result of such macroeconomic conditions and our unhedged position, the prices at which we sell oil and natural gas declined markedly during the fourth quarter of 2008 and are expected to remain at substantially lower levels for the foreseeable future. Our total revenues and profitability declined during the fourth quarter of 2008 as a result of the decline in oil and natural gas prices and a reduction in our production and are expected to continue to be adversely affected for the foreseeable future.

Determination to Temporarily Shut-in Colombian Production

As a result of the continued depressed commodity price environment in the first quarter of 2009, Hupecol, the operator of our Colombian properties, made the determination to temporarily shut-in production from the majority of our wells in Colombia. During the first quarter of 2009, most of our Colombian wells remained profitable to operate; however, the Hupecol managing partners chose not to continue to produce what they considered valuable oil reserves at these low levels of profitability.

On March 14th, the Company was notified by Hupecol that the majority of its productive wells will be immediately restored to production.

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

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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, 2008. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves are amortized on a units-of-production method over the estimated productive life of the reserves. Unevaluated oil and gas properties are excluded from this calculation. The capitalized oil and gas property costs, less accumulated amortization, are limited to an amount (the ceiling limitation) equal to the sum of: (a) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, calculated at prices in effect as of the balance sheet date and a discount factor of 10%; (b) the cost of unproved and unevaluated properties excluded from the costs being amortized; (c) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (d) related income tax effects. Excess costs are charged to proved properties impairment expense.

Unevaluated Oil and Gas Properties. Unevaluated oil and gas properties consist principally of our cost of acquiring and evaluating undeveloped leases, net of an allowance for impairment and transfers to depletable oil and gas properties. When leases are developed, expire or are abandoned, the related costs are transferred from unevaluated oil and gas properties to depletable oil and gas properties. Additionally, we review the carrying costs of unevaluated oil and gas properties for the purpose of determining probable future lease expirations and abandonments, and prospective discounted future economic benefit attributable to the leases. We record an allowance for impairment based on a review of present value of future cash flows. Any resulting charge is made to operations and reflected as a reduction of the carrying value of the recorded asset. Unevaluated oil and gas properties not subject to amortization include the following at December 31, 2007 and 2008:

The carrying value of unevaluated oil and gas prospects include $480,532 and $88,681 expended for properties in South America at December 31, 2007 and December 31, 2008, 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:

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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.”

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, 2008 Compared to Year Ended December 31, 2007

Oil and Gas Revenues. Total oil and gas revenues increased $5,644,878, or 113.4%, to $10,622,050 in fiscal 2008 compared to $4,977,172 in fiscal 2007.

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The increase in oil and gas revenue is principally due to increased production resulting from the development of the Colombian fields, particularly fields in which we hold a higher working interest (12.5%), and higher oil prices during the first three quarters of 2008, partially offset by the sale of 34 producing wells as part of the Caracara transaction during the second quarter of 2008. During 2008, we had interests in 45 producing wells in Colombia, including the 34 Caracara wells, and 6 producing wells in the U.S as compared to 39 producing wells in Colombia and 7 producing wells in the U.S. during 2007.

Oil and gas revenues from the Caracara prospect totaled $3,005,140 and $3,703,739 during 2008 and 2007, respectively.

The following table sets forth a comparison of hydrocarbon prices for 2008 and 2007:

As a result of the sharp worldwide economic decline during the second half of 2008, our average prices realized from the sale of oil and gas declined markedly in the fourth quarter of 2008 to $59.26 per barrel of oil and $6.20 per mcf of gas. That decline in prices continued into 2009 and, as a result of such decline and the determination to temporarily shut-in production from our wells in Colombia during March of 2009, 2009 revenues are expected to decline.

The following table sets forth a comparison of oil and gas sales by region during 2008 and 2007.

Natural Gas production was down in 2008 due to production declines related to our domestic wells.

Lease Operating Expenses. Lease operating expenses, excluding joint venture expenses relating to our Colombia operations discussed below, increased 82.9% to $3,366,740 in 2008 from $1,841,119 in 2007.

The increase in lease operating expenses was attributable to the increase in the number of wells operated during 2008 and increased activities on prospects in which we hold a higher working interest (12.5%) during 2008 as compared to 2007, partially offset by the elimination of lease operating expenses on the Caracara assets following the sale of the assets in June 2008.

Following is a summary comparison of lease operating expenses, by region, for 2008 and 2007:

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Joint Venture Expenses. Joint venture expenses totaled $183,510 in 2008 compared to $149,200 in 2007. The joint venture expenses represent our allocable share of the indirect field operating and region administrative expenses billed by the operator of the Colombian concessions. The increase in joint venture expenses was attributable to an increase in drilling activity in concessions in which we own a higher working interest.

Depreciation and Depletion Expense. Depreciation and depletion expense increased by 428.9% to $5,816,691 in 2008 from $1,099,826 in 2007. This significant increase was due to a 37.6% increase in the depletable cost pool attributable to the drilling results on prospects in which we hold a higher interest, as well as a significant decrease in our proved reserve estimates at year end; partially offset by the sale of our interest in the Caracara prospect.

Impairment Expense. During 2008, we recorded a provision for impairments of $5,621,106, most of which was attributable to our South American properties. Impairments related to reduced commodity prices at year end and lower reserve estimates for our Colombian wells, as well as reduced reserve estimates for our U.S. properties as a result of lower commodity prices and lower then expected production volumes, as well as the lack of commercial production on our Caddo Lake prospect.

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 increased by 101% to $3,152,930 in 2008 from $1,568,228 in 2007. The increase in general and administrative expense was primarily attributable to increases in compensation expense relating to one time restricted stock grants ($400,320), cash bonuses payable on closing of the Caracara sale ($750,000) and stock options grants ($686,567).

Gain on sale of oil & gas properties. The sale of our Caracara assets resulted in a gain of $7,615,236 during 2008. The gain realized may be subject to adjustment based on post-closing adjustments.

Other Income. Other income consists of interest income earned on cash balances and marketable securities.

Interest income decreased 54.5% to $295,375 during 2008 from $649,792 during 2007. The decrease in interest income was attributable to reduced interest rates on short term cash investments and slightly reduced cash and cash equivalent amounts held through the year.

Income Tax Expense. Income tax expense decreased to a benefit of ($73,261) in 2008 from income tax expense of $127,116 in 2007. The decrease in income tax expense was attributable to the overall decrease to net income, due to the book impairment write-down on oil and gas properties, as well as the tax gain on the sale of the Caracara property. A deferred income tax benefit in the amount of $5,273,567 was attributable to the US and income tax expense in the amount of $5,200,306 was attributable to Colombia. Income tax expense during 2007 was entirely attributable to operations in Colombia. No U.S. income tax liability was recorded in 2007. At December 31, 2008, we had foreign tax credit carryovers of $2,019,488.

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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.

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.

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

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.

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General and Administrative Expenses. General and administrative expense (excluding stock based compensation) increased by 31.0% to $1,233,020 during 2007 from $941,324 in 2006. The increase in general and administrative expense was primarily attributable to an increase in salary to our president in mid-2006, payment of a full year’s salary to our chief financial officer hired during 2006, increases in base salary of our president and chief financial officer during the third quarter of 2007 and payment of bonuses to our president and chief financial officer during 2007.

Stock based compensation expense included in general and administrative expenses increased by 15.7% to $335,208 in 2007 as compared to $289,755 in 2006. The increase in stock-based compensation expense was attributable to the 2006 grant of stock options in connection with the hiring of our chief financial officer and the grants of options to our directors during 2007.

Other Income, Net. Other income, net, consists of interest income, net of financing costs in the nature of interest and deemed interest associated with outstanding shareholder loans and convertible notes and warrants issued in May 2005 and outstanding during part of 2006. Certain features of the convertible notes and warrants resulted in the recording of a deemed derivative liability on the balance sheet and periodic interest associated with the deemed derivative liabilities and changes in the fair market value of those deemed liabilities.

Other income, net, totaled $649,792 in 2007 compared to $99,263 in 2006. The improvement in other income, net, was attributable to interest earned on funds received from the 2006 private placement and the absence of interest expense, financing fees and derivative related expense during 2007 attributable to the retirement or conversion during 2006 of all outstanding shareholder loans and convertible notes.

Income Tax Expense (Benefit). Income tax expense decreased to $127,116 in 2007 from $510,637 in 2006. The decrease in income tax expense during 2007 was attributable to a gain of $662,668 associated with the reallocation by Hupecol of certain Colombian tax credits among the members of the various Hupecol entities, partially offset by an increase in revenue and an effective tax rate increase in Colombia. Income tax expense during 2007 and 2006 was entirely attributable to operations in Colombia. We recorded no U.S. income tax liability in 2007 or 2006. At December 31, 2007, we had net operating loss carry forward of approximately $832,821 and foreign tax credits of approximately $875,873.

Financial Condition

Liquidity and Capital Resources. At December 31, 2008, we had a cash balance of $9,910,694 and working capital of $10,536,834 compared to a cash balance of $417,818 and working capital of $10,358,502 at December 31, 2007. The increase in working capital during the period was attributable to the sale proceeds from the Caracara sale offset by increased drilling activity in Colombia and lower product prices.

Cash Flows. Operations provided cash during 2008 totaling $1,452,054 as compared to $1,801,481 of cash provided by operations during 2007. The decrease in cash flows from operations was primarily a result of cash taxes paid in Colombia.

Investing activities provided $8,787,853 during 2008 compared to $1,792,672 used during 2007. The funds provided by investing activities reflect the receipt of proceeds from the sale of the Caracara assets ($9,878,797) and the Home Run and North Henry Bayou prospects ($273,696), as well as the net sale of marketable securities of ($9,650,000) during 2008 and ($4,350,000) during 2007. Funds used in investing activities consisted primarily of investments in oil and gas properties and assets of ($10,841,353) during 2008 and ($6,142,672) during 2007.

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Financing activities used $747,031 during 2008, consisting of cash dividends paid in the amount of $1,122,031, partially offset by the receipt of $375,000 from the exercise of outstanding warrants. We had no financing activities during 2007.

Long-Term Liabilities. At December 31, 2008, we had long-term liabilities of $205,524 as compared to $135,267 at December 31, 2007. Long-term liabilities at December 31, 2008 and December 31, 2007 consisted of a reserve for plugging costs and deferred rent liability. The increase in 2008 of long-term liabilities was a result of increased plugging cost from drilling in Colombia.

Capital and Exploration Expenditures and Commitments. Our principal capital and exploration expenditures relate to our ongoing efforts to acquire, drill and complete prospects. We expect that future capital and exploration expenditures will be funded principally through funds generated from operations and funds on hand, including funds generated from the sale of our interest in the Caracara prospect.

During 2008, we invested approximately $10,841,353 for the acquisition and development of oil and gas properties, consisting of (1) drilling of 15 wells in Colombia ($9,212,662), (2) seismic and geological costs in Colombia ($700,427), (3) delay rentals on U.S. properties ($40,977), (4) leasehold costs on U.S. properties ($188,550) and (5) capital expenditures on U.S. wells ($698,737).

At December 31, 2008, 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, 2008:

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.

2009 Planned Drilling, Leasehold and Other Activities. As of December 31, 2008, we planned to drill a total of 11 wells during 2009, of which three wells are planned to be drilled on our domestic exploration projects and eight wells are planned to be drilled on our Colombian exploration projects. The following table reflects planned drilling activities during 2009:

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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, the recent sharp decline in oil and gas prices may result in delays in, or abandonment of, planned drilling operations.

We also plan to selectively evaluate and acquire interests in additional drilling prospects.

At December 31, 2008, our acquisition and drilling budget for 2009 totaled approximately $2,950,000, consisting of (1) $1,850,000 for drilling of eight wells in Colombia, (2) $1,000,000 for drilling of three domestic wells, and (3) $100,000 for infrastructure construction related cost 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, 2008.

Inflation

We believe that inflation has not had a significant impact on our operations since inception.

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 derivative commodity instruments or transactions designed to manage, or limit exposure to oil and gas price volatility.

Our financial statements appear immediately after the signature page of this report. See “Index to Financial Statements” on page 35 of this report.

Previously disclosed. See Form 8-K, filed April 19, 2007.

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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, 2008 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, 2008.

Management’s Report on Internal Control over Financial Reporting

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, 2008, 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. Based on our assessment, management has concluded that our internal control over financial reporting at December 31, 2008 were effective.

The effectiveness of our internal control over financial reporting as of December 31, 2008 has been audited by GBH CPAs, PC, an independent registered public accounting firm, as stated in their report which is included herein.

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Changes in Internal Control over Financial Reporting

At September 30, 2008, we identified deficiencies in segregation of duties as a weakness in internal controls. During the fourth quarter of 2008 we increased the involvement of members of management and other personnel in the financial processes in order to provide for the segregation of duties. As a result of such changes, we determined that the previously identified weakness no longer existed at December 31, 2008.

Except as noted above, 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 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Not applicable

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PART III

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, 2008, and their ages and positions as of that date, are as follows:

John F. Terwilliger has served as our President, CEO and Chairman since our inception in April 2001.

James J. 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.

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.

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

Equity compensation plan information is set forth in Part II, Item 5 of this Form 10-K.

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.

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.

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PART IV