HOUSTON AMERICAN ENERGY CORP - Annual Report: 2009 (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, 2009

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “accelerated filer,” “large accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one)

Large accelerated filer  ¨    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant on June 30, 2009, based on the closing sales price of the registrant’s common stock on that date, was approximately $27,345,000. 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 March 24, 2010 was 31,080,772.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company’s Proxy Statement for its 2010 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 development of concessions in the South American country of Colombia and development of properties in the U.S. onshore Gulf Coast Region, principally Texas and Louisiana. 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 South America, particularly Colombia, and in the onshore Texas Gulf Coast region 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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The following table sets forth information relating to our principal exploration projects as of December 31, 2009:

- United States Properties:

In the United States, our properties and operations are principally located in the on-shore Gulf Coast region of Louisiana and Texas.

Louisiana Properties

Our principal producing and exploration properties in Louisiana consist of the following:

In addition to the foregoing, we hold interests in the following properties in Louisiana: the 620-acre Crowley Prospect in Acadia Parish, in which we hold a 0.15% overriding royalty interest and the 640-acre Caddo Lake Prospect in Caddo Parish, in which we hold a 33.5% working interest. We have no present plans to conduct drilling on any of these prospects.

Texas Properties

Our principal exploration properties in Texas consist of the following:

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In addition to the foregoing, we hold interests in the following non-producing property in Texas: the 91.375-acre West Turkey Prospect in Hardeman Count, Texas, in which we hold a 10.0% working interest with a 7.5% net revenue interest. We have no present plans to conduct drilling on this prospect.

- Colombian Properties:

We hold interests in multiple prospects in Colombia covering approximately 970,186 gross acres. Substantially all of our holdings in Colombia are located within the 125,000 square mile Llanos Basin, one of the most active drilling regions in Colombia. We identify our Colombian prospects by the prospect operator and concessions operated.

The following table sets forth information relating to our interests in prospects in Colombia at December 31, 2009:

Hupecol Prospects

At December 31, 2009 we held interests in six concessions and one Technical Evaluation Area (“TEA”) operated by Hupecol. The six concessions are located in the Llanos Basin of Colombia and the TEA is located in the Caguan Putumayo Basin of Colombia. The six concessions and TEA cover an aggregate area of approximately 513,965 acres. Subsequent to December 31, 2009, we acquired an additional TEA (the “Macaya TEA”) in the Caguan Putumayo Basin which is also operated by Hupecol. The Macaya TEA covers an area of 195,171 acres.

At December 31, 2009, five of the Hupecol concessions had production, we had interests in 18 gross wells (2.032 net wells) operated by Hupecol and our net daily production from interests operated by Hupecol was approximately 652 barrels of oil (no natural gas). Well depths range from 3,500 feet to 5,800 feet.

Our interest in each of the described concessions 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 and the La Cuerva Contract. We hold a 6.25% working interest in the Surimena concession and a 1.594674% working interest in the La Cuerva Contract.

Our working interest in each of the concessions is subject to an escalating royalty ranging from 8% to 20% depending upon production volumes and pricing and an additional 6% to 10% per concession when 5,000,000 barrels of oil have been produced on that concession.

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For 2010, Hupecol has advised us that they plan to drill 12 additional wells on 6 concessions. See “Potential Sale of Certain Hupecol Holdings” below.

SK Energy Prospect

Pursuant to a Farmout Agreement and Joint Operating Agreement, we hold an interest in the 345,452 acre CPO 4 Block located in the Western Llanos Basin and operated by SK Energy Co. LTD. Under the Joint Operating Agreement, effective retroactive to May 31, 2009, SK will act as operator of the CPO 4 Block and we will pay 25.0% of all past and future cost related to the CPO 4 block, as well as an additional 12.5% of the Seismic Acquisition Costs incurred during the Phase 1 Work Program, for which we will receive a 25.0% interest in the CPO 4 Block. Our share of the past costs incurred was $194,584.

The Phase 1 Work Program consists of reprocessing approximately 400 kilometers of existing 2-D seismic data, the acquisition, processing and interpretation of a 2-D seismic program containing approximately 620 kilometers of data and the drilling of two exploration wells. The Phase 1 Work Program is estimated to be completed by June 1, 2011 and our costs for the entire Phase 1 Work Program are estimated to total approximately $15,000,000, with $10.2 million of that amount budgeted for 2010.

For 2010, SK Energy has advised us that they plan to focus on completion of seismic work on the CPO 4 Block and preparation for drilling of the initial exploration wells on the block.

Shona Energy Prospect

Pursuant to a Farmout Agreement with Shona Energy Limited we hold an interest in the 110,769 acre Serrania Block located in the Caguan Putumayo Basin. Under the Farmout Agreement we will pay 25% of designated Phase 1 geological and seismic costs in return for a 12.5% interest in the Contract for Exploration and Production covering the Block. The net costs incurred by Houston American Energy during 2009 for the Phase 1 geological and seismic costs were approximately $390 thousand.

For 2010, Shona Energy has advised us that they plan to complete seismic work on the Serrania Block and to drill two initial wells on the block. Houston American Energy’s estimated net cost to complete this work is approximately $2.0 million.

Potential Sale of Certain Hupecol Holdings

In September 2009, we were advised that Hupecol had retained Scotia Waterous for purposes of evaluating a possible transaction (a “Transaction”) involving the monetization of five exploration and production contracts covering approximately 413,000 acres comprising the Leona Block, La Cuerva Block, Dorotea Block, Las Garzas Block and Cabiona Block in Colombia. The Transaction may involve the sale of some or all of the assets and operations of the subject properties, an exchange or trade of assets, or other similar transaction and may be effected in a single transaction or a series of transactions. Scotia Waterous established a process whereby interested parties may evaluate a potential Transaction and has established a due date for proposals of April 6, 2010.

We are an investor in Hupecol and our interest in the assets and operations of Hupecol that would be included in any Transaction represent a substantial portion of our assets and operations in Colombia and are our principal revenue producing assets and operations. We intend to closely monitor the nature and progress of the Transaction in order to protect the interests of our company and our shareholders. However, we have no effective ability to alter or prevent a Transaction and are unable to predict whether or not a Transaction will in fact occur or the nature or timing of any such Transaction.

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Further, we are unable to estimate the actual value that we might derive from any such Transaction and whether any such Transaction will ultimately be beneficial to our company and our shareholders.

Drilling Activity

During 2009, we participated in the drilling of a total of 15 gross wells, of which ten were classified as exploratory and five were classified as development. Our 2009 drilling program achieved a 60.0% success rate. The following table summarizes the number of wells drilled during 2009, 2008, and 2007, excluding any wells drilled under farmout agreements, royalty interest ownership, or any other wells in which we do not have a working interest.

Productive wells are wells that are found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

As of December 31, 2009, we had no wells in progress or awaiting completion in the United States and 1 gross (0.125 net) well in progress or awaiting completion in Colombia.

Seismic Activity

During 2009, our operators in Colombia acquired approximately 155 square miles of additional seismic and geological data. The additional data relates primarily to the Serrania and La Cuerva concessions where we hold 12.5% and 1.59% working interest, respectively. Our share of the costs of such data acquisition was $438,875.

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Productive Wells

Productive wells consist of producing wells and wells capable of production, including shut-in wells. A well bore with multiple completions is counted as only one well. As of December 31, 2009, we owned interests in 26 gross wells containing multiple completions. As of December 31, 2009, we had ownership interests in productive wells, categorized by geographic area, as follows:

Volume, Prices and Production Costs

The following table sets forth certain information regarding the production volumes, average prices received and average production costs associated with our sales of gas and oil, categorized by geographic area, for each of the three years ended December 31, 2009:

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Natural Gas and Oil Reserves

Reserve Estimates

The following table sets forth, as of December 31, 2009, our net oil and natural gas reserves categorized as proved developed, proved undeveloped and total proved, and categorized by geographic area.

Revisions to SEC Oil and Gas Reserve Reporting Requirements.

Effective December 31, 2008, the SEC effected revisions designed to modernize the oil and gas company reserves reporting requirements. The revisions are effective for annual reports filed on or after December 15, 2009. Among other things, the revised reporting requirements include:

Reserve Estimation Process, Controls and Technologies.

The reserve estimates set forth above were prepared by Lonquist & Co., LLC. Lonquist & Co. also estimated the PV-10 value of our proved reserves, as of December 31, 2009, at $15,820,559. The

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PV-10 value is a widely used measure of value of oil and natural gas assets and represents a before-tax present value of estimated future cash flows discounted at 10%. Due to the inherent uncertainties and the limited nature of reservoir data, proved, probable and possible reserves are subject to change as additional information becomes available. The reserves, future cash flows and present value are based on various assumptions, including those prescribed by the Securities and Exchange Commission (“SEC”), and are inherently imprecise. Although we believe the assumptions utilized are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from the amounts reflected above. Also, in computing and reporting PV-10 value, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards. The estimated present value of proved reserves does not include indirect expenses such as general and administrative expenses, debt service and future income tax expense or depletion, depreciation, and amortization.

In accordance with applicable financial accounting and reporting standards of the SEC, our proved reserves and the present value of proved reserves set forth herein were computed using average oil and natural gas sales prices as of the first trading day of each month over the twelve months ended December 31, 2009 which prices are held constant throughout the life of the properties. Quantities of proved reserves and their present value are affected by changes in oil and natural gas prices. The prices utilized for the purpose of determining our proved reserves and the present value of proved reserves as of December 31, 2009 were a WTI Cushing spot price of $61.19 per Bbl and a Henry Hub spot natural gas price of $4.24 per MMBtu, adjusted by property for energy content, quality, transportation fees, and regional price differentials. Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and gas than would have resulted under the previous rules. Use of new 12-month average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of approximately 144.2 mboe in our Colombian reserves.

Lonquist & Co. is an independent professional engineering firm specializing in the technical and financial evaluation of oil and gas assets. Lonquist & Co’s report was conducted under the direction of Don E. Charbula, P.E., Vice President of Lonquist & Co. Mr. Charbula holds a BS in Petroleum Engineering from The University of Texas at Austin and is a registered professional engineer with more than 29 years of experience in production engineering, reservoir engineering, acquisitions and divestments, field operations and management. Lonquist & Co., and its employees, have no interest in our company and were objective in determining our reserves.

The SEC’s new rules expanded the technologies that a company can use to establish reserves. The SEC now allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Lonquist used a combination of production performance, offset analogies, seismic data and their interpretation, subsurface geologic data and core data to estimate our reserves.

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Proved Undeveloped Reserves.

As of December 31, 2009, our proved undeveloped (“PUD”) reserves totaled 894.2 mbls of oil and 0.0 mcf of natural gas, for a total of 894.2 mboe.

PUD Locations.

All of our PUD reserves at December 31, 2009 were associated with our properties operated by Hupecol in Colombia. We had no PUD reserves associated with our U.S. properties.

Changes in PUD Reserves.

Changes in PUD Reserves that occurred during 2009 were due to:

Development Costs.

Estimated future development costs relating to the development of PUDs are projected to be approximately $3.681 million in 2010 and $7.594 million thereafter.

Drilling Plans.

All PUD locations are scheduled to be drilled or otherwise converted to proved developed reserves before the end of 2014. None of our PUD locations have been booked for longer than five years.

Developed and Undeveloped Acreage

The following table sets forth the gross and net developed and undeveloped acreage (including both leases and concessions), categorized by geographical area, which we held as of December 31, 2009:

Developed acreage is comprised of leased acres that are within an area spaced by or assignable to a productive well. Undeveloped acreage is comprised of leased acres with defined remaining terms and not within an area spaced by or assignable to a productive well.

As is customary in the oil and natural gas industry, we can generally retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by paying delay rentals during the remaining primary term of leases. The oil and natural gas leases in which we have an interest are for varying primary terms and, if production under a lease continues from our developed lease acreage beyond the primary term, we are entitled to hold the lease for as long as oil or natural gas is produced.

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Many of the leases and concessions comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the acreage has been established prior to such date, in which event the lease or concession will remain in effect until the cessation of production. The following table sets forth, as of December 31, 2009, the expiration periods of the gross and net acres that are subject to leases or concessions summarized in the above table of undeveloped acreage.

Title to Properties

Title to properties is subject to royalty, overriding royalty, carried working, net profits, working and other similar interests and contractual arrangements customary in the gas and oil industry, liens for current taxes not yet due and other encumbrances. As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than preliminary review of local records).

Investigation, including a title opinion of local counsel, generally is made before commencement of drilling operations.

Marketing

At January 1, 2010, we had no contractual agreements to sell our gas and oil production and all production was sold on spot markets.

Employees

As of March 24, 2010, 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.

Regulatory Matters

Regulation of Oil and Gas Production, Sales and Transportation

The oil and gas industry is subject to regulation by numerous national, state and local governmental agencies and departments. Compliance with these regulations is often difficult and costly and noncompliance could result in substantial penalties and risks. Most jurisdictions in which we operate also have statutes, rules, regulations or guidelines governing the conservation of natural resources, including the unitization or pooling of oil and gas properties, minimum well spacing, plugging and abandonment of wells and the establishment of maximum rates of production from oil and gas wells. Some jurisdictions also require the filing of drilling and operating permits, bonds and reports. The failure to comply with these statutes, rules and regulations could result in the imposition of fines and penalties and the suspension or cessation of operations in affected areas.

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Environmental Regulation

Various federal, state and local laws and regulations relating to the protection of the environment, including the discharge of materials into the environment, may affect our exploration, development and production operations and the costs of those operations. These laws and regulations, among other things, govern the amounts and types of substances that may be released into the environment, the issuance of permits to conduct exploration, drilling and production operations, the discharge and disposition of generated waste materials and waste management, the reclamation and abandonment of wells, sites and facilities, financial assurance and the remediation of contaminated sites. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations and may require the suspension or cessation of operations in affected areas.

The environmental laws and regulations applicable to our U.S. operations include, among others, the following United States federal laws and regulations:

Colombia has similar laws and regulations designed to protect the environment.

We routinely obtain permits for our facilities and operations in accordance with these applicable laws and regulations on an ongoing basis. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of our facilities or operations.

The ultimate financial impact of these environmental laws and regulations is neither clearly known nor easily determined as new standards are enacted and new interpretations of existing standards are rendered. Environmental laws and regulations are expected to have an increasing impact on our operations. In addition, any non-compliance with such laws could subject us to material administrative, civil or criminal penalties, or other liabilities. Potential permitting costs are variable and directly associated with the type of facility and its geographic location. Costs, for example, may be incurred for air emission permits, spill contingency requirements, and discharge or injection permits. These costs are considered a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with government regulations.

Although we do not operate the properties in which we hold interests, noncompliance with applicable environmental laws and regulations by the operators of our oil and gas properties could expose us, and our properties, to potential costs and liabilities associated with such environmental

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laws. While we exercise no oversight with respect to any of our operators, we believe that each of our operators is committed to environmental protection and compliance. However, since environmental costs and liabilities are inherent in our operations and in the operations of companies engaged in similar businesses and since regulatory requirements frequently change and may become more stringent, there can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production.

Climate Change Legislation and Greenhouse Gas Regulation

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, many nations have agreed to limit emissions of “greenhouse gases” or “GHGs” pursuant to the United Nations Framework Convention on Climate Change, and the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are considered “greenhouse gases” regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol, several states have adopted legislation and regulations to reduce emissions of greenhouse gases. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect our operations and demand for our products. Additionally, the United States Supreme Court has ruled, in Massachusetts, et al. v. EPA, that the EPA abused its discretion under the Clean Air Act by refusing to regulate carbon dioxide emissions from mobile sources. As a result of the Supreme Court decision and the change in presidential administrations, on December 7, 2009, the EPA issued a finding that serves as the foundation under the Clean Air Act to issue other rules that would result in federal greenhouse gas regulations and emissions limits under the Clean Air Act, even without Congressional action. As part of this array of new regulations, on September 22, 2009, the EPA also issued a GHG monitoring and reporting rule that requires certain parties, including participants in the oil and natural gas industry, to monitor and report their GHG emissions, including methane and carbon dioxide, to the EPA. The emissions will be published on a register to be made available on the Internet. These regulations may apply to our operations. The EPA has proposed two other rules that would regulate GHGs, one of which would regulate GHGs from stationary sources, and may affect sources in the oil and natural gas exploration and production industry and the pipeline industry. The EPA’s finding, the greenhouse gas reporting rule, and the proposed rules to regulate the emissions of greenhouse gases would result in federal regulation of carbon dioxide emissions and other greenhouse gases, and may affect the outcome of other climate change lawsuits pending in United States federal courts in a manner unfavorable to our industry.

On June 26, 2009, the United States House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or ACESA. On November 5, 2009 the Senate Committee on Environment and Public Works approved the “Clean Energy Jobs and American Power Act of 2009,” authored by John Kerry and Barbara Boxer, that is similar in many ways to ACESA. One of the purposes of these bills is to control and reduce emissions of greenhouse gases in the United States. These bills would establish an economy-wide cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions of 17% to 20% (from 2005 levels) by 2020, and by over 80% by 2050. Under these bills, most sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet the overall emission reduction goals of the bills. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The net effect of these bills would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. President Obama has indicated that he is in support of the adoption of legislation such as the two bills discussed above, and the White House is expending significant efforts to push for the legislation.

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Two recent court decisions, one before the United States Second Circuit Court of Appeals and one before the United States Fifth Circuit Court of Appeals (The Fifth Circuit) have allowed cases to proceed. In the first case, Connecticut v. American Electric Power, the Second Circuit ruled that several states and other plaintiffs could continue a suit to impose GHG reductions on several utility defendants, concluding that a political question and standing objections of the defendants did not prohibit the suit from going forward. The Fifth Circuit, in Comer v. Murphy Oil, ruled that plaintiffs could similarly pursue a damage suit and the political question did not prohibit the suit. This case involves claims by plaintiffs who suffered damages from Hurricane Katrina that are seeking to recover damages from certain GHG emitters asserting their emissions contributed to their increased damages. In another case filed in the Texas District Court in Austin on October 6, 2009, a citizens group sued the Texas Commission on Environmental Quality (TCEQ) asserting that the agency was required to regulate carbon dioxide emissions from parties applying for permits under the Texas Clean Air Act. The result of this lawsuit could impose additional regulations on oil and gas operations in Texas, if the Texas courts require the TCEQ to regulate carbon dioxide and perhaps other GHGs such as methane. We may be subject to the EPA GHG monitoring and reporting rule, and potentially new EPA permitting rules if adopted to apply GHG permitting obligations and emissions limitations under the federal Clean Air Act. Even if no federal greenhouse gas regulations are enacted, or if the EPA issues regulations, more than one-third of the states have begun taking action on their own to control and/or reduce emissions of greenhouse gases. Several multi-state programs have been developed or are in the process of being developed: the Regional Greenhouse Gas Initiative involving 10 Northeastern states, the Western Climate Initiative involving seven western states, and the Midwestern Greenhouse Gas Reduction Accord involving seven states. The latter two programs have several other states acting as observers and they may join one of the programs at a later date. Foreign governments, including Colombia, have similarly begun various initiatives with respect to the regulation and reduction of GHGs. Any of the climate change regulatory and legislative initiatives described above could have a material adverse effect on our business, financial condition, and results of operations.

Web Site Access to Reports

Our Web site address is www.houstonamericanenergy.com. We make available, free of charge on or through our Web site, our annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and all amendments to these reports as soon as reasonably practicable after such material is electronically filed with, or furnished to, the United States Securities and Exchange Commission.

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:

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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 financial and credit markets, and the accompanying economic contraction, during second half of 2008 and continuing through 2009 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 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 crisis experienced during the 2008-2009 period 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 and reduced revenues and profitability. While prices have recovered a portion of their decline and stabilized, continued weakness and uncertainty in U.S. and global markets may result in deterioration in commodity prices and in 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, 2009, approximately 73.5% of our proved reserves were undeveloped. 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, including funds received from our 2009 offering of common stock, 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, borrowings or other means.

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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 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 reported.

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

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Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development activities, prevailing oil and natural gas prices and other factors, many of which are beyond our control. During the years ended December 31, 2008 and 2009, revisions to prior estimates resulted in significant negative revisions to our proved reserves in 2008 and positive revisions in 2009. 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. Positive revisions during fiscal year 2009 amounted to 46.8% of prior year-end gas reserves and 8.2% 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 costs on the date of the estimate and average prices over the preceding twelve months. Actual future prices and costs may differ materially from those used in the present value estimate. If future prices 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 and operating 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:

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 proved undeveloped. 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.

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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:

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

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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.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

The Obama Administration has proposed legislation that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

On December 15, 2009, the U.S. Environmental Protection Agency (“EPA”) officially published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009, the EPA had proposed two sets of regulations in anticipation of finalizing its findings that would require a reduction in emissions of greenhouse gases from motor vehicles and that could also lead to the imposition of greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas that we produce.

Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade

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program to reduce U.S. emissions of greenhouse gases including carbon dioxide and methane. ACESA would require a 17% reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and the Obama Administration has indicated its support of legislation to reduce greenhouse gas emissions through an emission allowance system. Although it is not possible at this time to predict when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas that we produce.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills currently pending before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, these bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

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.

A 40-year armed conflict between government forces and anti-government insurgent groups and illegal paramilitary groups—both funded by the drug trade—continues in Colombia. Insurgents continue to attack civilians and violent guerilla activity continues in many parts of the country. While our operators take measures to protect our assets, operations and personnel from guerilla activity, continuing attempts to reduce or prevent guerilla activity may not be successful and guerilla activity may disrupt our operations in the future. There can also be no assurance that we can maintain the safety of our operations and personnel in Colombia or that this violence will not affect our operations in the future. Continued or heightened security concerns in Colombia could also result in a significant loss to us.

Additionally, Colombia is among several nations whose eligibility to receive foreign aid from the United States is dependent on its progress in stemming the production and transit of illegal drugs,

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which is subject to an annual review by the President of the United States. Although Colombia is currently eligible for such aid, Colombia may not remain eligible in the future. A finding by the President that Colombia has failed demonstrably to meet its obligations under international counternarcotics agreements may result in any of the following:

Each of these consequences could result in adverse economic consequences in Colombia and could further heighten the political and economic risks associated with our operations there. Any changes in the holders of significant government offices could have adverse consequences on our relationship with ANH and Ecopetrol and the Colombian government’s ability to control guerrilla activities and could exacerbate the factors relating to our foreign operations. Any sanctions imposed on Colombia by the United States government could threaten our ability to obtain necessary financing to develop the Colombian properties or cause Colombia to retaliate against us, including by nationalizing our Colombian assets. Accordingly, the imposition of the foregoing economic and trade sanctions on Colombia would likely result in a substantial loss and a decrease in the price of our common stock. The United States may impose sanctions on Colombia in the future, and we cannot predict the effect in Colombia that these sanctions might cause.

Our operations in Colombia are controlled by operators which may carry out transactions affecting our Colombian assets and operations without our consent.

Our operations in Colombia are subject to a substantial degree of control by the operators of the properties in which we hold interests in Colombia. We are an investor in Hupecol and our interest in the assets and operations of Hupecol represent a substantial portion 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 and, in the fourth quarter of 2009, Hupecol commenced efforts to sell certain concessions in Colombia. 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 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.

In addition to Hupecol’s control of decisions regarding properties operated by Hupecol in Colombia, as minority owners, we are subject to substantial control of other properties in Colombia in which we hold interests that are operated by SK Energy and Shona Energy. Our Colombian assets consist exclusively of minority, non-operator project interests in certain Colombian assets owned and operated by Hupecol, LLC, a 25% non-operated working interest in certain Colombian assets owned and operated by SK Energy Co. LTD and a 12.5% non-operated working interest in certain Colombian assets owned and operated by Shona Energy Ltd. Our passive investments in such Colombian assets constitute our principal assets, and as a result, our financial results are directly affected by the independent strategies and decisions of Hupecol, SK Energy and Shona Energy.

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

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

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

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

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

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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, including funds provided by our 2009 common stock offering, 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. In particular, given our recent commitments to participate in additional properties operated by Hupecol and our agreements to participate in the development of additional prospects in Colombia operated by Shona Energy and SK Energy, we may be subject to substantially greater calls for commitments to provide capital to support development of our additional interests. 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, bylaws, and 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 24, 2010, our directors and executive officers owned approximately 42% 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 24, 2010, 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.

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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 closing sale prices of our common stock, and cash dividends declared, for each quarter during the past two fiscal years.

At March 16, 2010, the closing price of the common stock on Nasdaq was $14.90.

Holders

As of March 24, 2010, there were approximately 924 shareholders of record of our common stock.

Dividends

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, 2009 with respect to the shares of our common stock that may be issued under our existing equity compensation plans.

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Not applicable

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. Since the fourth quarter of 2002, we have expanded our focus to include oil and gas exploration in Colombia 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.

Recent Developments

Production Levels, Commodity Prices and Revenues

Our production levels and revenues during 2009, as compared to 2008, were affected by the sale of our Caracara prospect in 2008 and the sharp decline in oil and natural gas prices that began during the second half of 2008 and continued through the third quarter of 2009. As a result of depressed commodity prices, our operator in Colombia temporarily shut-in production from a majority of our Colombian properties and we had no sales in Colombia from February 13, 2009 through April 5, 2009.

During 2008, the Caracara prospect accounted for approximately 29,954 barrels of oil (net to the Company) produced, or 24% of our oil production, and $3,005,140 of revenues.

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Drilling Activity

During 2009, we drilled 14 international wells in Colombia, as follows:

During 2009, we drilled one domestic well, the Wilberts & Sons #1 (Home Run Prospect) which was a dry hole and re-completed one domestic well, the Allar # 1 which was placed into production on May 27, 2009.

At December 31, 2009, drilling operations were ongoing in Colombia on one well.

Domestic Leasehold Activity

During 2009, we acquired interests in four additional prospects in Louisiana, the N. Jade and W. Jade prospects, acquired for $67,480, and the Profit Island and North Profit Island prospects, acquired for $350,644. Subsequent to purchasing our interest in the Profit and North Profit Island prospects, on July 16, 2009 we received $353,896 from the sale of part of our interest in the Profit Island prospect. We still retain an interest in both of the prospects.

During 2009, we acquired (1) a 2.5% working interest in over 6,520 acres under lease within a 50,000 acre area of mutual interest (AMI) in Karnes County, Texas, for a purchase price of $75,000, and (2) a 1.25% Overriding Royalty in the same leases and all acreage within the AMI, for a purchase price of $100,000. Per the contract, we will be carried to the completion point on the first well.

Colombian Farm-Outs and Participations.

In June 2009, we entered into a farmout agreement with Shona Energy Limited pursuant to which we will pay 25% of designated Phase 1 geological and seismic costs relating to the Serrania Contract for Exploration and Production relating to the approximately 110,769 acre Serrania Block in Colombia and for which we will receive a 12.5% interest in the Serrania Contract.

In September 2009, we elected to participate for our percentage interest (12.5%) in the Los Picachos Technical Evaluation Agreement (the “Los Picachos TEA”). The Los Picachos TEA was entered into in August 2009 by and between the Colombian National Hydrocarbons Agency (the “ANH”) and Hupecol Operating Co. LLC and encompasses an 86,235 acre region located to the west and northwest of the Serrania block, which is located in the municipalities of Uribe and La Macarena in the Department of Meta in the Republic of Colombia. As a result of the election to participate, we agreed to pay our proportionate share, or 12.5%, of the acquisition costs and costs for the minimum work program contained in the Los Picachos TEA.

On October 16, 2009, we announced the approval by the ANH of a Farmout Agreement and Joint Operating Agreement with SK Energy Co. LTD., a Korean multinational conglomerate (“SK Energy”), relating to the CPO 4 Contract for Exploration and Production (the “CPO 4 Contract”) covering the 345,452 net acre CPO 4 Block located in the Western Llanos Basin in the Republic of Colombia.

Under the Joint Operating Agreement, effective retroactive to May 31, 2009, SK Energy will act as operator of the CPO 4 Block and we agreed to pay 25.0% of all past and future cost related to the CPO

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4 block as well as an additional 12.5% of the Seismic Acquisition Costs incurred during the Phase 1 Work Program, for which we will receive a 25.0% interest in the CPO 4 Block. Our share of the past costs was $194,584.

The Phase 1 Work Program consists of reprocessing approximately 400 kilometers of existing 2-D seismic data, the acquisition, processing and interpretation of a 2-D seismic program containing approximately 620 kilometers of data and the drilling of two exploration wells. The Phase 1 Work Program is estimated to be completed by June 1, 2011. Our share of the costs for the entire Phase 1 Work Program are estimated to total approximately $15,000,000.

Subsequent to year-end, in February 2010, we elected to participate for our percentage interest (12.5%) in the Macaya Technical Evaluation Agreement (the “Macaya TEA”). The Macaya TEA was entered into in February 2010 by and between the ANH and Hupecol and encompasses a 195,171 acre region located to the southeast of the Serrania block. As a result of the election to participate, we agreed to pay our proportionate share, or 12.5%, of the acquisition costs and costs for the minimum work program contained in the Macaya TEA.

Acquisition Activity

In light of our debt-free capital structure, solid cash position and low overhead and in response to conditions in the oil and gas market, in particular the non-economical cost and capital structures of many operators and financiers following the sharp decline in commodity prices during the second half of 2008 continuing into early 2009, during the first half of 2009, we began actively seeking opportunistic oil and gas acquisitions.

Pursuant to those efforts, on February 4, 2009, we entered into a letter agreement (the “Letter Agreement”) with Yazoo Pipeline Co., L.P. (“Yazoo”), Sterling Exploration & Production Co., L.L.C. (“Sterling”), and Matagorda Operating Company (together with Yazoo and Sterling, the “Debtors”), pursuant to which we agreed to provide debtor-in-possession financing (“DIP Financing”) to the Debtors subject to approval of the Letter Agreement by the U.S. Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). On February 4, 2009, the Bankruptcy Court entered an order approving the DIP Financing on the terms set out in the Letter Agreement.

Under the terms of the Letter Agreement, we agreed to advance to the Debtors up to $300,000, with all advances bearing interest at 10% per annum and being repayable in full ninety (90) days from approval of the DIP Financing by the Bankruptcy Court, or the earlier consummation of a sale of the principal assets of the Debtors to our company. Under the Letter Agreement, we and the Debtors agreed to commence negotiations and due diligence with respect to the potential acquisition by our company of the principal assets of the Debtors based on certain financial terms described in the Letter Agreement. Advances were made under the Letter Agreement in the total amount of $115,724.

Pursuant to our rights under the Letter Agreement, after conducting due diligence with respect to the Debtors, we determined to terminate negotiations with the Debtors with respect to the potential acquisition of the assets of the Debtors. On April 10, 2009, the Debtors repaid the DIP Financing in full in the amount of $117,897, including principal and interest, and at December 31, 2009 no amounts were owed to us relative to the DIP Financing.

We intend to continue to seek out and evaluate opportunities to acquire existing oil and gas assets and operations where we determine attractive returns on invested capital can be realized in current market conditions and superior returns can be derived from a recovery in primary prices. There is no assurance, however, that we will be successful in our efforts to identify and acquire oil and gas assets or operations or that any acquisitions that may be consummated will provide the returns expected by management.

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Possible Hupecol Transaction

In September 2009, we were advised that Hupecol LLC had retained Scotia Waterous for purposes of evaluating a possible transaction (a “Transaction”) involving the monetization of five exploration and production contracts covering approximately 413,000 acres comprising the Leona Block, La Cuerva Block, Dorotea Block, Las Garzas Block and Cabiona Block in Colombia. The Transaction may involve the sale of some or all of the assets and operations of the subject properties, an exchange or trade of assets, or other similar transaction and may be effected in a single transaction or a series of transactions. Scotia Waterous has established a process whereby interested parties may evaluate a potential Transaction and has established a due date for proposals of April 6, 2010.

We are an investor in Hupecol and our interest in the assets and operations of Hupecol that would be included in any Transaction represent a substantial portion of our assets and operations in Colombia and are our principal revenue producing assets and operations. We intend to closely monitor the nature and progress of the Transaction in order to protect the interests of our company and our shareholders. However, we have no effective ability to alter or prevent a Transaction and are unable to predict whether or not a Transaction will in fact occur or the nature or timing of any such Transaction. Further, we are unable to estimate the actual value that we might derive from any such Transaction and whether any such Transaction will ultimately be beneficial to our company and our shareholders.

Seismic Activity

During 2009, our operators in Colombia acquired approximately 155 square miles of additional seismic and geological data. The additional data relates primarily to the Serrania and La Cuerva concessions where we hold 12.5% and 1.60% working interest, respectively. Our share of the costs of such data acquisition was $438,875.

Compensation Expense—Stock Options

During 2009, we granted 120,000 stock options to our Chief Financial Officer and 26,665 stock options to our non-employee directors. Our total non-cash compensation expense for 2009 was $1,080,128.

Sale of Common Stock

In December 2009, we sold 2,890,000 shares of common stock in a registered direct offering to select institutional investors at $4.68 per share pursuant to which we received net proceeds of approximately $12.8 million. We intend to use the net proceeds of the offering for general working capital purposes, including funding our share of costs of development of properties in which we hold interests in Colombia and in the U.S.

Dividends

During 2009, we declared and paid cash dividends to our shareholders of $0.035 per share, or an aggregate of $980,057.

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.

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Full Cost Method of Accounting for Oil and Gas Activities. We follow the full cost method of accounting for oil and gas property acquisition, exploration and development activities. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisition, geological and geophysical work, delay rentals, costs of drilling, completing and equipping successful and unsuccessful oil and gas wells and related internal costs that can be directly identified with acquisition, exploration and development activities, but does not include any cost related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized unless significant amounts of oil and gas reserves are involved. No corporate overhead has been capitalized as of December 31, 2009. 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 using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) 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. Unevaluated oil and gas properties not subject to amortization include the following at December 31, 2008 and 2009:

The carrying value of unevaluated oil and gas prospects include $88,681 and $2,993,732 expended for properties in South America at December 31, 2008 and December 31, 2009, respectively. We are maintaining our interest in these properties and development has or is anticipated to commence within the next twelve months.

Stock-Based Compensation. We account for stock-based compensation in accordance with the provisions of FASB ASC Topic 718. 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.

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Results of Operations

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Oil and Gas Revenues. Total oil and gas revenues decreased 23.6%, to $8,116,275 in 2009 from $10,622,050 in 2008.

The decrease in oil and gas revenue was due to: (1) a decline in oil and gas prices received during 2009 (approximately $84,000 based on lower average gas prices realized during 2009 and approximately $2.8 million based on lower average oil prices), (2) the cessation of production and sales from the majority of our Colombian properties for 52 days in early 2009, and (3) the sale of our Caracara interest in June 2008.

The following table sets forth the gross and net producing wells, net oil and gas production volumes and average hydrocarbon sales prices for 2009 and 2008:

Production volumes were less then what they otherwise would have been in 2009 due to the sale of our Caracara interest during 2008 (accounting for 29,954 barrels of production and $3,005,140 of revenues during 2008) and the cessation of production and sales from the majority of our Colombian properties for 52 days in early 2009 as a result of unfavorable commodity prices, partially offset by increased production in fields in which we hold higher working interests (12.5% vs. 1.6% in Caracara). Giving pro forma effect to exclude sales revenues from the Caracara interest, which was sold in June 2008, oil and gas revenues for 2008 would have been $7,616,910.

The decline in average sales prices realized reflects the sharp worldwide economic decline, and accompanying decline in commodity prices, during the second half of 2008 continuing through 2009.

Oil and gas sales revenues for 2009 and 2008, by region, were as follows:

Lease Operating Expenses. Lease operating expenses, excluding joint venture expenses relating to our Colombian operations discussed below, increased 41% to $4,746,295 in 2009 from $3,366,740 in 2008.

The increase in lease operating expenses as a percentage of revenues, from 32% of revenues in 2008 to 58% of revenues in 2009, was primarily attributable to the temporary cessation of production from a majority of our Colombian properties during the 2009 period as discussed above, the steep decline in oil and gas prices and an increase in our average working interest following the Caracara

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sale, as well as increased cost in Colombia relating to personnel expenses, facilities and equipment expenses, catering expenses, road maintenance, as well environmental services expenses.

Following is a summary comparison of lease operating expenses for the periods.

Hupecol, our operator in Colombia, has implemented cost cutting measures in order to improve field economics from our Colombian operations. We have also seen declines in drilling and operating costs in the Llanos Basin which, together, are expected to result in improved margins during 2010 and beyond.

Joint Venture Expenses. Joint venture expenses totaled $172,890 in 2009 compared to $183,510 in 2008. 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 decrease in the number of producing wells during 2009.

Depreciation and Depletion Expense. Depreciation and depletion expense decreased by 67% to $1,900,631 in 2009 from $5,816,691 in 2008. The decrease in depreciation and depletion was due to an increase in reserves due to exploration and development. This resulting increase in our reserves from exploration and development activities lowered our depreciation rate per barrel.

Impairment Expense. During 2008, we recorded a provision for impairment of oil and gas properties 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, 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.

Gain on sale of oil & gas properties. The sale of our Caracara assets resulted in a gain of $7,615,236 during 2008.

General and Administrative Expenses. General and administrative expense decreased by 12% to $2,768,195 in 2009 from $3,152,930 in 2008. The decrease in general and administrative expense was primarily attributable to decreases in employee compensation and professional fees, including a decrease of $750,000 related to cash bonuses paid in 2008 not repeated in 2009 and $400,320 related to restricted stocks grants in 2008.

Other Income. Other income consists of interest earned on cash balances and marketable securities. Other income totaled $64,882 in 2009 as compared to $295,375 in 2008. The decrease in other income resulted from the sale of the balance of our marketable securities during early 2008 and a reduction in interest rates on short-term cash investments, partially offset by interest earned on DIP Financing provided to the Creditors under the Letter Agreement.

Income Tax Expense/Benefit. We reported an income tax benefit of $737,406 in 2009 as compared to an income tax benefit of $73,261 in 2008.

The income tax benefit during 2009 was primarily attributable to net operating losses generated in Colombia and the United States and the refund during 2009 of approximately $548,000 of Colombian taxes. The income tax benefit during 2009 was attributable $402,663 to the U.S. and $334,743 to Colombia.

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The income tax benefit during 2008 was primarily attributable to a decrease in valuation allowance and the availability of U.S. foreign tax credits that more than offset taxes attributable to operating income in Colombia. A deferred income tax benefit in the amount of $5,273,567 was attributable to the U.S. and income tax expense in the amount of $5,200,306 was attributable to Colombia during 2008. Income tax expense during 2008 was entirely attributable to operations in Colombia.

At December 31, 2009, we had foreign tax credit carryovers of $1,684,745. Currently, we expect to be able to utilize the incremental foreign tax credit carry forward and net operating loss generated during 2009 and, therefore, no additional valuation allowance has been recorded to date.

Financial Condition

Liquidity and Capital Resources. At December 31, 2009, we had a cash balance of $14,010,637 and working capital of $16,365,490 compared to a cash balance of $9,910,694 and working capital of $10,536,834 at December 31, 2008. The increase in working capital during the period was primarily attributable to the receipt of $12,763,550 (net proceeds) from the sale of common stock in December 2009, partially offset by payment of drilling costs, acquisition costs, operating costs in Colombia and dividends.

Cash Flows. Operating activities used cash during 2009 totaling $484,677 as compared to $1,452,054 of cash provided by operations during 2008. The decrease in cash flows from operations was primarily a result of a decrease in revenue due to lower commodity prices and the shut-in of Colombian production for part of the year.

Investing activities used $7,201,763 during 2009 compared to $8,787,853 provided during 2008. The funds used by investing activities during 2009 reflect investments in oil and gas properties and assets of $8,273,545 partially offset by the receipt of $799,680 from the escrow account related to the sale of the Caracara assets and $397,102 from the sale of selected domestic prospects, including Profit Island and North Profit Island. The funds provided by investing activities during 2008 reflect the receipt of proceeds from the sale of the Caracara assets totaling $9,878,797 and the Home Run and North Henry Bayou prospects totaling $273,696, as well as the net sale of marketable securities of $9,650,000, partially offset by investments in oil and gas properties and assets of $10,841,353.

Financing activities provided $11,786,383 during 2009 compared to $747,031 used during 2008. Funds provided by financing activities during 2009 consisted of proceeds from the December 2009 common stock placement of $13,525,200, partially offset by cash dividends paid of $980,057 and cost associated with our registered direct offering of $758,760. Funds used by financing activities during 2008 consisted 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.

Long-Term Liabilities. At December 31, 2009, we had long-term liabilities of $332,912 as compared to $205,524 at December 31, 2008. Long-term liabilities at December 31, 2009 and December 31, 2008 consisted of a reserve for plugging costs and deferred rent liability. The increase in 2009 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 our 2009 sale of common stock.

During 2009, we invested approximately $8,273,545 for the acquisition and development of oil and gas properties, which included expenses related to (1) drilling of 14 wells in Colombia ($3,731,322),

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(2) seismic and geological costs in Colombia ($528,529), (3) delay rentals on U.S. properties ($19,112), (4) leasehold costs on U.S. properties ($1,098,704), (5) capital expenditures on U.S. wells ($335,070) and (6) acquisition and evaluation costs in Colombia ($2,560,808).

At December 31, 2009, 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, 2009:

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.

Planned Drilling, Leasehold and Other Activities. As of December 31, 2009, our acquisition and drilling budget for 2010 totaled approximately $16.15 million and related principally to (1) drilling eight wells in Colombia on existing Hupecol prospects; (2) seismic work and drilling two wells on the Serrania Block operated by Shona Energy; (3) seismic work and preparation for drilling two wells on the CPO 4 Block operated by SK Energy; and (4) drilling one well on domestic prospects. Additional wells may be drilled at locations to be determined based on the results of the planned drilling projects. 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. In particular, we note that, in light of the sharp decline in commodity prices during the second half of 2008 and early 2009, we expanded our efforts to seek out favorable asset acquisition opportunities. Should we pursue any such opportunities, our acquisition and drilling budget could be materially altered.

Management presently anticipates that our total expenditures relating to exploration and development of the CPO 4 Bloc will be approximately $15.0 million running through 2011 and including $10.2 million budgeted during 2010. Management anticipates that our current financial resources combined with expected operating cash flows, will meet our anticipated objectives and business operations, including investments in the CPO 4 Block and other planned property acquisitions and drilling activities, for at least the next 12 months, without the need for additional capital. Management anticipates that available capital resources will be supplemented by the expected proceeds from the potential sale of a portion of the Hupecol properties, although there is no assurance as to whether such a sale will in fact take place or, if such a sale does occur, the timing of such a sale or the proceeds that may be realized from such a sale. Because the timing and actual costs and results associated with development of the Serrania Block and CPO 4 Block cannot be predicted with certainty and because we continually seek opportunities to acquire and develop reserves, it is possible that we may require and seek additional financing to support development of existing prospects or additional prospects that may be acquired in the future. We have no commitments to provide any additional financing should we require and seek such financing and there is no guarantee that we will be able to secure additional financing on acceptable terms, or at all, to support future acquisitions and development activities.

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Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements or guarantees of third party obligations at December 31, 2009.

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 43 of this report.

Not applicable.

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, 2009 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, 2009.

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

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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, 2009, 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, 2009 was effective.

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

Changes in Internal Control over Financial Reporting

No change in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) occurred during the fourth quarter of fiscal 2009 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, 2009, 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

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

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HOUSTON AMERICAN ENERGY CORP.

INDEX TO FINANCIAL STATEMENTS

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Houston American Energy Corp.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Houston American Energy Corp. (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for the years ended December 31, 2009 and 2008. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Houston American Energy Corp. as of December 31, 2009 and 2008, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ GBH CPAs, PC

GBH CPAs, PC

www.gbhcpas.com

Houston, Texas

March 25, 2010

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HOUSTON AMERICAN ENERGY CORP.

CONSOLIDATED BALANCE SHEETS