General

Houston American Energy was incorporated in April 2001 for the purposes of seeking oil and gas exploration and development prospects. Since inception, we have sought out prospects utilizing the expertise and business contacts of John F. Terwilliger, our founder and principal executive officer. Through the third quarter of 2002, the acquisition targets were in the Gulf Coast region of Texas and Louisiana, where Mr. Terwilliger has been involved in oil and gas exploration for over 30 years. In the fourth quarter 2002, we initiated international efforts through a Colombian joint venture more fully described below. Domestically and internationally, the strategy is to be a non-operating partner with exploration and production companies that have much larger resources and operations.

Overview of Operations

Our operations are exclusively devoted to natural gas and oil exploration and production.

Our focus, to date and for the foreseeable future, is the identification of oil and gas drilling prospects and participation in the drilling and production of prospects. We typically identify prospects and assemble various drilling partners to participate in, and fund, drilling activities. We may retain an interest in a prospect for our services in identifying and assembling prospects without any contribution on our part to drilling and completion costs or we may contribute to drilling and completion costs based on our proportionate interest in a prospect.

We derive our revenues from our interests in oil and gas production sold from prospects in which we own an interest, whether through royalty interests, working interest or other arrangements. Our revenues vary directly based on a combination of production volumes from wells in which we own an interest, market prices of oil and natural gas sold and our percentage interest in each prospect.

Our well operating expenses vary depending upon the nature of our interest in each prospect. We may bear no interest or a proportionate interest in the costs of drilling, completing and operating prospects on which we own an interest. Other than well drilling, completion and operating expenses, our principal operating expenses relate to our efforts to identify and secure prospects, comply with our various reporting obligations as a publicly held company and general overhead expenses.

Business Developments During 2007

Drilling Activities

During 2007, we drilled 26 international wells in Colombia, as follows:

· 8 wells were drilled on concessions in which we hold a 12.5% working interest, of which 1 was in production as of December 31, 2007, 2 were temporarily shut in due to mechanical problems or weather conditions and 5 were either dry holes or were ultimately abandoned, including 1 well that was converted to a water disposal well.

· 18 wells were drilled on concessions in which we hold a 1.116% working interest, of which 13 were in production as of December 31, 2007 and 5 were dry holes.

During 2007, we drilled three domestic wells, of which 1 was in production as of December 31, 2007, 1 was a dry hole and 1 was awaiting a pipeline connection before testing and completion.

At December 31, 2007, we had 1 well in Colombia being drilled and no domestic wells being drilled.

Leasehold Activity

During 2007, we acquired an interest in a 640-acre prospect known as the Caddo Lake Prospect in Caddo Parish, Louisiana with a right to participate in drilling on an additional 4,400 acres. We paid 35% of the costs of the initial well drilled on the Caddo Lake Prospect and have a 33.5% Working Interest (25.125% Net Revenue Interest) until well payout. After well payout, we will own a 27.25% Working Interest and 20.4375% Net Revenue Interest. On all additional well costs after the initial well and on all additional lease costs, we will have a 27.25% Working Interest with a 20.4375% Net Revenue Interest.

During 2007, we relinquished interests in various leases in Texas covering approximately 664 gross acres and 80 net acres and leases in Louisiana covering approximately 425 gross acres and 35 net acres. Also during 2007, a 30% interest in our Cara Cara Concession reverted to Ecopetrol pursuant to the terms of the concession, reducing our interest in the concession from approximately 1.59% to 1.116% and resulting in an approximately 1,094 acre reduction in our net acreage in Colombia.

Seismic Activity

During 2007, we conducted no new seismic activity.

Possible Sale of Cara Cara Concession

On July 17, 2007, our management was advised that Hupecol LLC had retained an investment bank for purposes of evaluating a possible transaction involving the monetization of Hupecol assets. Pursuant to that engagement, in March 2008, Hupecol Caracara LLC, as owner/operator under the Caracara Association Contract, entered into a Purchase and Sale Agreement to sell all of its interest in the Caracara Association Contract and related assets for a gross sale price of $920 million, subject to certain closing adjustments based on oil price fluctuations and operations between the effective date of the sale, January 1, 2008, and the closing date. Pursuant to our investment in Hupecol Caracara LLC, we hold a 1.594674% interest in the Caracara assets being sold and will receive our proportionate interest in the net sale proceeds after deduction of commissions and transaction expenses.

Completion of the sale of the Caracara assets is subject to satisfaction of various conditions set out in the Purchase and Sale Agreement, including the granting of all consents and approvals of the Colombian governmental authorities required for the transfer of the assets to the purchaser.

Hupecol Tax Allocation Credits

In August 2007, we were advised that Hupecol would be adjusting the division of interests among the members of the various Hupecol entities to reflect revised Colombian tax allocations among the various Hupecol entities. Specifically, Hupecol advised that Colombian tax attributes were allocated among the Hupecol entities without taking into account the specific contributions of each individual entity resulting in an improper shifting of tax expenses and benefits among the Hupecol entities and, in turn, the members of each of the Hupecol entities, including our company.

As a result of the adjustment by Hupecol, during 2007, we received a net credit from Hupecol for excess Colombian taxes allocated to us in the amount of $662,688. The credit is reflected in our financial statements as a credit to income tax expense.

Corporate Developments

During 2007, our compensation committee engaged a compensation consultant, as called for by the terms of employment of our chief financial officer, to review the compensation arrangements of our senior executives with a view to adjusting such compensation to reflect industry compensation practices. Following that review, the compensation committee approved increases in base salary of our chief executive officer and our chief financial officer, the payment of one-time cash bonuses to each and the grant of shares of restricted stock to each, which grants are subject to approval of the same by our shareholders.

Critical Accounting Policies

The following describes the critical accounting policies used in reporting our financial condition and results of operations. In some cases, accounting standards allow more than one alternative accounting method for reporting. Such is the case with accounting for oil and gas activities described below. In those cases, our reported results of operations would be different should we employ an alternative accounting method.

Full Cost Method of Accounting for Oil and Gas Activities. We follow the full cost method of accounting for oil and gas property acquisition, exploration and development activities. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisition, geological and geophysical work, delay rentals, costs of drilling, completing and equipping successful and unsuccessful oil and gas wells and related internal costs that can be directly identified with acquisition, exploration and development activities, but does not include any cost related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized unless significant amounts of oil and gas reserves are involved. No corporate overhead has been capitalized as of December 31, 2007. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves are amortized on a units-of-production method over the estimated productive life of the reserves. Unevaluated oil and gas properties are excluded from this calculation. The capitalized oil and gas property costs, less accumulated amortization, are limited to an amount (the ceiling limitation) equal to the sum of: (a) the present value of estimated future net revenues from the projected production of proved oil and gas reserves, calculated at prices in effect as of the balance sheet date and a discount factor of 10%; (b) the cost of unproved and unevaluated properties excluded from the costs being amortized; (c) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (d) related income tax effects. Excess costs are charged to proved properties impairment expense.

Unevaluated Oil and Gas Properties. Unevaluated oil and gas properties consist principally of our cost of acquiring and evaluating undeveloped leases, net of an allowance for impairment and transfers to depletable oil and gas properties. When leases are developed, expire or are abandoned, the related costs are transferred from unevaluated oil and gas properties to depletable oil and gas properties. Additionally, we review the carrying costs of unevaluated oil and gas properties for the purpose of determining probable future lease expirations and abandonments, and prospective discounted future economic benefit attributable to the leases. We record an allowance for impairment based on a review of present value of future cash flows. Any resulting charge is made to operations and reflected as a reduction of the carrying value of the recorded asset. Unevaluated oil and gas properties not subject to amortization include the following at December 31, 2007 and 2006:

                                      At December 31, 2007       At December 31, 2006
                 Acquisition costs   $              192,843     $              180,197
                 Evaluation costs                   719,102                    520,352
                 Retention costs                     86,861                          0
                 Total               $              998,806     $              700,549

The carrying value of unevaluated oil and gas prospects include $13,330 and $151,039 expended for properties in South America at December 31, 2007 and December 31, 2006, respectively. We are maintaining our interest in these properties and development has or is anticipated to commence within the next twelve months.

Subordinated Convertible Notes and Warrants - Derivative Financial Instruments. The Subordinated Convertible Notes and Warrants issued during 2005 have been accounted for in accordance with SFAS 133 and EITF No. 00-19, "Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company's Own Stock."

We identified the following instruments and derivatives requiring evaluation and accounting under the relevant guidance applicable to financial derivatives:

· Subordinated Convertible Notes

· Conversion feature

· Conversion price reset feature

· Company's optional redemption right

· Warrants

· Warrants exercise price reset feature

We identified the conversion feature; the conversion price reset feature and our optional early redemption right within the Convertible Notes to represent embedded derivatives. These embedded derivatives were bifurcated from their respective host debt contracts and accounted for as derivative liabilities in accordance with EITF 00-19. The conversion feature, the conversion price reset feature and our optional early redemption right within the Convertible Notes were bundled together as a single hybrid compound instrument in accordance with SFAS No. 133 Derivatives Implementation Group Implementation Issue No. B-15, "Embedded Derivatives: Separate Accounting for Multiple Derivative Features Embedded in a Single Hybrid Instrument."

We identified the common stock warrant to be a detachable derivative. The warrant exercise price reset provision was identified as an embedded derivative within the common stock warrant. The common stock warrant and the embedded warrant exercise price reset provision were accounted for as a separate single hybrid compound instrument.

The single compound embedded derivatives within Subordinated Convertible Notes and the derivative liability for Warrants were recorded at fair value at the date of issuance (May 4, 2005); and were marked-to-market each quarter with changes in fair value recorded to our income statement as "Net change in fair value of derivative liabilities." We utilized a third party valuation firm to fair value the single compound embedded derivatives under the following methods: a layered discounted probability-weighted cash flow approach for the single compound embedded derivatives within Subordinated Convertible Notes; and the Black-Scholes model for the derivative liability for Warrants based on a probability weighted exercise price.

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

In May 2006, each of the Subordinated Convertible Notes and Warrants accounted for as derivative financial instruments was converted or exercised. Accordingly, for subsequent periods, we have no derivative financial instruments requiring account under SFAS 133.

Stock-Based Compensation. We account for stock-based compensation in accordance with the provisions of SFAS 123(R). We use the Black-Scholes option-pricing model, which requires the input of highly subjective assumptions. These assumptions include estimating the volatility of our common stock price over the vesting term, dividend yield, an appropriate risk-free interest rate and the number of options that will ultimately not complete their vesting requirements ("forfeitures"). Changes in the subjective assumptions can materially affect the estimated fair value of stock-based compensation and consequently, the related amount recognized on the Statements of Operations.

Results of Operations

Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

Oil and Gas Revenues. Total oil and gas revenues increased $1,774,441, or 55.4%, to $4,977,172 in fiscal 2007 compared to $3,202,731 in fiscal 2006. The increase in revenue is due to (a) increased production resulting from the development of the Colombian fields and (b) increases in oil and natural gas prices, partially offset by declines in U.S. production. We had interests in 39 producing wells in Colombia and 7 producing wells in North America during 2007 as compared to 22 producing wells in Colombia and 11 producing wells in North America during 2006. Average prices from sales were $65.61 per barrel of oil and $6.90 per mcf of gas during 2007 as compared to $55.55 per barrel of oil and $6.75 per mcf of gas during 2006. Following is a summary comparison, by region, of oil and gas sales for the periods.

                                            Colombia        North America         Total
                         Year ended 2007
                         Oil sales         $ 4,531,640     $       140,313     $ 4,671,953
                         Gas sales                   0             305,219         305,219
                         Year ended 2006
                         Oil sales         $ 2,565,105     $        95,363     $ 2,660,468
                         Gas sales                   0             542,263         542,263

Lease Operating Expenses. Lease operating expenses, excluding joint venture expenses relating to our Colombia operations discussed below, increased 81% to $1,841,119 in 2007 from $1,017,440 in 2006. The increase in lease operating expenses was attributable to the increase in the number of wells operated during 2007 (46 wells as compared to 33 wells) partially offset by improved operating efficiencies. Additionally operations have increased in workovers as well as in the Dorotea and Cabiona areas where we have a higher working interest (12.5%), which increased the amount of operating expense we incurred during the period.

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

                                            Colombia        North America         Total
                         Year ended 2007   $ 1,710,689     $       130,430     $ 1,841,119
                         Year ended 2006       819,273             198,167       1,017,440

Joint Venture Expenses. Joint venture expenses totaled $149,200 in 2007 compared to $167,023 in 2006. The joint venture expenses represent our allocable share of the indirect field operating and region administrative expenses billed by the operator of the Colombian concessions. The decrease in joint venture expenses was attributable to the operator reducing the personnel working on undrilled contract areas.

Depreciation and Depletion Expense. Depreciation and depletion expense increased by 23.9% to $1,099,826 in fiscal 2007 when compared to $887,911 in 2006. The increase in depreciation and depletion expense was primarily attributable to increases in Colombian production and an 82% increase in the depletable cost pool.

Impairment Expense. During 2007, we recorded a provision for impairments of $348,019, all of which was attributable to our North American properties. Impairments related to the termination, during 2007, of operations of seven wells in the U.S. and the fact that, as of December 31, 2007, well testing had not yet been conducted on, and no reserves had been attributed to, the well drilled during 2007 on our Caddo Lake Prospect.

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

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

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

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

Income Tax Expense (Benefit). Income tax expense decreased to $57,196 in 2007 from $510,637 in 2006. The decrease in income tax expense during 2007 was attributable to the gain of $662,668 associated with the reallocation of the Hupecol tax credits discussed above, partially offset by an increase in revenue and an effective tax rate increase in Colombia. Income tax expense during 2007 and 2006 was entirely attributable to operations in Colombia. We recorded no U.S. income tax liability in 2007 or 2006. At December 31, 2007, we had net operating loss carry forward of approximately $832,821 and foreign tax credits of approximately $224,750.

Financial Condition

Liquidity and Capital Resources. At December 31, 2007, we had a cash balance of $417,818 and working capital of $10,428,422 compared to a cash balance of $409,008 and working capital of $14,202,160 at December 31, 2006. The changes in cash and working capital during the period were primarily attributable to the payment of drilling costs.

Cash Flows. Operating cash flows for 2007 totaled $1,801,481 as compared to $1,239,446 during 2006. The increase in operating cash flow was primarily attributable to increased revenues from oil and gas sales partially offset by increased lease operating expenses and general and administrative expenses and reductions in payables and accrued expenses.

Investing activities used $1,792,672 during 2007 as compared to $17,507,371 used during 2006. The decrease in cash flows used by investing activities during 2007 was primarily attributable to the temporary net investment of $14,000,000 in marketable securities during 2006 as compared to the sale of $7,500,000 of those marketable securities during 2007, offset by the purchase of $3,150,000 of marketable securities in 2007 and investments in oil and gas acquisition and drilling activities of $6,142,672 during 2007 as compared to $3,507,371 in 2006.

Financing activities provided $0 during 2007 as compared to $14,952,833 during 2006. Cash flows from financing activities during 2006 related to the private placement of common stock resulting in the receipt of net proceeds of $15,361,583 and the receipt of $491,250 from the exercise of warrants partially offset by the repayment of shareholder loans of $900,000.

Long-Term Liabilities. At December 31, 2007, we had long-term liabilities of $135,267 as compared to $38,816 at December 31, 2006. Long-term liabilities at December 31, 2007 and December 31, 2006 consisted of a reserve for plugging costs and deferred rent liability.

Capital and Exploration Expenditures and Commitments. Our principal capital and exploration expenditures relate to our ongoing efforts to acquire, drill and complete prospects. With the receipt of additional financing in 2006 and prior years, and the increase in our revenues and operating cash flows, we expect that future capital and exploration expenditures will be funded principally through funds on hand and funds generated from operations.

During 2007, we invested $6,142,672 for the acquisition and development of oil and gas properties, primarily consisting of (1) drilling of 3 domestic wells ($1,799,792), (2) drilling 26 wells in Colombia ($4,247,009), and (3) lease retention payments on domestic properties ($95,871).

At December 31, 2007, our only material contractual obligation requiring determinable future payments on our part was our lease relating to our executive offices.

The following table details our contractual obligations as of December 31, 2007:

                                               Payments due by period
                       Total         2008         2009 - 2010       2011 - 2012     Thereafter
  Operating leases     369,050       79,576           166,260           123,214               0
  Total                369,050       79,576           166,260           123,214               0

In addition to the contractual obligations requiring that we make fixed payments, in conjunction with our efforts to secure oil and gas prospects, financing and services, we have, from time to time, granted overriding royalty interests (ORRI) in various properties, and may grant ORRIs in the future, pursuant to which we will be obligated to pay a portion of our interest in revenues from various prospects to third parties.

2008 Planned Drilling, Leasehold and Other Activities. As of December 31, 2007, we planned to drill a total of 15 wells during 2008, of which 1 well is planned to be drilled on our domestic exploration projects and 14 wells are planned to be drilled on our Colombian exploration projects. The following table reflects planned drilling activities during 2008:

               Location              Prospect Name       # of Planned Wells

        Caddo Parish, LA         Caddo Lake Prospect             1
        Llanos Basin, Colombia   Cara Cara Concession            1
        Llanos Basin, Colombia   Dorotea Concession              7
        Llanos Basin, Colombia   Cabiona Concession              3
        Llanos Basin, Colombia   Las Garzas Concession           1
        Llanos Basin, Colombia   Leona Concession                1
        Llanos Basin, Colombia   Camarita Concession             1

Additional wells are expected to be drilled at locations to be determined based on the results of the planned drilling projects. Our planned drilling activity is subject to change from time to time without notice. In particular, we cannot predict the impact on our planned drilling activities in Colombia of ongoing efforts by Hupecol to monetize assets.

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

At December 31, 2007, our acquisition and drilling budget for 2008 totaled approximately $6,270,000, consisting of (1) $4,090,000 for drilling of 14 wells in Colombia, (2) $545,000 for drilling of 1 domestic well, (3) $385,000 for seismic operations in Colombia, and (4) $1,250,000 for road construction and facilities in Colombia. Our acquisition and drilling budget has historically been subject to substantial fluctuation over the course of a year based upon successes and failures in drilling and completion of prospects and the identification of additional prospects during the course of a year.

Management anticipates that our current financial resources will meet our . . .