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Module and Segment References
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the Fiscal Year Ended December 31, 2010

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 T

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 T

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 T 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. T

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 T Non-accelerated filer  ̈ Smaller reporting company  ̈

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant on June 30, 2010, based on the closing sales price of the 

registrant’s common stock on that date, was approximately $153.5 million. 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 15, 2011 was 31,112,673.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company’s Proxy Statement for its 2011 Annual Meeting are incorporated by reference into Part III of this Report.

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T ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 ̈ TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Delaware 76-0675953

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

Title of each class Name of each exchange on which each is registered

Common Stock, $0.001 par value NYSE AMEX

 

 
TABLE OF CONTENTS

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 Page

PART I 

 Item 1. Business 3 

 Item 1A. Risk Factors 15 

 Item 1B. Unresolved Staff Comments 25 

 Item 2. Properties 25 

 Item 3. Legal Proceedings 25 

 Item 4. (Removed and Reserved) 25 

 

PART II 

 Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 26 

 Item 6. Selected Financial Data 28 

 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 29 

 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 39 

 Item 8. Financial Statements and Supplementary Data 39 

 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 39 

 Item 9A. Controls and Procedures 40 

 Item 9B. Other Information 40 

 

PART III 

 Item 10. Directors, Executive Officers and Corporate Governance 41 

 Item 11. Executive Compensation 41 

 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 41 

 Item 13. Certain Relationships and Related Transactions, and Director Independence 41 

 Item 14. Principal Accountant Fees and Services 41 

 

PART IV 

 Item 15. Exhibits and Financial Statement Schedules 42 

 

SIGNATURES 43 

 

2
FORWARD-LOOKING STATEMENTS

This annual report on Form 10-K contains forward-looking statements within the meaning of the federal securities laws. These forwarding-looking statements include without 

limitation statements regarding our expectations and beliefs about the market and industry, our goals, plans, and expectations regarding our properties and drilling activities and results, 

our intentions and strategies regarding future acquisitions and sales of properties, our intentions and strategies regarding the formation of strategic relationships, our beliefs regarding 

the future success of our properties, our expectations and beliefs regarding competition, competitors, the basis of competition and our ability to compete, our beliefs and expectations 

regarding our ability to hire and retain personnel, our beliefs regarding period to period results of operations, our expectations regarding revenues, our expectations regarding future 

growth and financial performance, our beliefs and expectations regarding the adequacy of our facilities, and our beliefs and expectations regarding our financial position, ability to 

finance operations and growth and the amount of financing necessary to support operations. These statements are subject to risks and uncertainties that could cause actual results and 

events to differ materially. See “Item 1A. Risk Factors” for a discussion of certain risk factors. 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 independent 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.

Sale of Interests in Hupecol Dorotea and Cabiona, LLC and Hupecol Llanos, LLC

During the fourth quarter of 2010, Hupecol Dorotea & Cabiona Holdings, LLC (“Hupecol D&C Holdings”) sold all of its interest in Hupecol Dorotea and Cabiona, LLC (“HDC, 

LLC”), and Hupecol Llanos Holdings, LLC (“Hupecol Llanos Holdings”) sold all of its interest in Hupecol Llanos, LLC (“HL, LLC”). We hold a 12.5% ownership interest in each of 

Hupecol D&C Holdings and Hupecol Llanos Holdings and, prior to the sale, held indirect interests in identical amounts in HDC, LLC and HL, LLC. HDC, LLC and HL, LLC hold interests 

in the Dorotea, Cabiona, Leona and Las Garzas blocks, and related assets, in Colombia.

The Dorotea, Cabiona, Leona and Las Garzas blocks cover an aggregate of approximately 310,730 gross acres. At December 31, 2009, the estimated proved reserves associated 

with the blocks totaled 1,178,576 barrels of oil, which represented 96.9% of our estimated proved oil and natural gas reserves.

As a result of the sale, we received net proceeds, after deduction of fees and expenses of the transaction of $29,359,463 before escrow holdbacks, realized a gain on the sale of 

$25,397,048 and eliminated from oil and gas properties costs subject to amortization associated with the underlying assets totaling $3,989,236. Production from the Dorotea, Cabiona, 

Leona and Las Garzas blocks accounted for $18,880,299, $7,936,673 and $7,206,439 of our revenues during 2010, 2009 and 2008, respectively.

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Table of Contents

Item 1. Business

 

3
Fifteen percent of the sales price was held in escrow pursuant to the Purchase and Sales Agreement to fund potential claims arising from the sale with escrowed amounts to be 

released over a three year period based on amounts remaining in escrow after claims. In addition to the fifteen percent escrowed, Hupecol withheld 5% of the proceeds in escrow for any 

contingencies that may arise, and it is expected that the Company will receive the 5% withheld by Hupecol in 2011. The Company is not aware of any claims that would reduce the 

escrow amounts as of December 31, 2010. Our proportionate interest in the sales proceeds deposited into escrow totaled $7,069,810. Following completion of the sale of HDC, LLC and 

HL, LLC, we have no continuing interest in the Dorotea, Cabiona, Leona and Las Garzas blocks.

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.

The following table sets forth information relating to our principal exploration projects as of December 31, 2010:

- 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:

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 Net acreage

Average working 

interest %

Net producing 

wells

Net proved 

reserves

(boe)

2010 Net Production

Oil (1)

(bbls)

Natural Gas

(mcf)

Oklahoma 4 2.36% 0.0236 378 - 727

Louisiana 1,776 37.00% 0.0988 17,608 1,002 14,474

Texas 42 3.81% 0.0788 1,727 538 2,597

Total U.S. 1,822 36.16% 0.2011 19,713 1,540 17,798

Colombia 179,978 30.41% 0.1280 61,150 206,239 -

Total 181,800 30.47% 0.3291 80,863 261,779 17,798

(1) Net oil production reflects our total production for 2010, including production from the Dorotea, Cabiona, Leona and Las Garzas prospects that were divested during 2010. Oil 

production during 2010 attributable to prospects held at December 31, 2010 totaled 67,161 barrels.

 • East Baton Rouge Parish — we hold a 37.55% working interest in the Profit Island and North Profit Island prospects, covering 4,670 gross acres in East Baton Rouge Parish, 

Louisiana. In addition, we hold a 7.29% royalty interest in 2,485 royalty acres, as well as a 5.675% royalty interest in the Crown Paper #01 well.

 

4
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. We have no present plans to conduct drilling on the Crowley prospect.

Texas Properties

Our principal exploration properties in Texas consist of the following:

Our exploration properties in Texas at December 31, 2010 reflect our sale, during 2010, of a 2.5% working interest and our 1.25% of 8/8s overriding royalty interest ("ORRI") in 

6000+ gross acres in Karnes County, Texas and our right to a 1.25% overriding royalty interest in an Area of Mutual Interest ("AMI") covering approximately 50,000 gross acres in 

Karnes County, Texas.

- Colombian Properties:

We hold interests in multiple prospects in Colombia covering 825,657 gross acres. The majority of our holdings in Colombia are located within the Llanos and the Caguan 

Putumayo Basins. 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, 2010:

Hupecol Prospects

At December 31, 2010 we held interests in two concessions and two Technical Evaluation Areas (“TEA”) operated by Hupecol. The two concessions are located in the Llanos 

Basin of Colombia and the TEAs are located in the Caguan Putumayo Basin of Colombia. The concessions and TEAs cover an aggregate area of 369,436 acres.

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 • Plaquemines Parish — we hold a 1.80% working interest in the SL 180771 well and prospect which covers 300 gross acres. We have no present plans to drill additional wells 

on the SL 180771 Prospect.

 • Vermilion Parish — we hold a 2.25% working interest in the 830 acre La Furs, Inc. F-16 well and prospect. We have no present plans to drill additional wells on the La 

Furs Prospect.

 • Jim Hogg County — we hold a 4.375% working interest in the 340 acre Hog Heaven Prospect in Jim Hogg County, Texas. At December 31, 2010, the Hog Heaven Prospect 

produced from a single 6,200-foot well. We have no present plans to drill additional wells on the Hog Heaven Prospect.

 • Matagorda Country — we hold a 3.50% working interest in the 779 acre Harrison Prospect in Matagorda County, Texas. We have no present plans to drill additional wells 

on the Harrison Prospect.

Property Operator

Ownership 

Interest

Total Gross 

Acres

Total Gross 

Developed Acres

Gross Productive 

Wells

La Cuerva Contract Hupecol 1.6% 48,000 5,120 8

LLA 62 Hupecol 1.6% 40,000 — —

Los Picachos TEA Hupecol 12.5% 86,235 — —

Macaya TEA Hupecol 12.5% 195,201 — —

CPO 4 Block SK Energy 37.5% 345,452 — —

Serrania Block Shona Energy 12.5% 110,769 — —

Total 825,657 5,120 8

 

5
At December 31, 2010, one of the Hupecol concessions had production and we had interests in 8 gross wells (0.128 net wells) operated by Hupecol. Our net daily production 

during December 2010 from interests operated by Hupecol was approximately 23 barrels of oil (no natural gas) per day. Well depths range from 3,000 feet to 4,000 feet.

Our interest in each of the described concessions in Colombia is held through an interest in Hupecol, LLC and affiliated entities.

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.

The concessions and TEAs operated by Hupecol at December 31, 2010 reflect the sale in December 2010 of Hupecol related entities that held four concessions covering 310,730 

acres. See “Sale of Interests in Hupecol Dorotea and Cabiona, LLC and Hupecol Llanos, LLC.”

For 2011, Hupecol has advised us that they plan to drill 10 additional wells on the La Cuerva concession.

SK Energy Prospect

Pursuant to two Farmout Agreements and a 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 acts as operator of the CPO 4 Block. Under the original Farmout Agreement, entered 

in 2009, we agreed to 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 received a 25.0% interest in the CPO 4 Block. Under a second Farmout Agreement, entered in 2010 and effective July 31, 2010, we acquired from SK an additional 

12.5% interest in the CPO 4 Block and we agreed to pay our proportionate interest in ongoing costs plus 12.5% of certain defined costs relating to the development of the CPO 4 Block 

and 25% of seismic acquisition costs incurred with respect to the Phase 1 cost of the CPO 4 Block between June 18, 2009 and June 17, 2012.

As a result of the second Farmout Agreement, at December 31, 2010, we held a 37.5% interest in the CPO 4 Block.

Pursuant to the terms of, and in conjunction with, the second Farmout Agreement and the Joint Operating Agreement, we entered into a separate agreement with Gulf United 

Energy (“Gulf United”) whereby we waived our right of first refusal under the Joint Operating Agreement for the specific purpose of permitting Gulf United to acquire a 12.5% interest in 

the CPO 4 Block. SK Energy, simultaneously, entered into an agreement with Gulf United to assign a 12.5% interest in the CPO 4 Block to Gulf United conditioned upon approval, by 

July 31, 2011, of the assignment by the National Hydrocarbon Agency of Colombia (the “ANH”) and the Republic of Korea. Under our agreement with Gulf United, Gulf United agreed 

to pay us, not later than 30 days following receipt by Gulf United of ANH approval, our 12.5% share of past costs incurred through July 31, 2010 and our 25% share of seismic 

acquisition costs incurred through July 31, 2010 on the CPO 4 Block.

In November 2010, we paid our proportionate interest in the past costs attributable to the additional 12.5% interest acquired in the CPO 4 Block. At December 31, 2010 and 

through the date of this filing, approval of the assignment to Gulf United by the ANH remained pending, as did Gulf United’s obligation to reimburse us the agreed 12.5% of past costs 

and 25% of seismic acquisition costs.

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 was modified to allow 3-D data to be shot in place of the 

initial 2-D requirement. The Phase 1 seismic acquisition was completed during 2010 and the entire Phase 1 Work Program is estimated to be completed by December of 2011. During 2010, 

our total expenditures on the CPO 4 Phase 1 Work Program were $8.2 million.

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6
For 2011, SK Energy has advised us that they plan to focus on the drilling of three wells on CPO 4. Our budgeted expenditures on the CPO 4 Block for 2011 are approximately 

$20.0 million.

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.

During 2010, Shona Energy completed seismic work on the Serrania Block. The net costs incurred by Houston American Energy for the Phase 1 geological and seismic costs were 

approximately $390 thousand in 2009 and $950 thousand in 2010.

During 2011, Shona Energy has advised that it plans to drill two initial wells on the Serrania Block. Houston American Energy’s estimated net cost associated with drilling the two 

initial wells on the Serrania Block is approximately $1.0 million.

Drilling Activity

During 2010, we participated in the drilling of a total of 12 gross wells, all of which were in Colombia. Of the 12 wells drilled, 10 were classified as exploratory and 2 were classified 

as development. Our 2010 drilling program achieved a 75% success rate. The following table summarizes the number of wells drilled during 2010, 2009, and 2008, 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, 2010, we had no wells in progress or awaiting completion in the United States and one gross (.016 net) well in progress in Colombia.

Seismic Activity

During 2010, our operators in Colombia acquired approximately 225 square miles of additional 3-D and 2-D seismic and geological data. The additional data relates primarily to the 

CPO 4, Serrania, and La Cuerva concessions where we hold 37.5%, 12.5%, and 1.6% working interests, respectively. Our share of the costs of such data acquisition was approximately 

$6.4 million.

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 Year Ended December 31,

 2010 2009 2008

 Gross Net Gross Net Gross Net

Development wells, completed as:

Productive 2 0.032 4 0.500 6 0.750

Non-productive — — 1 0.125 1 0.125

Total development wells 2 0.032 5 0.625 7 0.875

Exploratory wells, completed as:

Productive 7 0.439 5 0.407 5 0.625

Non-productive 3 0.204 5 0.486 4 0.475

Total exploratory wells 10 0.643 10 0.893 9 1.100

 

7
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, 2010, we owned interests in 15 gross wells containing multiple completions. As of December 31, 2010, we had ownership interests in productive wells, categorized by 

geographic area, as follows:

Productive wells at December 31, 2010 reflect our sale, during 2010, of our interest in HDC, LLC and HL, LLC which accounted for 19 gross (2.375 net) productive wells.

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, 2010:

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 Oil Wells Gas Wells

United States

Gross — 7

Net — 0.201

Colombia

Gross 8 —

Net 0.128 —

Total

Gross 8 7

Net 0.128 0.201

 Year Ended December 31,

 2010 2009 2008

Net Production:

Gas (Mcf):

United States 17,798 15,761 24,748

Colombia — — —

Total 17,798 15,761 24,748

Oil (Bbls):

United States 1,540 1,581 1,510

Colombia 260,239 129,782 122,415

Total 261,779 131,363 123,925

Average sales price:

Gas ($ per Mcf)

United States $ 5.01 $ 4.89 $ 10.22

Colombia — — —

Total 5.01 4.89 10.22

Oil ($ per Bbl)

United States 76.21 59.99 104.30

Colombia 74.17 61.21 83.42

Total 74.18 61.20 83.67

Average production costs ($ per BOE):

United States 8.50 26.01 10.40

Colombia 31.08 35.95 27.03

Total $ 30.70 $ 35.33 $ 26.43

 

8
Natural Gas and Oil Reserves

Reserve Estimates

The following tables sets forth, by country and as of December 31, 2010, our estimated net proved oil and natural gas reserves, and the estimated present value (discounted at an 

annual rate of 10%) of estimated future net revenues before future income taxes (PV-10) and after future income taxes (Standardized Measure) of our proved reserves, each prepared in 

accordance with assumptions prescribed by the Securities and Exchange Commission (SEC).

The PV-10 value is a widely used measure of value of oil and natural gas assets and represents a pre-tax present value of estimated cash flows discounted at ten percent. PV-10 is 

considered a non-GAAP financial measure as defined by the SEC. We believe that our PV-10 presentation is relevant and useful to our investors because it presents the discounted 

future net cash flows attributable to our proved reserves before taking into account the related future income taxes, as such taxes may differ among various companies because of 

differences in the amounts and timing of deductible basis, net operating loss carry forwards and other factors. We believe investors and creditors use our PV-10 as a basis for 

comparison of the relative size and value of our proved reserves to the reserve estimates of other companies. PV-10 is not a measure of financial or operating performance under GAAP 

and is not intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the 

standardized measure of discounted future net cash flows as defined under GAAP.

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.

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 Reserves (1)

 Oil Natural Gas Total (2)

 (bbls) (mcf) (boe)

Reserve category

Proved Developed

United States 6,010 82,220 19,713

Colombia 17,202 — 17,202

Total Proved Developed Reserves 23,212 82,220 36,915

Proved Undeveloped

United States — — —

Colombia 43,948 — 43,948

Total Proved Undeveloped Reserves 43,948 — 43,948

Total Proved Reserves 67,160 82,220 80,864

 Proved Developed

Proved 

Undeveloped Total Proved

 

PV-10 (1) $ 994,249 $ 1,063,756 $ 2,058,005

Standardized measure (3) $ 752,129 $ 804,751 $ 1,556,880

 (1) In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of our proved reserves and the PV-10 set forth herein reflect estimated 

future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing 

economic conditions at December 31, 2010. For purposes of determining prices, we used the unweighted arithmetical average of the prices on the first day of each month within 

the 12-month period ended December 31, 2010. The average prices utilized for purposes of estimating our proved reserves were $77.54 per barrel of oil and $5.12 per mcf of 

natural gas for our US properties and $77.26 per barrel for our Colombian properties, adjusted by property for energy content, quality, transportation fees and regional price 

differentials. The prices should not be interpreted as a prediction of future prices. The amounts shown do not give effect to non-property related expenses, such as corporate 

general administrative expenses and debt service, future income taxes or to depreciation, depletion and amortization.

 

9
Due to the inherent uncertainties and the limited nature of reservoir data, proved reserves are subject to change as additional information becomes available. The estimates of 

reserves, future cash flows and present value are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise. Although we believe these 

estimates 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 these estimates.

Reserve Estimation Process, Controls and Technologies

The reserve estimates, including PV-10 and Standard Measure estimates, set forth above were prepared by Lonquist & Co., LLC.

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.

Our year-end reserve report is prepared by Lonquist & Co. based upon a review of property interests being appraised, production from such properties, current costs of 

operation and development, current prices for production, agreements relating to current and future operations and sale of production, geosciences and engineering data, and other 

information provided to them by our management team and by the various Hupecol entities that operated all of our proved properties in Colombia at December 31, 2010. Lonquist & Co. 

also prepares reserve estimates for the various Hupecol entities. This information is reviewed by knowledgeable members of our Company to ensure accuracy and completeness of the 

data, as it pertains to our Company, prior to submission to Lonquist & Co. Upon analysis and evaluation of data provided, Lonquist & Co. issues a preliminary appraisal report of our 

reserves. The preliminary appraisal report and changes in our reserves are reviewed by our Senior Vice President of Exploration, a degreed geophysicist with over 25 years oil and gas 

industry experience, and our President for completeness of the data presented and reasonableness of the results obtained. Once any questions have been addressed, Lonquist & Co. 

issues the final appraisal report, reflecting their conclusions.

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 rules with respect to technologies that a company can use to establish reserves, effective for years ending after December 31, 2008, 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 has been field tested and has been demonstrated to provide reasonably 

certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Lonquist & Co. used a combination of production and pressure performance, simulation studies, offset analogies, seismic data and interpretation, geophysical logs and core data 

to calculate our reserves estimates.

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 (2) Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent.

 (3) The Standard Measure differs from PV-10 only in that the Standard Measure reflects estimated future income taxes.

 

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Proved Undeveloped Reserves

As of December 31, 2010, our proved undeveloped reserves totaled 43.9 mbbls of oil and 0 mcf of natural gas, for a total of 43.9 mbbls compared to 894.2 mbbls of oil and 0.0 mcf 

of natural gas, for a total of 894.2 mbbls as of December 31, 2009. The decrease in our proved undeveloped reserves during 2010 was principally attributable to the sale of our indirect 

interest in the Dorotea, Cabiona, Leona and Las Garzas Blocks in Colombia.

PUD Locations

All of our proved undeveloped reserves at December 31, 2010 were associated with our properties in Colombia operated by Hupecol.

Changes in Proved Undeveloped (“PUD”) Reserves

Changes in PUD Reserves that occurred during 2010 were due to:

Development Cost

Estimated future development costs relating to the development of proved undeveloped reserves are projected to be $147 thousand for 2011 and $478 thousand thereafter.

Drilling Plans

All proved undeveloped locations are scheduled to be drilled or otherwise converted to proved developed reserves before the end of 2015. None of our proved undeveloped 

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, 2010:

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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 • Negative revisions of 883.4 mboe in PUD reserves due to the sale of Dorotea, Cabiona, Leona and Las Garzas blocks, and related assets, in Colombia

 • Positive revisions of 33.2 mboe in PUD reserves due to Hupecol’s on-going drilling program and subsequent changes in subsurface mapping

 Developed Undeveloped

 Gross Net Gross Net

United States 3,029 71 4,671 1,751

Colombia 5,120 82 820,537 179,896

Total 8,149 153 825,208 181,647

 

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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, 2010, 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 December 31, 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 1, 2011, we had 4 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.

Competition

We encounter intense competition from other oil and gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. 

Our competitors include major integrated oil and gas companies, numerous independent oil and gas companies and individuals. Many of our competitors are large, well-established 

companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil and gas business for a much longer time than our Company. These 

companies may be able to pay more for productive oil and gas properties, exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and 

prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate 

and select suitable properties and to consummate transactions in this highly competitive environment.

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 Undeveloped Acres Expiring

Twelve Months Ending: Gross Net

December 31, 2011 — —

December 31, 2012 — —

December 31, 2013 4,671 1,751

December 31, 2014 — —

December 31, 2015 and later 820,537 179,896

Total 825,208 181,647

 

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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.

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.

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 • Clean Air Act, and its amendments, which govern air emissions;

 • Clean Water Act, which governs discharges into waters of the United States;

 • Comprehensive Environmental Response, Compensation and Liability Act, which imposes liability where hazardous releases have occurred or are threatened to occur 

(commonly known as “Superfund”);

 • Resource Conservation and Recovery Act, which governs the management of solid waste;

 • Oil Pollution Act of 1990, which imposes liabilities resulting from discharges of oil into navigable waters of the United States;

 • Emergency Planning and Community Right-to-Know Act, which requires reporting of toxic chemical inventories;

 • Safe Drinking Water Act, which governs the underground injection and disposal of wastewater; and

 • U.S. Department of Interior regulations, which impose liability for pollution cleanup and damages.

 

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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 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

In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill. The U.S. Senate’s version, 

The Clean Energy Jobs and American Power Act, or the Boxer-Kerry Bill, has been introduced, but has not passed. Although these bills include several differences that require 

reconciliation before becoming law, both bills contain the basic feature of establishing a “cap and trade” system for restricting greenhouse gas emissions. Under such system, certain 

sources of greenhouse gas emissions would be required to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases. The number of 

emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of greenhouse gas emission allowances declines each year, 

the cost or value of allowances is expected to escalate significantly. The ultimate outcome of this legislative initiative remains uncertain. In addition to the pending climate legislation, 

the EPA has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and require reporting by regulated facilities by March 2011 and annually 

thereafter. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the 

public health and welfare of current and future generations. The EPA has proposed regulations that would require permits for and reductions in greenhouse gas emissions for certain 

facilities, and may issue final rules as early as 2011. Similarly, foreign governments, including Colombia, have begun various initiatives with respect to regulation and reduction of 

greenhouse gases. Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating costs, and could 

have an adverse effect on demand for the oil and natural gas we produce, depending on the applicability to company operations and the refining, processing, and use of oil and gas.

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.

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Our business activities and the value of our securities are subject to significant hazards and risks, including those described below. If any of such events should occur, our 

business, financial condition, liquidity and/or results of operations could be materially harmed, and holders and purchasers of our securities could lose part or all of their investments.

A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital 

expenditure obligations and financial commitments.

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are 

commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas 

have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors 

beyond our control. These factors include, but are not limited to, the following:

Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. 

Lower prices will also negatively impact the value of our proved reserves. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our future 

business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

We may be affected by general economic conditions

The disruption experienced in U.S. and global financial and credit markets, and the accompanying economic contraction, during second half of 2008 and continuing through 2009 

resulted in projected decreases in demand for oil and natural gas, resulting in a sharp drop in energy prices, and affected the availability and cost of capital. While the U.S. and global 

economies have experienced a slow recovery from the deep recessionary conditions that prevailed in late 2008 and much of 2009 and commodity prices have recovered a portion of the 

decline experienced over that period, uncertainty that continues to exist with respect to the pace and sustainability of the economic recovery continues to be a risk to oil and natural gas 

operators and other businesses. Global economic growth drives demand for energy from all sources, including fossil fuels. Should the U.S. and global economies experience further 

weakness, demand for energy and accompanying commodity prices may decline and our financial position may deteriorate along with our ability to operate profitably and our ability to 

obtain financing to support operations and the cost and terms of the same, is unclear. With respect to Houston American Energy, 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.

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Item 1A. Risk Factors

 • changes in global supply and demand for oil and natural gas;

 • the actions of the Organization of Petroleum Exporting Countries, or OPEC;

 • the price and quantity of imports of foreign oil and natural gas;

 • political conditions, including embargoes, in or affecting other oil-producing activity;

 • the level of global oil and natural gas exploration and production activity;

 • the level of global oil and natural gas inventories;

 • weather conditions;

 • technological advances affecting energy consumption; and

 • the price and availability of alternative fuels.

 

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Our cash flows and profitability may fluctuate by large amounts as a result of our strategy of investment in drilling and exploration of unproven properties and opportunistic asset 

divestitures.

We have historically experienced large fluctuations in our cash flows and profitability associated with our drilling and development of properties, divestitures of interests in 

select properties and reinvestment in drilling and development of unproven properties. Our strategy has historically focused on early identification of, and entrance into, existing and 

emerging resource plays. As part of that strategy, we and our partners have participated in accumulating positions and drilling unproven acreage, that may be perceived to be higher 

risk, where acquisition, drilling and operation costs may be lower with a view to proving reserves, divesting selected assets on an opportunistic basis to operators willing to pay higher 

prices for proven prospects without early stage drilling risk and reinvesting operating cash flow and sales proceeds in accumulating, drilling and developing additional, and larger, 

acreage positions. As a result of such strategy, we sold acreage positions in 2008 and 2010 that both provided large one-time profits and cash proceeds and substantially reduced our 

proved reserves, production and operating cash flows immediately following such sales and after which we invested substantial portions of sales proceeds in the accumulation and 

exploratory drilling of larger acreage positions. Typically, our reserves, production, operating cash flows and operating profitability has grown as properties have been drilled and 

developed and fall following strategic asset divestitures when we are incurring costs to drill and develop properties. As a result of drilling and other risks, there can be no assurance 

that our reserve and production growth strategy will allow us to continue to grow, and replace, our acreage position, reserves, production and profitability following divestitures and we 

may continue to experience large fluctuations in such positions.

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 require significant capital to prove and develop such properties before they may 

become productive. At December 31, 2010, approximately 99% of our net acreage was unproven and 54.1% 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 2010 sale of interests in certain assets, 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.

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:

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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 would 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.

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.

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 • delays imposed by or resulting from compliance with regulatory requirements;

 • pressure or irregularities in geological formations;

 • shortages of or delays in obtaining equipment and qualified personnel;

 • equipment failures or accidents;

 • adverse weather conditions;

 • reductions in oil and natural gas prices;

 • title problems; and

 • limitations in the market for oil and natural gas.

 

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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 each 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 approximately 54.1% 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.

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:

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 • the timing and amount of capital expenditures;

 • the timing of initiating the drilling and recompleting of wells;

 • the extent of operating costs; and

 • the level of ongoing production.

 • environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and 

shoreline contamination;

 • abnormally pressured formations;

 • mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;

 • fires and explosions;

 

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Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to our Company. We may elect not to obtain insurance if we believe that 

the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or 

other event occurs and is not fully covered by insurance, then it could adversely affect us.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

Exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large 

expenditures to comply with governmental regulations. Matters subject to regulation include:

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 will be subject to environmental and other government laws and regulations that are costly and could potentially subject us to substantial liabilities.

Crude oil and natural gas exploration and production operations in the United States and in Colombia are subject to extensive federal, state and local laws and regulations. Oil and 

gas companies are subject to laws and regulations addressing, among others, land use and lease permit restrictions, bonding and other financial assurance related to drilling and 

production activities, spacing of wells, unitization and pooling of properties, environmental and safety matters, plugging and abandonment of wells and associated infrastructure after 

production has ceased, operational reporting and taxation. Failure to comply with such laws and regulations can subject us to governmental sanctions, such as fines and penalties, as 

well as potential liability for personal injuries and property and natural resources damages. We may be required to make significant expenditures to comply with the requirements of 

these laws and regulations, and future laws or regulations, or any adverse change in the interpretation of existing laws and regulations, could increase such compliance costs. 

Regulatory requirements and restrictions could also delay or curtail our operations and could have a significant impact on our financial condition or results of operations.

Our oil and gas operations are subject to stringent laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental 

protection. These laws and regulations:

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 • personal injuries and death; and

 • natural disasters.

 • discharge permits for drilling operations;

 • drilling bonds;

 • reports concerning operations;

 • the spacing of wells;

 • unitization and pooling of properties; and

 • taxation.

 • require the acquisition of a permit before drilling commences;

 

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Failure to comply with these laws and regulations may result in:

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 attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our 

own results of operations, competitive position or financial condition. Although we intend to be in compliance in all material respects with all applicable environmental laws and 

regulations, we cannot assure you that we will be able to comply with existing or new regulations. In addition, the risk of accidental spills, leakages or other circumstances could expose 

us to extensive liability.

We are unable to predict the effect of additional environmental laws and regulations that may be adopted in the future, including whether any such laws or regulations would 

materially adversely increase our cost of doing business or affect operations in any area.

Under certain environmental laws that impose strict, joint and several liability, we may be required to remediate our contaminated properties regardless of whether such 

contamination resulted from the conduct of others or from consequences of our own actions that were or were not in compliance with all applicable laws at the time those actions were 

taken. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations. Moreover, new or modified environmental, health or 

safety laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. Therefore, the costs to comply with 

environmental, health or safety laws or regulations or the liabilities incurred in connection with them could significantly and adversely affect our business, financial condition or results 

of operations. In addition, many countries as well as several states and regions of the U.S. have agreed to regulate emissions of “greenhouse gases.” Methane, a primary component of 

natural gas, and carbon dioxide, a byproduct of burning of natural gas and oil, are greenhouse gases. Regulation of greenhouse gases could adversely impact some of our operations 

and demand for some of our services or products in the future. See “Business — Regulatory Matters.”

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.

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 • 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 operations.

 • the imposition of administrative, civil and/or criminal penalties;

 • incurring investigatory or remedial obligations; and

 • the imposition of injunctive relief.

 

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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, 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 and 2010, respectively, Hupecol sold its interest in a concession and in two entities holding multiple concessions each representing, at the time, the largest prospect(s) in terms of 

reserves and revenues in which we then held an interest. In early March 2009, Hupecol determined to temporarily shut-in production from our Colombian properties. It is possible that 

Hupecol will carry out similar sales or acquisitions of prospects or make similar decisions in the future. Our management intends to closely monitor the nature and progress of future 

transactions by Hupecol in order to protect our interests. However, we have no effective ability to alter or prevent a transaction and are unable to predict whether or not any such 

transactions will in fact occur or the nature or timing of any such transaction.

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 • all bilateral aid, except anti-narcotics and humanitarian aid, would be suspended;

 • the Export-Import Bank of the United States and the Overseas Private Investment Corporation would not approve financing for new projects in Colombia;

 • United States representatives at multilateral lending institutions would be required to vote against all loan requests from Colombia, although such votes would not 

constitute vetoes; and

 • the President of the United States and Congress would retain the right to apply future trade sanctions.

 

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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 37.5% 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.

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 attract and retain our management and non-management employees, including engineers, geoscientists and other technical and 

professional staff and, in particular, our President, John Terwilliger, who is principally responsible for sourcing our resource plays. We will depend, to a large extent, on the efforts, 

technical expertise and continued employment of such personnel and members of our management team. If members of our management team should resign or we are unable to attract 

the necessary personnel, our business operations could be adversely affected.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute on a timely basis our exploration 

and development plans within our budget.

Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our development and exploration operations. As the price of oil and 

natural gas increases, the demand for production equipment and personnel will likely also increase, potentially resulting, at least in the near-term, in shortages of equipment and 

personnel. In addition, larger producers may be more likely to secure access to such equipment by virtue of offering drilling companies more lucrative terms. If we are unable to acquire 

access to such resources, or can obtain access only at higher prices, not only would this potentially delay our ability to convert our reserves into cash flow, but could also significantly 

increase the cost of producing those reserves, thereby negatively impacting anticipated net income.

If our access to markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases.

Market conditions or the unavailability of satisfactory transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability 

of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to 

pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities 

owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business.

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We may operate in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such 

restrictions on our ability to sell our oil or natural gas have several adverse affects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a 

lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of 

production.

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

While we presently believe that our operating cash flows and funds on hand, including funds provided by our 2010 sale of certain Hupecol assets, 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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 • quarterly variations in our operating results;

 • operating results that vary from the expectations of management, securities analysts and investors;

 • changes in expectations as to our future financial performance;

 • announcements by us, our partners or our competitors of leasing and drilling activities;

 

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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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 • the operating and securities price performance of other companies that investors believe are comparable to us;

 • future sales of our equity or equity-related securities;

 • changes in general conditions in our industry and in the economy, the financial markets and the domestic or international political situation;

 • fluctuations in oil and gas prices;

 • departures of key personnel; and

 • regulatory considerations.

 • authorize our board of directors to issue “blank check” preferred stock, which is preferred stock that can be created and issued by our board of directors, without 

stockholder approval, with rights senior to those of our common stock;

 • provide for a staggered board of directors and three-year terms for directors, so that no more than one-third of our directors could be replaced at any annual meeting;

 • provide that directors may be removed only for cause; and

 • establish advance notice requirements for submitting nominations for election to the board of directors and for proposing matters that can be acted upon by stockholders at 

a meeting.

 

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Our management owns a significant amount of our common stock, giving them influence or control in corporate transactions and other matters, and their interests could differ 

from those of other shareholders.

At March 1, 2011, our directors and executive officers owned approximately 38.8% of our outstanding common stock. As a result, our current directors and executive officers are 

in a position to significantly influence or control the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of any amendment to our 

certificate of incorporation or bylaws, and the approval of mergers and other significant corporate transactions. Such level of control of the Company may delay or prevent a change of 

control on terms favorable to the other shareholders and may adversely affect the voting and other rights of other shareholders.

Not applicable.

We currently lease approximately 4,739 square feet of office space in Houston, Texas as our executive offices. Management anticipates that our space will be sufficient for the 

foreseeable future. The average monthly rental under the lease, which expires on May 31, 2012, is $6,682.

A description of our interests in oil and gas properties is included in “Item 1. Business.”

We may from time to time be a party to lawsuits incidental to our business. As of March 1, 2011, 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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Item 1B. Unresolved Staff Comments

Item 2. Properties

Item 3. Legal Proceedings

Item 4. (Removed and Reserved)

 

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PART II

Market Information

Our common stock is listed on the NYSE Amex (“AMEX”) under the symbol “HUSA.” Prior to July 27, 2010, our common stock traded on the Nasdaq Global Market also 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 1, 2011, the closing price of the common stock on AMEX was $15.03.

Holders

As of March 1, 2011, there were approximately 898 shareholders of record of our common stock, excluding holders in street name.

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, 2010 with respect to the shares of our common stock that may be issued under our existing equity compensation 

plans.

______________________________

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Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 High Low Dividend

Calendar Year 2010 Fourth Quarter $ 18.52 $ 10.40 $ 0.205

 Third Quarter 10.99 8.50 0.005

 Second Quarter 20.35 9.30 0.005

 First Quarter 18.55 6.39 0.005

 

Calendar Year 2009 Fourth Quarter $ 6.16 $ 3.38 $ 0.005

 Third Quarter 3.70 1.72 0.005

 Second Quarter 2.18 1.64 0.005

 First Quarter 4.38 1.77 0.020

Plan Category

Number of securities to be 

issued upon exercise of 

outstanding options, 

warrants and rights (a)

Weighted-average 

exercise price of 

outstanding options, 

warrants and rights (b)

Number of securities 

remaining available for 

future issuance under 

equity compensation plans 

(excluding securities 

reflected in column (a))

Equity compensation plans approved by security holders (1) 1,813,998 $ 6.57 886,002

Equity compensation plans not approved by security holders — — —

Total 1,813,998 $ 6.57 886,002

(1) Consists of 500,000 shares reserved for issuance under the Houston American Energy Corp. 2005 Stock Option Plan and 2,200,000 shares reserved for issuance under the 

Houston American Energy 2008 Equity Incentive Plan.

 

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Performance Graph

The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall 

such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that 

the Company specifically incorporates it by reference into such filing.

The following performance graph compares the change in the cumulative total return of Houston American Energy’s common stock, the Dow Jones U.S. Exploration and 

Production Index, and the S&P 500 Index for the five years ended December 31, 2010. The graph assumes that $100 was invested in the Company’s common stock and each index on 

December 31, 2005, and that dividends were reinvested.

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN AMONG

HOUSTON AMERICAN ENERGY CORPORATION, THE S&P 500 INDEX

AND DJ U.S. EXPL & PROD. INDEX

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December 31,

2005 2006 2007 2008 2009 2010

Houston American Energy Corporation $ 100 $ 234 $ 97 $ 109 $ 198 $ 584

S&P 500 Index $ 100 $ 116 $ 122 $ 77 $ 97 $ 112

DJ U.S. Expl. & Prod. Index $ 100 $ 105 $ 151 $ 91 $ 127 $ 149

 

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The following table sets forth a summary of selected historical financial information for each of the years in the five-year period ended December 31, 2010. This information is 

derived from our Financial Statements and the notes thereto. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. 

Financial Statements and Supplementary Data.”

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Item 6. Selected Financial Data

 Year Ended December 31,

 2010 2009 2008 2007 2006

 

Statement of Operations Data:

Revenue:

Oil and gas revenue $ 19,508,894 $ 8,116,275 $ 10,622,050 $ 4,977,172 $ 3,202,731

Total revenues 19,508,894 8,116,275 10,622,050 4,977,172 3,202,731

Expenses of operations:

Lease operating expense and severance tax 8,142,444 4,746,295 3,366,740 1,841,119 1,017,440

Joint venture expense 156,686 172,890 183,510 149,200 167,023

Depreciation and depletion 3,161,366 1,900,631 5,816,691 1,099,826 887,911

Impairment of oil and gas properties — — 5,621,106 348,019 —

General and administrative expense 4,896,955 2,768,195 3,152,930 1,568,228 1,231,079

Gain on sale of oil and gas properties (27,159,114) — (7,615,236 ) — —

Total operating expenses (10,801,663) 9,588,011 10,525,741 5,006,392 3,303,453

Income (loss) from operations 30,310,557 (1,471,736 ) 96,309 (29,220 ) (100,722 )

Other income (expense):

Interest income 65,155 64,882 295,375 649,742 496,490

Interest expense (4,772) — — — (57,278 )

Interest expense – related party — — — — (20,440 )

Interest expense – derivative — — — — (37,773 )

Loss on change in fair value of derivative — — — — (170,949 )

Financing costs — — — — (110,787 )

Other income 12,864 — — — —

Total other income 73,247 64,882 295,375 649,742 99,263

Net income (loss) before income taxes 30,383,804 (1,406,854 ) 391,684 620,572 (1,459 )

Income tax expense (benefit) 9,353,864 (737,406 ) (73,261 ) 127,116 510,637

Net income (loss) $ 21,029,940 $ (669,448) $ 464,945 $ 493,456 $ (512,096)

Basic net income (loss) per share $ 0.68 $ (0.02) $ 0.02 $ 0.02 $ (0.02)

Diluted net income (loss) per share $ 0.66 $ (0.02) $ 0.02 $ 0.02 $ (0.02)

Cash dividends paid per share $ 0.22 $ 0.04 $ 0.04 $ — $ —

 

Cash Flow Data:

Cash flow from operating activities $ 8,290,671 $ (484,677) $ 1,452,054 $ 1,801,481 $ 1,239,446

Cash flow from investing activities 12,660,487 (9,239,263 ) 8,787,853 (1,792,672 ) (17,507,371 )

Cash flow from financing activities (6,267,845) 11,786,383 (747,031 ) — 14,952,833

 

Balance Sheet Data (at end of period):

Working capital $ 34,255,206 $ 16,365,490 $ 10,536,834 $ 10,358,502 $ 14,202,160

Property, plant and equipment, net 10,691,421 11,356,255 5,263,131 10,017,045 5,248,272

Total assets 55,476,428 34,062,829 22,637,054 20,714,797 19,985,883

Long-term debt, less current portion 26,761 332,912 205,524 135,267 38,816

Total stockholders’ equity 50,364,637 33,245,312 21,048,248 20,243,447 19,414,783

 

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General

We are an independent energy company focused on the development, exploration, exploitation, acquisition, and production of natural gas and crude oil in the U.S. Gulf Coast 

region and in South America. Our oil and gas reserves and operations are concentrated primarily in the South American country of Colombia and in the onshore Gulf Coast region, 

particularly Texas and Louisiana.

Our mission is to deliver outstanding net asset value per share growth to our investors via attractive oil and gas investments. Our strategy is to focus on early identification of, 

and entrance into, existing and emerging resource plays, particularly in South America and the U.S. Gulf Coast. We typically seek to partner with larger operators in development of 

resources or retain interests, with or without contribution on our part, in prospects identified, packaged and promoted to larger operators. By entering these plays earlier and partnering 

with, or promoting to, larger operators, we believe we can capture larger resource potential at lower cost and minimize our exposure to drilling risks and costs and ongoing operating 

costs.

We, along with our partners, actively manage our resources through opportunistic acquisitions and divestitures where reserves can be identified, developed, monetized and 

financial resources redeployed with the objective of growing reserves, production and shareholder value.

Generally, we generate nearly all our revenues and cash flows from the sale of produced natural gas and crude oil, whether through royalty interests, working interests or other 

arrangements. We may also realize gains and additional cash flows from the periodic divestiture of assets.

Recent Developments

Production Levels, Commodity Prices and Revenues

Our production levels, commodity prices realized and revenues during 2010, as compared to 2009, benefited from improved market conditions during 2010 as compared to 2009 

when sharply lower prices prevailed, particularly during the first half of 2009, following the global economic crisis that began in late 2008. As a result of depressed commodity prices 

during the first half of 2009, 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.

Our December 2010 sale of our interest in entities holding four concessions in Colombia resulted in sharp declines in our production levels and revenues during the last half of 

December 2010, and will continue to produce lower production and revenue levels unless and until we can successfully drill wells and bring on line new and/or additional production 

from our other properties. See “Asset Sales – Hupecol Dorotea and Cabiona, LLC and Hupecol Llanos, LLC.”

Drilling Activity

During 2010, we drilled 12 international wells in Colombia, as follows:

During 2010, no domestic wells were drilled.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 • 4 wells were drilled on concessions in which we hold a 12.5% working interest, of which 3 were in production at December 31, 2010, and 1 was a dry hole.

 • One well was drilled on a concession in which we hold a 6.25% working interest and was a dry hole.

 • 7 wells were drilled on a concession in which we hold a 1.6% working interest, of which 6 were in production at December 31, 2010, and 1 was a dry hole.

 

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At December 31, 2010, drilling operations were ongoing in Colombia on 1 well.

Leasehold Activity

During 2010, we acquired an interest in one additional block in Colombia, the LLA 62 Block, one TEA, the Macaya TEA, and increased our interest in the CPO 4 Block in 

Colombia.

Macaya TEA. During 2010, we elected to participate for our percentage interest (12.5%) in the Macaya Technical Evaluation Agreement (the “TEA”). The TEA was entered into 

in February 2010 by and between the Colombian National Hydrocarbons Agency (the “ANH”) and Hupecol Operating Co. LLC, and encompasses a 195,171 acre region located to the 

southeast 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 TEA.

LLA 62 Block. During 2010, we elected to participate for our percentage interest (1.6%) in the LLA 62 Block in Colombia (the “LLA 62 Block”). The LLA 62 Block was awarded to 

Hupecol by the ANH during 2010. The LLA 62 Block is adjacent to the La Cuerva Block operated by Hupecol. The award of the LLA 62 Block includes a Phase I commitment to shoot 60 

square kilometers of 3D seismic on the block. As a result of the election to participate, we agreed to pay our proportionate share, or 1.6%, of all costs of exploiting the block, except the 

3D seismic costs, where we agreed to pay two times our proportional cost.

CPO 4 Farmout. Effective July 31, 2010, we entered into a Farmout Agreement (the “Farmout Agreement”) with SK Energy Co. LTD (“SK Energy”) pursuant to which SK Energy 

agreed to assign to our Company an additional 12.5% interest in the approximately 345,452 acre CPO 4 Block in the Llanos Basin of Colombia, increasing our current interest in the CPO 4 

Block from 25% to 37.5%.

SK Energy serves as operator on the CPO 4 Block under a Joint Operating Agreement (the “JOA”).

Under the terms of the Farmout Agreement, we are responsible for paying our proportionate interest in all future development and operating costs (“Ongoing Costs”). In addition 

to payment of our proportionate interest in Ongoing Costs, as a condition of assignment of the additional 12.5% interest in the CPO 4 Block, we are responsible for reimbursement to SK 

Energy, or payment, of (i) 12.5% of certain defined past costs relating to development of the CPO 4 Block (the “Past Costs”), and (ii) 25% of seismic acquisition costs incurred with 

respect to the Phase One cost of the CPO 4 Block between June 18, 2009 and June 17, 2012 (the “Seismic Acquisition Costs”). The Phase One seismic acquisition was completed during 

2010.

The assignment of the additional interest in the CPO 4 Block was conditioned upon the approval by the ANH and the Republic of Korea by July 31, 2011, and payment of our 

proportionate interest in Past Costs, which was due on the earlier of (i) October 29, 2010, or (ii) 30 days following ANH approval. In November 2010, we were invoiced for, and paid, 

$3,939,003 as our share of the Past Costs attributable to our additional 12.5% interest in CPO 4. In December 2010 the Company received ANH approval of our additional 12.5% interest 

in Block CPO 4 along with the assignment from SK bringing our total interest to 37.5% in the Block.

Pursuant to the terms of, and in conjunction with, the Farmout Agreement and the JOA, we entered into a separate agreement with Gulf United Energy, Inc. (“Gulf United”) 

whereby we waived our right of first refusal under the JOA for the specific purpose of permitting Gulf United to acquire a 12.5% interest in the CPO 4 Block. Under the agreement with 

Gulf United, as a condition of our agreement to waive our preferential rights, Gulf United agreed to pay to us, not later than 30 days following ANH approval, (i) our 12.5% share of Past 

Costs incurred through July 31, 2010, and (ii) our 25% share of Seismic Acquisition Costs incurred through July 31, 2010. ANH approval of the Gulf United assignment had not yet been 

received at December 31, 2010 or through the date of this filing. It is anticipated that upon Gulf United receiving ANH approval, it will reimburse us for the $3,939,003 invoiced by SK 

Energy for Past Costs; plus any additional cost accrued under the terms of the Farmout Agreement.

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Asset Sales

During 2010, we divested our direct interest in acreage in Karnes County, Texas and our indirect interest in the Dorotea, Cabiona, Leona and Las Garzas blocks in Colombia.

Hupecol Dorotea and Cabiona, LLC and Hupecol Llanos, LLC. During the fourth quarter of 2010, Hupecol Dorotea & Cabiona Holdings, LLC (“Hupecol D&C Holdings”) sold 

all of its interest in Hupecol Dorotea and Cabiona, LLC (“HDC, LLC”) and Hupecol Llanos Holdings, LLC (“Hupecol Llanos Holdings”) sold all of its interest in Hupecol Llanos, LLC 

(“HL, LLC”). We hold a 12.5% ownership interest in each of Hupecol D&C Holdings and Hupecol Llanos Holdings and, prior to the sale, held indirect interests in identical amounts in 

HDC, LLC and HL, LLC. HDC, LLC and HL, LLC hold interests in the Dorotea, Cabiona, Leona and Las Garzas blocks, and related assets, in Colombia.

The Dorotea, Cabiona, Leona and Las Garzas blocks cover an aggregate of approximately 310,790 acres. At December 31, 2009, the estimated proved reserves associated with the 

blocks totaled 1,178,576 barrels of oil, which represented 96.9% of our estimated proved oil and natural gas reserves.

As a result of the sale, we received net proceeds, after deduction of fees and expenses of $29,359,463 before escrow holdbacks, realized a gain on the sale of $25,397,048 and 

eliminated from oil and gas properties costs subject to amortization associated with the underlying assets totaling $3,989,236. Production from the Dorotea, Cabiona, Leona and Las 

Garzas blocks accounted for $18,880,299, $7,936,673 and $7,206,439 of our revenues during 2010, 2009 and 2008.

Fifteen percent of the sales price was held in escrow pursuant to the Purchase and Sales Agreement to fund potential claims arising from the sale with escrowed amounts to be 

released over a three year period based on amounts remaining in escrow after claims. In addition to the fifteen percent escrowed, Hupecol withheld 5% of the proceeds in escrow for any 

contingencies that may arise, and it is expected that the Company will receive the 5% withheld by Hupecol in 2011. The Company is not aware of any claims that would reduce the 

escrow amounts as of December 31, 2010. Our proportionate interest in the sales proceeds that were withheld and deposited into escrow totaled $7,069,810 and have been recorded as 

escrow receivables. Following completion of the sale of HDC, LLC and HL, LLC, we have no continuing interest in the Dorotea, Cabiona, Leona and Las Garzas blocks.

Karnes County, Texas. In November 2010, we sold our 2.5% working interest and our 1.25% of 8/8s overriding royalty interest (“ORRI”) in 6,000+ gross acres in Karnes County, 

Texas and our right to a 1.25% ORRI in an AMI covering approximately 50,000 gross acres in Karnes County, Texas. We received gross proceeds of $4.1 million from the sale of our 

Karnes County, Texas holdings. Our Karnes County, Texas holdings were acquired in 2009 at a cost of $175,000 and, at the time of sale, we had no wells, no production and no reserves 

associated with the acreage.

Seismic Activity

During 2010, our operators in Colombia acquired approximately 225 square miles of additional 3-D and 2-D seismic and geological data. The additional data relates primarily to the 

CPO 4, Serrania and La Cuerva concessions where we hold 37.5%, 12.5%, and 1.6% working interests, respectively. Our share of the costs of such data acquisition was approximately 

$6.4 million.

Compensation Expense

In June 2010, our board of directors approved, and we paid, cash bonuses to our senior management team totaling $637,500 and, effective June 15, 2010, we increased the base 

salary of members of our senior management team by 10%. In August 2010, we expanded our management team with the appointment of a then-consultant to serve as Senior Vice 

President of Exploration.

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Also in June 2010, we modified the non-cash compensation arrangements for our non-employee directors to provide for annual grants of stock options to purchase 25,000 shares 

of common stock. The option grants vest on the grant date, are exercisable at the fair market value on the grant date and have a term of ten years. Pursuant to such revised 

compensation arrangements, we granted 100,000 stock options to non-employee directors on June 15, 2010 and granted 25,000 stock options to a newly appointed non-employee 

director in July 2010. In August 2010, we granted 150,000 stock options to the newly appointed member of our management team. As a result of these 2010 option grants and the 

amortization of the cost associated with options granted in prior years that remain subject to vesting, we recognized non-cash compensation expense for 2010 totaling $2,357,230.

Dividends

During 2010, we declared and paid cash dividends to our shareholders of $0.22 per share, or an aggregate of $6,837,845.

Development and Operating Outlook

While we continually seek to identify and evaluate opportunities, both domestically and in South America, to acquire interests in early stage high potential resource plays, our 

focus since the beginning of 2010 has been, and continues to be, the development of our Colombian assets. In particular, we have been, and are, focused on development of our CPO 4 

and Serrania prospects in Colombia where we have increased our interest in CPO 4 during 2010, conducted extensive seismic acquisition and analysis, invested in infrastructure and 

conducted preliminary work in preparation for drilling wells on both of our CPO 4 and Serrania prospects.

Consistent with our past operating plans, we selectively divest holdings on an opportunistic basis where we believe that favorable prices can be realized from assets and 

proceeds redeployed to grow our asset base and produce superior returns. To that end, during 2010, we divested our interest in undeveloped domestic acreage and four blocks in 

Colombia which were in various stages of development, which divestitures produced approximately $29.4 million of net proceeds (including $7.1 million held in escrow) to our company.

During 2011, we plan to invest approximately $21.4 million in the development of our Colombian prospects, including CPO 4, Serrania and four prospects operated by Hupecol. As 

of January 1, 2011, substantially all seismic, infrastructure and pre-drilling work had been completed on both our CPO 4 and Serrania prospects and our plans are to drill 3 test wells on 

the CPO 4 block and 2 test wells on the Serrania block during 2011. Subject to the results of those test wells, we expect to begin developmental drilling of those prospects.

While our 2010 asset sales provided funding that we believe will satisfy our financial commitments relating to the CPO 4 and Serrania prospects, as well as our remaining Hupecol 

holdings, the interests sold during 2010 accounted for approximately 97% of our net oil production and oil revenues during 2010, as well as 99% of our lease operating expenses. 

Accordingly, until we bring production on line from drilling and development of our CPO 4, Serrania and remaining Hupecol prospects, our future production, revenues and lease 

operating expenses will be substantially lower than 2010 levels. There can be no assurance as to the ultimate success of our drilling and development operations on our CPO 4, Serrania 

and remaining Hupecol prospects or the timing of such drilling and development operations.

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, 2010. 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. Costs in excess of this ceiling 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 oil and gas properties subject to amortization. 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, 2010 and 2009:

The carrying value of unevaluated oil and gas prospects includes $9,647,631 and $2,993,732 expended for properties in South America at December 31, 2010 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 expected life of the options, 

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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At

December 31,

2010

At

December 31,

2009

Acquisition costs $ 2,795,439 $ 3,370,734

Evaluation costs 7,463,541 2,140,296

Retention costs -- 47,294

Total $ 10,258,980 $ 5,558,324

 

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Results of Operations

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Oil and Gas Revenues. Total oil and gas revenues increased 140.37%, to $19,508,894 in 2010 from $8,116,275 in 2009.

The increase in revenue is principally due to (1) higher average sales prices for oil and gas during 2010 reflecting increased commodity pricing due to improved global 

macroeconomic conditions compared to 2009 and (2) increased oil production due to new wells brought onto production and production from our Colombian properties for the full 

period in 2010 as compared to 2009, when production was temporarily shut-in for 52 days due to market conditions.

 

The following table sets forth the gross and net producing wells, net oil and gas production volumes and average hydrocarbon sales prices for 2010 and 2009:

As noted, production volumes were less then what they otherwise would have been in 2009 due to 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.

Oil and gas sales revenues for 2010 and 2009 by region were as follows:

Lease Operating Expenses. Lease operating expenses, excluding joint venture expenses relating to our Colombian operations discussed below, increased 71.5% to $8,142,444 in 

2010 from $4,746,295 in 2009.

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

The increase in total lease operating expenses was attributable to an increase in production and the number of net wells producing. The decrease in lease operating expenses as a 

percentage of revenues, from 58% of revenues in 2009 to 42% of revenues in 2010, was attributable to the temporary cessation of production from the majority of our Colombian 

properties during the 2009 period and increased production and improved commodity prices during 2010.

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 2010 (1) 2009

Gross producing wells 34 26

Net producing wells 2.704 2.31

Net oil production (Bbls) 261,779 131,363

Net gas production (Mcf) 17,798 15,761

Oil—Average sales price per barrel $ 74.18 $ 61.20

Gas—Average sales price per mcf $ 5.01 $ 4.89

(1) As noted elsewhere, we sold our indirect interest in four Colombian concessions in December 2010. Of the wells and production shown in 2010, the concessions sold in 

December 31, 2010 account for 19 gross wells, 2.375 net wells and 254,785 bbls of net oil production.

 Colombia U.S. Total

2010

Oil sales $ 19,302,303 $ 117,360 $ 19,419,663

Gas sales $ — $ 89,231 $ 89,231

2009

Oil sales $ 7,944,353 $ 94,839 $ 8,039,192

Gas sales $ — $ 77,083 $ 77,083

 Colombia U.S. Total

2010 $ 8,088,230 $ 54,214 $ 8,142,444

2009 $ 4,665,578 $ 80,717 $ 4,746,295

 

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Joint Venture Expenses. Joint venture expenses totaled $156,686 in 2010 compared to $172,890 in 2009. The joint venture expenses represent our allocable share of the indirect 

field operating and region administrative expenses billed by Hupecol.

Depreciation and Depletion Expense. Depreciation and depletion expense increased by 66% to $3,161,366 in 2010 from $1,900,631 in 2009. The increase in depreciation and 

depletion was due to an increase in production volumes during 2010.

Gain on sale of oil and gas properties. The sale of our indirect interests in Hupecol Dorotea and Cabiona, LLC and Hupecol Llanos, LLC resulted in a gain of $25,397,048, and the 

sale of our Karnes County, Texas interests resulted in a gain of $1,762,066 during 2010.

General and Administrative Expenses. General and administrative expense increased by 77% to $4,896,955 in 2010 from $2,768,195 in 2009. The increase in general and 

administrative expense was primarily attributable to increases in employee compensation, principally related to the payment of $637,500 of cash bonuses, a 10% increase in base salaries 

effective June 15, 2010, the hiring of an additional executive and a $1,277,100 increase in stock-based compensation in 2010 versus 2009 associated with options granted to directors and 

officers during 2010.

Other Income. Other income consists primarily of interest earned on cash balances. Other income totaled $65,155 in 2010 as compared to $64,882 in 2009. The increase in other 

income resulted primarily from an increase in larger average interest earning cash balances.

Income Tax Expense/Benefit. We reported an income tax expense of approximately $9.4 million in 2010 as compared to a benefit of $737,406 in 2009.

The income tax expense during 2010 was entirely attributable to operations in Colombia and reflects increased sales and profitability in Colombia, as well as the taxes applicable to 

the proceeds received on sale of oil and gas properties discussed above.

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.

At December 31, 2010, we had no foreign tax credit carryovers.

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 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).

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:

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 2009 2008

Gross producing wells 26 16

Net producing wells 2.31 1.47

Net oil production (Bbls) 131,363 123,925

Net gas production (Mcf) 15,761 24,748

Oil—Average sales price per barrel $ 61.20 $ 83.67

Gas—Average sales price per mcf $ 4.89 $ 10.22

 

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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 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, implemented cost cutting measures in order to improve field economics from our Colombian operations.

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 than expected production volumes, as well as the lack of commercial production on our Caddo Lake prospect.

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 Colombia U.S. Total

2009

Oil sales $ 7,944,353 $ 94,839 $ 8,039,192

Gas sales $ — $ 77,083 $ 77,083

2008

Oil sales $ 10,211,579 $ 157,492 $ 10,369,071

Gas sales $ — $ 252,979 $ 252,979

 Colombia U.S. Total

2009 $ 4,665,578 $ 80,717 $ 4,746,295

2008 $ 3,232,213 $ 134,527 $ 3,366,740

 

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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 related to assets the Company was considering acquiring out of a bankruptcy 

proceeding.

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.

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, 2010, we had a cash balance of $26,656,450 and working capital of $34,255,206 compared to a cash balance of $11,973,137 and 

working capital of $16,365,490 at December 31, 2009. The increase in cash and working capital during the period was primarily attributable to the receipt of $25,942,822 (net proceeds) 

excluding escrowed monies from the sale of our Karnes County, Texas property and our indirect interest in four concessions in Colombia and operating cash flow, partially offset by 

payment of drilling costs, acquisition costs, seismic costs and other costs related to the planned drilling of prospects in Colombia and the payment of dividends.

Cash Flows. Operating activities provided cash during 2010 totaling $8,290,671 as compared to $484,677 of cash used in operating activities during 2009. The increase in cash 

flows from operations was primarily a result of improved profitability during 2010.

Investing activities provided cash during 2010 totaling $12,660,487 as compared to $9,239,263 used in investing activities during 2009. Funds provided by investing activities 

during 2010 reflect the receipt of proceeds from the sale of our Karnes County, Texas property and our indirect interest in four Colombian concessions which provided, in the aggregate, 

approximately $25,942,822 of net proceeds excluding escrowed amounts. The funds provided by investing activities during 2010 were partially offset by investments in oil and gas 

properties and assets and property plant and equipment of $8,662,516 and payments of $3,951,370 of costs associated with the CPO 4 prospect that are reimbursable by Gulf United and 

recorded as accounts receivable - other. 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.

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37
Financing activities used $6,267,845 of cash during 2010 as compared to $11,786,383 of cash provided by financing activities during 2009. Funds used by financing activities 

during 2010 consisted of cash dividends paid of $6,837,845, partially offset by warrant exercise proceeds received of $570,000. 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.

Long-Term Liabilities. At December 31, 2010, we had long-term liabilities of $26,761 as compared to $332,912 at December 31, 2009. Long-term liabilities at December 31, 2010 and 

December 31, 2009 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. 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 2010 sale of certain properties and our 2009 sale of common stock.

During 2010, we invested approximately $8.6 million for the acquisition and development of oil and gas properties, which included expenses related to (1) drilling of 12 wells in 

Colombia ($1.3 million ), (2) seismic and geological costs in Colombia ($7.0 million), (3) delay rentals on U.S. properties ($12 thousand), and (4) leasehold costs on U.S. properties ($0.3 

million).

At December 31, 2010, 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, 2010:

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, 2010, our acquisition and drilling budget for 2011 totaled approximately $21.4 million and related 

principally to (1) drilling 10 wells in Colombia on existing Hupecol prospects; (2) drilling 2 wells on the Serrania Block operated by Shona Energy; and (3) drilling 3 wells on the CPO 4 

Block operated by SK Energy. 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.

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. 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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 Payments due by period

 Total < 1 year 1-3 years 3-5 years > 5 years

Operating leases $ 123,214 $ 84,315 $ 38,899 $ — $ —

Total $ 123,124 $ 84,315 $ 38,899 $ — $ —

 

38
Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements or guarantees of third party obligations at December 31, 2010.

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 44 of this report.

Not applicable.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Item 8. Financial Statements and Supplementary Data

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

39
Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our principal executive and principal financial officers, we conducted an evaluation as of 

December 31, 2010 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, 2010.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under 

the Securities Exchange Act of 1934. Under the supervision and with the participation of management, including our principal executive and principal financial officers, we conducted an 

evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of 

Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this evaluation under the COSO Framework, management concluded that our internal 

control over financial reporting was effective as of December 31, 2010.

The effectiveness of our internal control over financial reporting as of December 31, 2010 has been audited by GHB CPAs, PC, an independent registered public accounting firm 

who audited our consolidated financial statements as of and for the year ended December 31, 2010, as stated in their report, which is included herein.

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the fourth quarter of 2010 that has materially affected, or is reasonably likely to materially affect, our 

internal control over financial reporting.

Not applicable

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Item 9A. Controls and Procedures

Item 9B. Other Information

 

40
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, 2010, 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.

Kenneth Jeffers has served as our Senior Vice President of Exploration since August 2010. Prior to his appointment as an officer, Mr. Jeffers served as a consultant to Houston 

American for six months focused on identification of prospects on the Company’s Colombian acreage. Previously, Mr. Jeffers served as Vice President, Geophysics for Goodrich 

Petroleum Corporation from 2004 to 2007. Mr. Jeffers’ experience includes serving as an exploration geophysicist with Mobil Oil and later serving as a staff geophysicist and senior 

geophysicist with Anadarko Petroleum, Pennzoil, Hunt Oil and Goodrich Petroleum.

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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Item 10. Directors, Executive Officers and Corporate Governance

Name Age Position

John F. Terwilliger 63 President, Chief Executive Officer and Chairman

James J. Jacobs 33 Chief Financial Officer

Kenneth Jeffers 50 Senior Vice President of Exploration

Item 11. Executive Compensation

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13. Certain Relationships and Related Transactions, and Director Independence

Item 14. Principal Accountant Fees and Services

 

41
PART IV

_________________________________

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Item 15. Exhibits and Financial Statement Schedules

 1. Financial statements. See “Index to Financial Statements” on page 44 of this report.

 2. Exhibits

 Incorporated by Reference 

Exhibit

Number Exhibit Description Form Date Number

Filed

Herewith

3.1 Certificate of Incorporation of Houston American Energy Corp. filed April 2, 

2001

SB-2 8/3/01 3.1 

 

3.2 Amended and Restated Bylaws of Houston American Energy Corp. adopted 

November 26, 2007

8-K 11/29/07 3.1 

 

3.3 Certificate of Amendment to the Certificate of Incorporation of Houston 

American Energy Corp. filed September 25, 2001

SB-2 10/01/01 3.4 

 

4.1 Text of Common Stock Certificate of Houston American Energy Corp. SB-2 8/3/01 4.1 

 

10.1 Houston American Energy Corp. 2005 Stock Option Plan* 8-K 8/16/05 10.1 

 

10.2 Form of Director Stock Option Agreement* 8-K 8/16/05 10.2 

 

10.3 Houston American Energy Corp. 2008 Equity Incentive Plan* Sch 14A 4/28/08 Ex A 

 

10.4 Letter Agreement, dated February 3, 2009, between Houston American 

Energy Corp., Yazoo Pipeline Co., L.P., Sterling Exploration & Production Co., 

L.L.C., and Matagorda Operating Company.

8-K 2/05/09 10.1 

 

10.5 Form of Subscription Agreement, dated November 2009 relating to the sale of 

shares of common stock

8-K 12/03/09 10.1 

 

10.6 Employment Agreement of Kenneth Jeffers* X

 

14.1 Code of Ethics for CEO and Senior Financial Officers 10-KSB 3/26/04 14.1 

 

23.1 Consent of GBH CPAs, PC X

 

23.2 Consent of Lonquist & Co., LLC X

 

31.1 Section 302 Certification of CEO X

 

31.2 Section 302 Certification of CFO X

 

32.1 Section 906 Certification of CEO X

 

32.2 Section 906 Certification of CFO X

 

99.1 Code of Business Ethics 8-K 7/7/06 99.1 

 

99.2 Report of Lonquist & Co., LLC X

* Compensatory plan or arrangement.

 

42
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.

Dated: March 15, 2011

 

 By: /s/ John F. Terwilliger

 John F. Terwilliger

President

Signature Title Date

/s/ John F. Terwilliger Chairman, Chief Executive Officer, President and Director (Principal 

Executive Officer)

March 15, 2011

John F. Terwilliger 

 

/s/ O. Lee Tawes III Director March 15, 2011

O. Lee Tawes, III 

 

/s/ Stephen Hartzell Director March 15, 2011

Stephen Hartzell 

 

/s/ John P. Boylan Director March 15, 2011

John P. Boylan 

 

/s/ James J. Jacobs Chief Financial Officer (Principal Accounting and Financial Officer) March 15, 2011

James J. Jacobs 

 

43
HOUSTON AMERICAN ENERGY CORP.

INDEX TO FINANCIAL STATEMENTS

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Reports of Independent Registered Public Accounting Firm 45

 

Consolidated Balance Sheets as of December 31, 2010 and December 31, 2009 47

 

Consolidated Statements of Operations For the Years Ended December 31, 2010, 2009 and 2008 48

 

Consolidated Statement of Changes in Shareholders’ Equity for the Years Ended December 31, 2010, 2009 and 2008 49

 

Consolidated Statements of Cash Flows For the Years Ended December 31, 2010, 2009 and 2008 50

 

Notes to Consolidated Financial Statements 51

 

44
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Houston American Energy Corp.

Houston, Texas

We have audited Houston American Energy Corp.’s (the “Company”) internal control over financial reporting as of December 31, 2010, based on criteria established in Internal 

Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Criteria”). The Company’s management is responsible 

for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in Management’s Report 

on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express an opinion on the effectiveness of the Company’s internal control over financial 

reporting based upon our audit.

We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those 

standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material 

respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design 

and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our 

audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers, or 

persons performing similar functions, and effected by the Company’s board of directors, management, and other personnel, to provide reasonable assurance regarding the reliability of 

financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and 

procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) 

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and 

that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable 

assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial 

statements.

Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, 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 our opinion, Houston American Corp. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based upon the COSO 

Criteria.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Houston 

American Energy Corp. as of December 31, 2010 and 2009, and the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for the years ended 

December 31, 2010, 2009 and 2008, and our report dated March 15, 2011 expressed an unqualified opinion thereon.

/s/GBH CPAs, PC

GBH CPAs, PC

www.gbhcpas.com

Houston, Texas

March 15, 2011

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45
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, 2010 and 2009, and the related 

consolidated statements of operations, changes in shareholders’ equity, and cash flows for the years ended December 31, 2010, 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. 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, 2010 and 2009, and the results of their operations and their cash flows for the years ended December 31, 2010, 2009 and 2008, in conformity with accounting principles 

generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Houston American Energy 

Corp.’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of 

Sponsoring Organizations of the Treadway Commission, and our report dated March 15, 2011 expressed an unqualified opinion thereon.

/s/ GBH CPAs, PC

GBH CPAs, PC

www.gbhcpas.com

Houston, Texas

March 15, 2010

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46
HOUSTON AMERICAN ENERGY CORP.

CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of these consolidated financial statements.

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 December 31,

 2010 2009

ASSETS

CURRENT ASSETS

Cash $ 26,656,450 $ 11,973,137

Restricted cash – letter of credit 3,056,250 2,037,500

Accounts receivable – oil and gas sales 1,226,341 1,831,674

Accounts receivable – other 3,951,370 —

Escrow receivable – current 4,440,953 873,871

Note receivable — 125,000

Prepaid expenses and other current assets 8,872 8,913

TOTAL CURRENT ASSETS 39,340,236 16,850,095

PROPERTY, PLANT AND EQUIPMENT

Oil and gas properties, full cost method

Costs subject to amortization 1,831,738 22,050,265

Costs not being amortized 10,258,980 5,558,324

Office equipment 90,004 11,878

Total 12,180,722 27,620,467

 

Accumulated depletion, depreciation, amortization, and impairment (1,489,301) (16,264,212)

PROPERTY, PLANT AND EQUIPMENT, NET 10,691,421 11,356,255

 

Deferred tax asset 1,997,079 5,680,026

Escrow receivable 3,434,167 —

Other assets 13,525 176,453

TOTAL ASSETS $ 55,476,428 $ 34,062,829

LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES

Accounts payable $ 122,536 $ 469,528

Accrued expenses 11,963 14,949

Income taxes payable 4,950,531 128

TOTAL CURRENT LIABILITIES 5,085,030 484,605

LONG-TERM DEBT

Reserve for plugging and abandonment costs 15,441 316,260

Deferred rent obligation 11,320 16,652

TOTAL LONG-TERM DEBT 26,761 332,912

 

COMMITMENTS AND CONTINGENCIES -— -—

 

SHAREHOLDERS’ EQUITY

Common stock, par value $0.001;

100,000,000 shares authorized, 31,080,772 and 30,890,772 shares issued and outstanding, respectively 31,081 30,891

Additional paid-in capital 38,422,435 35,495,395

Accumulated earnings (deficit) 11,911,121 (2,280,974)

TOTAL SHAREHOLDERS’ EQUITY 50,364,637 33,245,312

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $ 55,476,428 $ 34,062,829

 

47
HOUSTON AMERICAN ENERGY CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

The accompanying notes are an integral part of these consolidated financial statements.

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 2010 2009 2008

 

Oil and gas revenue $ 19,508,894 $ 8,116,275 $ 10,622,050

 

EXPENSES OF OPERATIONS

Lease operating expense and severance tax 8,142,444 4,746,295 3,366,740

Joint venture expense 156,686 172,890 183,510

Depreciation and depletion 3,161,366 1,900,631 5,816,691

Impairment of oil and gas properties — — 5,621,106

Gain on sale of oil and gas properties (27,159,114) — (7,615,236)

General and administrative expense 4,896,955 2,768,195 3,152,930

Total expenses (10,801,663) 9,588,011 10,525,741

 

Income (loss) from operations 30,310,557 (1,471,736) 96,309

 

OTHER INCOME (EXPENSE)

Interest income 65,155 64,882 295,375

Interest expense (4,772) — —

Other income 12,864 — —

Total other income 73,247 64,882 295,375

 

Net income (loss) before taxes 30,383,804 (1,406,854) 391,684

 

Income tax expense (benefit) 9,353,864 (737,406) (73,261)

Net income (loss) $ 21,029,940 $ (669,448) $ 464,945

Basic net income (loss) per share $ 0.68 $ (0.02) $ 0.02

Diluted net income (loss) per share $ 0.66 $ (0.02) $ 0.02

Basic weighted average shares 31,070,101 28,214,553 27,992,808

Diluted weighted average shares 31,958,073 28,214,553 28,038,847

 

48
HOUSTON AMERICAN ENERGY CORP.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 and 2008

The accompanying notes are an integral part of these consolidated financial statements.

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 Common Stock Treasury Stock

Accumulated 

Earnings

 Shares Amount

Additional 

Paid-in 

Capital Shares Amount (Deficit) Total

Balance at December 31, 2007 27,920,172 $ 27,920 $ 22,377,832 (100,000) $ (85,834) $ (2,076,471) $ 20,243,447

 

Retired treasury stock (100,000) (100) (85,734) 100,000 85,834 — —

 

Stock issued for -

Employees 55,600 56 400,264 — — — 400,320

Warrant exercise 125,000 125 374,875 — — — 375,000

Options issued to directors — — 15,113 — — — 15,113

Options issued to employee — — 671,454 — — — 671,454

Dividends paid — — (1,122,031) — — — (1,122,031)

 

Net income — — — — — 464,945 464,945

Balance at December 31, 2008 28,000,772 $ 28,001 $ 22,631,773 — $ — $ (1,611,526) $ 21,048,248

 

Stock issued for -

Cash, net of offering costs of $758,760 2,890,000 $ 2,890 $ 12,763,550 — $ — $ — $ 12,766,440

Options issued to directors — — 38,174 — — — 38,174

Options issued to employee — — 1,041,955 — — — 1,041,955

Dividends paid — — (980,057) — — — (980,057)

 

Net loss — — — — — (669,448) (669,448)

Balance at December 31, 2009 30,890,772 $ 30,891 $ 35,495,395 — $ — $ (2,280,974) $ 33,245,312

 

Stock issued for - Warrant exercise 190,000 $ 190 $ 569,810 — $ — $ — $ 570,000

Options issued to directors — — 1,177,783 — — — 1,177,783

Options issued to employee — — 1,179,447 — — — 1,179,447

Dividends paid — — — — — (6,837,845) (6,837,845)

 

Net income — — — — — 21,029,940 21,029,940

Balance at December 31, 2010 31,080,772 $ 31,081 $ 38,422,435 — $ — $ 11,911,121 $ 50,364,637

 

49
HOUSTON AMERICAN ENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008

The accompanying notes are an integral part of these consolidated financial statements.

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 2010 2009 2008

CASH FLOW FROM OPERATING ACTIVITIES

Net income (loss) $ 21,029,940 $ (669,448) $ 464,945

 

Adjustments to reconcile net income (loss) to net cash provided by (used in) operations

Depreciation and depletion 3,161,366 1,900,631 5,816,691

Stock based compensation 2,357,230 1,080,129 1,086,887

Impairment of oil and gas properties — — 5,621,106

Deferred tax asset 3,682,947 (402,672) (5,277,354)

Accretion of asset retirement obligation 24,272 13,038 17,501

Amortization of deferred rent (5,332) (2,962) (592)

Gain on sale of oil and gas properties (27,159,114) — (7,615,236)

Change in operating assets and liabilities:

Decrease (increase) in accounts receivable 605,333 (1,516,043) 278,716

Decrease in prepaid expense 41 11,327 12,191

(Decrease) increase in accounts payable and accrued liability 4,593,988 (898,677) 1,047,199

Net cash provided by (used in) operations 8,290,671 (484,677) 1,452,054

CASH FLOW FROM INVESTING ACTIVITIES

Purchases of marketable securities — — (3,000,000)

Sales of marketable securities — — 12,650,000

Restricted cash held for letter of credit (1,018,750) (2,037,500) —

Payments for accounts receivable - other (3,951,370) — —

Payments for issuance of note receivable — (125,000) —

Proceeds from payment of note receivable 125,000 — —

Payments for acquisition and development of oil and gas properties and assets (8,662,516) (8,273,545) (10,841,353)

Proceeds from sale of Colombian properties, net of expenses 22,289,653 — 9,878,797

Proceeds from sale of US properties, net of expenses 3,653,169 397,102 273,696

Payments for property, plant, and equipment (78,126) — —

Payments for deposits (10,357) — —

Proceeds (payments) from (to) escrow receivable, net 313,784 799,680 (173,287)

Net cash provided by (used in) investing activities 12,660,487 (9,239,263) 8,787,853

CASH FLOW FROM FINANCING ACTIVITIES

Sale of common stock — 13,525,200 —

Common stock offering costs — (758,760) —

Exercise of warrants 570,000 — 375,000

Dividends paid (6,837,845) (980,057) (1,122,031)

Net cash provided by (used in) financing activities (6,267,845) 11,786,383 (747,031)

INCREASE IN CASH 14,683,313 2,062,443 9,492,876

Cash, beginning of year 11,973,137 9,910,694 417,818

Cash, end of year $ 26,656,450 $ 11,973,137 $ 9,910,694

SUPPLEMENTAL CASH FLOW INFORMATION:

Interest paid $ 4,772 $ — $ —

Taxes paid $ 720,512 $ 224,261 $ 5,200,306

 

SUPPLEMENTAL NON-CASH INVESTING AND FINANCING ACTIVITIES

Net change in asset retirement obligation $ 3,142 $ 117,312 $ 99,981

Retired treasury stock $ — $ — $ 85,834

Cash proceeds from sale of oil and gas properties escrowed $ 7,315,033 $ — $ 1,673,551

 

50
HOUSTON AMERICAN ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Houston American Energy Corp. (a Delaware Corporation) (“the Company” or “HUSA”) was incorporated on April 2, 2001. The Company is engaged, as a non-operating joint 

owner, in the exploration, development, and production of natural gas, crude oil, and condensate from properties located principally in the Gulf Coast area of the United States and 

international locations with proven production, which to date has focused on Colombia, South America.

Consolidation

The accompanying consolidated financial statements include all accounts of HUSA and its subsidiaries (HAEC Louisiana E&P, Inc. and HAEC Caddo Lake E&P, Inc.). All 

significant inter-company balances and transactions have been eliminated in consolidation.

General Principles and Use of Estimates

The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America. In preparing financial 

statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the 

reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to such potential matters as 

litigation, environmental liabilities, income taxes, determination of proved reserves of oil and gas and asset retirement obligations. Changes in facts and circumstances may result in 

revised estimates and actual results may differ from these estimates.

Reclassification

Certain amounts for prior periods have been reclassified to conform to the current presentation.

Oil and Gas Revenues

The Company recognizes sales revenues, net of royalties and net profits interests, based on the amount of gas, oil and condensate sold to purchasers when delivery to the 

purchaser has occurred and title has transferred. This occurs when production has been delivered to a pipeline. The Company follows the sales method to account for natural gas 

imbalances. Sales may result in more or less than the Company’s share of pro-rata production from certain wells. When natural gas sales volumes exceed the Company’s entitled share 

and the accumulated overproduced balance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company will record a 

liability. Historically, sales volumes have not materially differed from the Company’s entitled share of natural gas production and the Company did not have a material imbalance 

position in terms of volumes or values at December 31, 2010 or 2009.

Oil and Gas Properties

The Company uses the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs for 

unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. Capitalized costs include lease acquisition, geological and 

geophysical work, delay rentals, costs of drilling, completing and equipping the wells and any internal costs that are directly related to acquisition, exploration and development 

activities but does not include any costs related to production, general corporate overhead or similar activities. Proceeds from the sale or other disposition of oil and gas properties are 

generally treated as a reduction in the capitalized costs of oil and gas properties, unless the impact of such a reduction would significantly alter the relationship between capitalized 

costs and proved reserves of oil and natural gas attributable to a country.

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The Company categorizes its full costs pools as costs subject to amortization and costs not being amortized. The sum of net capitalized costs subject to amortization, including 

estimated future development and abandonment costs, are amortized using the unit-of-production method. Depletion and amortization for oil and gas properties was $3,145,915, 

$1,900,631 and $5,816,691 at December 31, 2010, 2009 and 2008, respectively and accumulated amortization, depreciation and impairment was $1,461,972 and $16,252,334 at December 31, 

2010 and 2009, respectively.

Costs Excluded

Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent costs of investments in unproved properties. The 

Company excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed 

quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the costs subject to amortization.

Ceiling Test

Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X. The ceiling 

test determines a limit, on a country-by-country basis, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated 

depreciation, depletion, amortization and impairment (“DD&A”) and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas 

reserves, calculated for 2010 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) with consideration of price change only to the extent provided by contractual arrangement, discounted at 10%, net of 

related tax effects. If capitalized costs exceed this limit, the excess is charged to expense and reflected as additional accumulated DD&A.

Unevaluated oil and gas properties not subject to amortization at December 31, 2010 included the following:

Unevaluated oil and gas properties not subject to amortization at December 31, 2009 included the following:

Furniture and Equipment

Office equipment is stated at original cost and is depreciated on the straight-line basis over the useful life of the assets, which ranges from three to five years.

Depreciation expense for office equipment was $15,451 for 2010 and $0 for 2009 and 2008 and accumulated depreciation was $27,329 at December 31, 2010.

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 North America South America Total

Leasehold acquisition costs $ 610,468 $ 2,184,971 $ 2,795,439

Geological, geophysical, screening and evaluation costs 880 7,462,661 7,463,541

Total $ 611,348 $ 9,647,632 $ 10,258,980

North America South America Total

Leasehold acquisition costs $ 814,766 $ 2,555,968 $ 3,370,734

Geological, geophysical, screening and evaluation costs 1,702,533 437,763 2,140,296

Leasehold retention costs 47,294 — 47,294

Total $ 2,564,593 $ 2,993,731 $ 5,558,324

 

52
Asset Retirement Obligations

The Company has adopted Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 410, Asset Retirement and Environmental 

Obligations (“ASC 410”), which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement 

costs. For the Company, asset retirement obligations (“ARO”) represent the systematic, monthly accretion and depreciation of future abandonment costs of tangible assets such as 

platforms, wells, service assets, pipelines, and other facilities. ASC 410 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is 

incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is 

accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the 

recorded amount, an adjustment is made to the full cost pool, with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs 

and proved reserves. Although the Company’s domestic policy with respect to ARO is to assign depleted wells to a salvager for the assumption of abandonment obligations before the 

wells have reached their economic limits, as required under ASC 410, the Company has estimated its future ARO obligation with respect to its domestic operations. With the adoption of 

ASC 410, the ARO assets, which are carried on the balance sheet as part of the full cost pool, have been included in our amortization base for the purposes of calculating depreciation, 

depletion and amortization expense. For the purposes of calculating the ceiling test, the future cash outflows associated with settling the ARO liability have been included in the 

computation of the discounted present value of estimated future net revenues.

The following table describes changes in our asset retirement liability during each of the years ended December 31, 2010 and 2009. The ARO liability in the table below includes 

amounts classified as both current and long-term at December 31, 2010 and 2009.

Joint Venture Expense

Joint venture expense reflects the indirect field operating and regional administrative expenses billed by the operator of the Colombian concessions.

Income Taxes

Deferred income taxes are provided on a liability method whereby deferred tax assets and liabilities are established for the difference between the financial reporting and income 

tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it 

is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates 

on the date of enactment. At December 31, 2010, the Company had a deferred tax asset of $1,997,079.

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North America

Years Ended

December 31

South America

Years Ended

December 31

 2010 2009 2010 2009

ARO liability at January 1 $ 24,506 $ 9,479 $ 291,754 $ 176,431

Accretion expense 2,568 882 21,704 12,156

Liabilities incurred from drilling — 15,241 6,856 91,727

Liabilities settled—assets sold (21,144) — (307,089) —

Changes in estimates (449) (1,096 ) (3,265) 11,440

 

ARO liability at December 31, $ 5,481 $ 24,506 $ 9,960 $ 291,754

 

53
Preferred Stock

The Company has authorized 10,000,000 shares of preferred stock with a par value of $0.001. The Board of Directors shall determine the designations, rights, preferences, 

privileges and voting rights of the preferred stock as well as any restrictions and qualifications thereon. No shares of preferred stock have been issued.

Cash and Cash Equivalents

Cash and cash equivalents consist of demand deposits and cash investments with initial maturity dates of less than three months.

Net Income (Loss) Per Share

Pursuant to FASB ASC Topic 260, Earnings Per Share, basic net income (loss) per share is computed by dividing the net income (loss) attributable to common shareholders by 

the weighted-average number of common shares outstanding during the period. Diluted net income (loss) per share is computed by dividing the net income (loss) attributable to 

common shareholders by the weighted-average number of common and common equivalent shares outstanding during the period. Common share equivalents included in the diluted 

computation represent shares issuable upon assumed exercise of stock options and warrants using the treasury stock and “if converted” method. For periods in which net losses are 

incurred, weighted average shares outstanding is the same for basic and diluted loss per share calculations, as the inclusion of common share equivalents would have an anti-dilutive 

effect.

As of December 31, 2010, 1,813,998 outstanding options to purchase common stock resulted in weighted averaged diluted shares outstanding of 31,958,073 based upon the 

treasury method, which resulted in $0.66 diluted earnings per share. For the year ended December 31, 2009, 1,538,998 options and 190,000 warrants to purchase common stock were 

excluded from the calculation of diluted net loss per share because they were anti-dilutive. For the year ended December 31, 2008, 1,392,333 options and 190,000 warrants to purchase 

common stock resulted in weighted average diluted shares outstanding of 28,038,847 based upon the treasury method, which resulted in $0.02 diluted earnings per share.

Concentration of Risk

The Company is dependent upon the industry skills and contacts of John F. Terwilliger and James J. Jacobs, the chief executive officer and chief financial officer, respectively, to 

identify potential acquisition targets in the onshore coastal Gulf of Mexico region of Texas and Louisiana and in the South American country of Colombia. Further, as a non-operator oil 

and gas exploration and production company, and through its interest in a limited liability company (“Hupecol”) and concessions operated by Hupecol, Shona Energy and by SK 

Energy in the South American country of Colombia, the Company is dependent on the personnel, management and resources of Hupecol, Shona Energy and SK Energy to operate 

efficiently and effectively.

As a non-operating joint interest owner, the Company has a right of investment refusal on specific projects and the right to examine and contest its division of costs and 

revenues determined by the operator.

The Company currently has interests in concessions in Colombia and expects to be active in Colombia for the foreseeable future. The political climate in Colombia is unstable and 

could be subject to radical change over a very short period of time. In the event of a significant negative change in political and economic stability in the vicinity of the Company’s 

Colombian operations, the Company may be forced to abandon or suspend their efforts. Either of such events could be harmful to the Company’s expected business prospects.

At December 31, 2010, 93% of the Company’s net oil and gas property investment and 99% of its revenue was with or derived from interests operated by Hupecol.

For 2010, 98% of our oil production from the Company’s mineral interests was sold to an international integrated oil company. The gas production is sold to U.S. natural gas 

marketing companies based on the highest bid. There were no other product sales of more than 10% to a single buyer.

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The Company reviews accounts receivable balances when circumstances indicate a balance may not be collectible. Historically, the Company has not experienced any 

uncollectible accounts receivable. Based upon the Company’s review, no allowance for uncollectible accounts was deemed necessary at December 31, 2010 and 2009, respectively.

Concentration of Credit Risk

Financial instruments that potentially subject the Company to a concentration of credit risk include cash and cash equivalents. The Company had cash deposits of $29,249,920 in 

excess of the FDIC’s current insured limit of $250,000 at December 31, 2010 for interest bearing accounts. The Company has not experienced any losses on its deposits of cash and cash 

equivalents.

Stock-Based Compensation

The Company measures the cost of employee services received in exchange for stock and stock options based on the grant date fair value of the awards under FASB ASC Topic 

718, Compensation – Stock Compensation (“ASC 718”). The Company determines the fair value of stock option grants using the Black-Scholes option pricing model. The Company 

determines the fair value of shares of nonvested stock (also commonly referred to as restricted stock) based on the last quoted price of our stock on the date of the share grant. The fair 

value determined represents the cost for the award and is recognized over the vesting period during which an employee is required to provide service in exchange for the award. As 

share-based compensation expense is recognized based on awards ultimately expected to vest, the Company reduces the expense for estimated forfeitures based on historical forfeiture 

rates. Previously recognized compensation costs may be adjusted to reflect the actual forfeiture rate for the entire award at the end of the vesting period. Excess tax benefits, as defined 

in ASC 718, if any, are recognized as an addition to paid-in capital.

Recent Accounting Developments

In January 2010, the FASB issued revised authoritative guidance that requires more robust disclosures about the different classes of assets and liabilities measured at fair value, 

the valuation techniques and inputs used, the activity in Level 3 fair value measurements, and the transfers between Levels 1, 2 and 3. This guidance is effective for interim and annual 

reporting periods beginning after December 15, 2009 (which is January 1, 2010 for the Company) except for the disclosures about purchases, sales, issuances, and settlements in the roll 

forward activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years 

(which is January 1, 2011 for the Company). Early application is encouraged. The revised guidance was adopted as of January 1, 2010. The adoption of this guidance did not have a 

material impact on the Company’s consolidated financial position, results of operations or cash flows.

No other accounting standards or interpretations issued recently are expected to a have a material impact on our consolidated financial position, operations or cash flows.

NOTE 2—RELATED PARTIES

In conjunction with the Company’s efforts to secure oil and gas prospects, financing and services, in lieu of salary or other forms of compensation, during 2005, the Company 

granted to John F. Terwilliger, Chief Executive Officer, and Orrie L. Tawes, a principal shareholder and Director, overriding royalty interests in select mineral properties of the Company. 

During 2010 and 2009, Mr. Terwilliger received royalty payments relating to those properties totaling $458,448 and $114,135, respectively, and Mr. Tawes received royalty payments 

relating to those properties totaling $458,448 and $113,532, respectively.

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NOTE 3—INCOME TAXES

The following table sets forth a reconciliation of the statutory federal income tax for the years ending December 31, 2010, 2009 and 2008.

At December 31, 2010 the Company has utilized its entire US Federal tax loss carry forward of $705,994 and its entire foreign tax credit carry forward of $1,684,745 in connection 

with the sale of interests in Hupecol Dorotea and Cabiona, LLC and Hupecol Llanos, LLC. The valuation allowance associated with the foreign tax credit carry forward has been 

reversed as well.

The tax effects of the temporary differences between financial statement income and taxable income are recognized as a deferred tax asset and liabilities. Significant components 

of the deferred tax asset and liability as of December 31, 2010 and 2009 are set out below.

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 2010 2009 2008

 

Income (loss) before income taxes $ 30,383,804 $ (1,406,854) $ 391,684

Income tax expense (benefit) computed at statutory rates $ 10,589,580 $ (478,330) $ 133,173

Permanent differences, nondeductible expenses 4,915 2,789 2,960

Current Colombian tax expense — — 5,200,306

Increase (decrease) in valuation allowance (1,111,932) (220,939) (284,561)

Change in tax rate (148,245) — —

Return to accrual items — — 99,330

Foreign tax credit — — (5,201,387)

State (net of federal benefit) 19,546 (40,926) (23,082)

Tax provision (benefit) $ 9,353,864 $ (737,406) $ (73,261)

Total Provision

Current Federal $ 3,850,927 $ — $ —

Current State 30,071 — 3,787

Deferred Federal 3,682,947 (361,737) (5,251,772)

Deferred State — (40,926) (25,582)

Foreign 1,789,919 (334,743) 5,200,306

Total provision (benefit) $ 9,353,864 $ (737,406) $ (73,261)

2010 2009

Non-Current Deferred tax assets:

Net operating loss carry forwards $ — $ 240,038

Foreign tax credit carry forwards — 1,684,745

Asset retirement obligation — 17,781

Deferred State Tax (66,505) 66,507

Stock Compensation 1,560,696 714,647

Book in excess of tax depreciation, depletion, and capitalization methods on oil and gas properties 369,878 3,579,549

Other — 315,067

Colombia Future Tax Obligations — 173,616

 

Total Non-Current Deferred tax assets 1,997,079 6,791,949

Non-Current Deferred tax liabilities:

 

Total Non-Current tax liabilities —

Valuation Allowance — (1,111,923 )

 

Net deferred tax asset $ 1,997,079 $ 5,680,026

 

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Foreign Income Taxes

The Company owns an interest in various limited liability companies that operate and have activities in Colombia, through various entities controlled by Hupecol. Additionally, 

the Company owns an interest in properties located in Colombia and operated by SK Energy and Shona Energy. Colombia’s current tax rate is 33%. Based on information provided by 

the manager of Hupecol, the Company has determined its share of the Colombia tax liability relating to the entities operated by Hupecol for 2010 will be $1,789,919. This amount has been 

accrued during the year and will be funded by withholdings from the 2010 revenue and from revenue received in 2011. The Company has determined that it has no Colombian tax liability 

relating to the operations of SK Energy or Shona Energy during 2010.

NOTE 4—STOCK BASED COMPENSATION

On August 12, 2005, the Company’s Board of Directors adopted the Houston American Energy Corp. 2005 Stock Option Plan (the “2005 Plan”). The terms of the 2005 Plan allow 

for the issuance of up to 500,000 options to purchase 500,000 shares of the Company’s common stock.

During 2008, the Company’s shareholders approved and the Company granted 55,600 shares of restricted common stock with immediate vesting to the Company’s two principal 

officers. The Company recognized compensation expense of $400,320 based upon the stock price at the grant date attributable to these grants, which were originally approved, subject 

to stockholder approval, in 2007 by the Company’s Board of Directors and then later approved by the Company’s stockholders and issued in June 2008.

In 2008, the Company’s Board of Directors adopted the Houston American Energy Corp. 2008 Equity Incentive Plan (the “2008 Plan” and, together with the 2005 Plan, the 

“Plans”). The terms of the 2008 Plan allow for the issuance of up to 2,200,000 shares of the Company’s common stock pursuant to the grant of stock options and restricted stock. 

Persons eligible to participate in the Plans are key employees, consultants and directors of the Company.

During 2008, the Company granted 3,333 options to the members of the Board of Directors and 1,050,000 options to employees. Additionally, 200,000 previously granted options 

were vested at December 31, 2008.

The options granted to the directors during 2008 vested immediately, had a ten year life and were valued on the date of the grant using the Black-Scholes option-pricing model 

with the following weighted average assumptions: risk-free interest rate 3.875%, expected life in years 5.0, expected stock volatility 73.81754%, and expected dividend yield of 0.0%. The 

Company determined the options qualify as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life. Using this model 

yielded a value of $15,113 which was charged to expense in 2008.

The options granted to employees during 2008 had a ten year life and 150,000 of the options vest ratably over three years and 900,000 of the options vest ratably over six years. 

The options were valued on the date of the grant using the Black-Scholes option-pricing model with the following weighted average assumptions: risk-free interest rate 3.875%, 

expected life in years of 6 and 6.75, respectively, expected stock volatility 73.81754%, and expected dividend yield of 0.0%. The Company determined the options qualify as ‘plain 

vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life. The total value of the options was $5,299,214. The options are being 

expensed over the vesting period. During 2010, 2009 and 2008, $994,983, $1,007,558 and $586,361, respectively, were amortized to expense as employee compensation for the options 

granted to employees during 2008.

During 2009, the Company granted 26,665 options to members of the Board of Directors and 120,000 options to employees.

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The options granted to the directors during 2009 vested immediately, had a ten year life and were valued on the date of the grant using the Black-Scholes option-pricing model 

with the following weighted average assumptions:, risk-free interest rate 3.19%, expected life of 5 years, expected stock volatility 87.625%, expected future dividend yield of 0.0%. The 

Company determined the options qualify as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life. Using this model 

yielded a value of $38,174 which was charged to expense in 2009 for the options granted to directors during 2009.

The options granted to employees during 2009 vest ratably over three years, had a ten year life and were valued on the date of the grant using the Black-Scholes option-pricing 

model with the following weighted average assumptions: risk-free interest rate 3.19%, expected life of 6 years, expected stock volatility 87.625%, and expected future dividend yield of 

0.0%. The Company determined the options qualify as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life. The total 

value of the options was $182,831. The options are being expensed over the vesting period. During 2010 and 2009, $60,943 and $34,396 was amortized to expense as employee 

compensation for the options granted to employees during 2009.

During 2010, the company granted 125,000 options to members of the Board of Directors and 150,000 options to employees.

The options granted to the directors during 2010 vested immediately, had a ten year life and were valued on the date of the grant using the Black-Scholes option-pricing model 

with the following weighted average assumptions: risk-free interest rate 2.23%, expected life of 5.7 years, expected stock volatility 87.97%, and expected future dividend yield of 0.44%. 

The Company determined the options qualify as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life. Using this 

model yielded a value of $1,177,781 which was charged to expense in 2010 for the options granted to directors during 2010. These options had a weighted average grant date fair value 

of $4.28 per share,

The options granted to employees during 2010 vest ratably over three years, had a ten year life and were valued on the date of the grant using the Black-Scholes option-pricing 

model with the following weighted average assumptions: risk-free interest rate 1.70%, expected life of 5.8 years, expected stock volatility 87.35%, and expected future dividend yield of 

0.0%. The Company determined the options qualify as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life. The total 

value of the options was $958,477. The options are being expensed over the vesting period. During 2010, $123,421 was amortized to expense as employee compensation for the options 

granted to employees during 2010. These options had a weighted average grant date fair value of $3.49 per share,

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Option activity during 2010, 2009 and 2008 is as follows:

As of December 31, 2010, 1,053,998 of the outstanding options were exercisable. The exercisable options had a weighted average exercise price of $6.18 and an intrinsic value of 

$12,554,713 as of December 31, 2010.

Unvested options at December 31, 2010 totaled 760,000, with a weighted average grant date fair value and exercise price per share of $4.97 and $7.02, respectively, an amortization 

period of 3.1 years and a weighted average remaining life of 7.89 years.

As of December 31, 2010, total unrecognized stock-based compensation expense related to non-vested stock options was $3,625,799. As of December 31, 2010 there were 886,002 

shares of common stock available for issuance pursuant to future stock or option grants under the Plans.

The following table reflects share-based compensation recorded by the Company for 2010, 2009 and 2008:

NOTE 5—COMMON STOCK

2009 Registered Direct Offering

In December 2009, the Company sold to various institutional investors, in a “registered direct” offering, an aggregate of 2,890,000 shares of common stock for net proceeds after 

offering costs of $12,766,440.

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 Options

Weighted 

Average Exercise 

Price

Weighted 

Average 

Remaining 

Contractual 

Term

(in Years)

Aggregate 

Intrinsic Value

Outstanding at December 31, 2007 339,000 $ 3.12

Granted 1,053,333 $ 7.20

Exercised —

Forfeited —

 

Outstanding at December 31, 2008 1,392,333 $ 6.21

Granted 146,665 $ 2.05

Exercised —

Forfeited —

 

Outstanding at December 31, 2009 1,538,998 $ 5.81

Granted 275,000 $ 10.85

Exercised —

Forfeited —

 

Outstanding at December 31, 2010 1,813,998 $ 6.57 7.44 $ 20,889,613

 2010 2009 2008

Share-based compensation expense included in general and administrative expense $ 2,357,230 $ 1,080,128 $ 1,086,887

Earnings per share effect of share-based compensation expense $ (0.08) $ (0.04) $ (0.04)

 

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Exercise of Warrants

During 2008, the placement agent of a 2005 private placement exercised 125,000 Placement Agent Warrants, and was issued 125,000 shares for an aggregate consideration of 

$375,000.

During 2010, the remaining 190,000 warrants were exercised and the Company issued 190,000 shares for an aggregate consideration of $570,000. At December 31, 2010, no 

warrants were outstanding.

Dividends

During 2010, 2009 and 2008, we declared and paid cash dividends to our shareholders of $0.22, $0.035 and $0.04 per share, or an aggregate of $6,837,845, $980,057 and $1,122,031, 

respectively.

NOTE 6—COMMITMENTS AND CONTINGENCIES

Lease Commitment

The Company leases office facilities under an operating lease agreement that expires May 31, 2012. The lease agreement requires future payments as follows:

Total rental expense was $80,381 in 2010, $99,388 in 2009 and $74,455 in 2008. The Company does not have any capital leases or other operating lease commitments.

Standby Letter of Credit – CPO 4 Block

On November 5, 2009 JP Morgan Chase issued a Letter of Credit to Banco de Bogota S.A. for $2,037,500. Banco de Bogota then in turn issued a Stand by Letter of Credit to the 

Agency De National Hydrocarbons to guaranty Houston American Energy’s compliance and proper execution of the work obligations relating to the phase one (1) work program of the 

CPO-4 block for Houston American Energy’s 25% interest in the Block. Per the Standby Letter of Credit issued between JP Morgan Chase and Banco de Bogota, Houston American 

Energy was required to keep on deposit with JP Morgan Chase $2,037,500. In addition, Houston American Energy was required by JP Morgan Chase to pay fees associated with the 

Standby Letter of Credit equal to 1.0% per year of the amount, equal to $20,375.

On December 2, 2010 JP Morgan Chase amended the Letter of Credit to Banco de Bogota S.A. to increase the total amount of the Letter of Credit to $3,056,250. Banco de Bogota 

then in turn issued an amended Stand by Letter of Credit to the Agency de National Hydrocarbons to guaranty Houston American Energy’s compliance and proper execution of the 

work obligations relating to the phase one (1) work program for the CPO-4 block for Houston American Energy’s 37.5% interest in the Block. Per the amended Standby Letter of Credit 

issued between JP Morgan Chase and Banco de Bogota, the date of expiration was extended until January 18, 2013 and Houston American Energy is required to keep on deposit with JP 

Morgan Chase $3,056,250. This increase in deposits was related to Houston American Energy increasing its interest in the CPO 4 block from 25.0% to 37.5%. All other terms and 

conditions of the Letter of Credit remained unchanged. Houston American Energy paid JP Morgan fees associated with the Standby Letter of Credit equal to 1.0% per year of the 

amount, equal to $32,070. The deposit with JP Morgan Chase is classified as Restricted cash – letter of credit in the accompanying balance sheet.

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Year Amount

2011 84,315

2012 38,899

Thereafter —

Total $ 123,124

 

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Legal Contingencies

The Company is subject to legal proceedings, claims and liabilities that arise in the ordinary course of its business. The Company accrues for losses associated with legal claims 

when such losses are probable and can be reasonably estimated. These accruals are adjusted as further information develops or circumstances change. The Company is currently not a 

party to any litigation.

Environmental Contingencies

The Company’s oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the 

environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, 

quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain 

lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and 

regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief. Changes 

in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements 

could require the Company to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on its results of operations, competitive position 

or financial condition as well as the industry in general. Under these environmental laws and regulations, the Company could be held strictly liable for the removal or remediation of 

previously released materials or property contamination regardless of whether the Company was responsible for the release or if its operations were standard in the industry at the time 

they were performed. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental 

risks.

Development Commitments

During the ordinary course of oil and gas prospect development, the Company commits to a proportionate share for the cost of acquiring mineral interests, drilling exploratory or 

development wells and acquiring seismic and geological information.

Employment Arrangements

The Company has one employment agreement with its Senior Vice President of Exploration, Ken Jeffers. Under the agreement, Mr. Jeffers receives a base salary of $240,000 annually and 

is entitled to discretionary bonuses and other benefits consistent with those available to members of senior management. The Company has no other employment agreements.

NOTE 7—NOTES RECEIVABLE

Yazoo DIP Financing

On February 4, 2009, the Company entered into a letter agreement (the “Letter Agreement”) with Yazoo Pipeline Co., L.P., Sterling Exploration & Production Co., L.L.C., and 

Matagorda Operating Company (together, the “Debtors”), pursuant to which the Company 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, the Company advanced a total of $115,724 to the Debtors. Advances incurred interest at 10% per annum and were to be repaid 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 the Company.

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Pursuant to its rights under the Letter Agreement, after conducting due diligence with respect to the Debtors, the Company elected 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 the Company relative to the DIP Financing.

West Klondike Advances

During 2009, the Company advanced funds towards the West Klondike prospect in Louisiana, but subsequently elected not to proceed with the project. On December 30, 2009, 

the operator of the West Klondike prospect delivered to the Company a promissory note in the amount of $125,000 representing the obligation of the operator to refund the amount 

advanced with respect to the prospect. The note was repaid in full during 2010.

NOTE 8—OIL AND GAS ACQUISITIONS

Domestic Leases

During 2009, the Company acquired interests in four 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 its interest in the Profit and North Profit Island prospects, the Company sold down part of its interest in the Profit Island 

prospect. The Company still retains an interest in both of the prospects. See “Note 9 – Sale of Oil and Gas Properties – Sale of Domestic Leasehold Interests.”

During 2009, the Company acquired (1) a 2.5% working interest in over 4,500 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, the Company was 

carried to the completion point on the first well. Subsequent to purchasing its interests in the Karnes County Leases and AMI, during the year ended December 31, 2010, the Company 

sold its entire interest in the Karnes County Leases and AMI. See “Note 9 – Sale of Oil and Gas Properties – Sale of Domestic Leasehold Interests.”

Colombian Leases

Serrania Contract Farmout

During 2009, the Company entered into a farmout agreement with Shona Energy Limited pursuant to which the Company will pay 25.0% of designated Phase 1 geological and 

seismic costs in return for a 12.5% interest in the Serrania Contract for Exploration and Production covering the approximately 110,769 acre Serrania Block in Colombia.

Los Picachos TEA

During 2009, the Company elected to participate at its percentage interest (12.5%) in the Los Picachos Technical Evaluation Agreement (the “TEA”).

The TEA was entered into by and between the Colombian National Hydrocarbons Agency (the “ANH”) and Hupecol Operating Co. LLC (“Hupecol”) 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, the Company agreed to pay its proportionate share, or 12.5%, of the acquisition costs and costs for the minimum work program 

contained in the TEA.

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CPO 4 Farmout

During 2009, the Company announced the approval by the ANH of a Farmout Agreement and Joint Operating Agreement (the “JOA”) with SK Energy Co. LTD., a Korean 

multinational conglomerate (“SK”), relating to the CPO 4 Contract for Exploration and Production covering the 345,452 net acre CPO 4 Block located in the Western Llanos Basin in the 

Republic of Colombia.

Under the JOA, effective retroactive to May 31, 2009, SK will act as operator of the CPO 4 Block and the Company 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 the Company will receive a 25.0% interest in the CPO 4 

Block. The Company’s share of the past costs related to its initial 25.0% farm in was $194,584. During 2010, the Company entered into a separate Farmout Agreement with SK pursuant 

to which SK agreed to assign to the Company an additional 12.5% interest in the CPO 4 Block, increasing the Company’s current interest in the CPO 4 Block from 25% to 37.5%.

Under the terms of the Farmout Agreement, the Company will be responsible for paying its proportionate interest in all future development and operating costs (“Ongoing 

Costs”). In addition to payment of its proportionate interest in Ongoing Costs, the Company will be responsible for reimbursement to SK, or payment, of (i) 12.5% of certain defined past 

costs relating to development of the CPO 4 Block (the “Past Costs”), and (ii) 25% of seismic acquisition costs incurred with respect to the Phase One cost of CPO 4 Block between June 

18, 2009 and June 17, 2012 (the “Seismic Acquisition Costs”). The assignment of the additional interest in the CPO 4 Block was conditioned upon the approval by the ANH and the 

Republic of Korea by July 31, 2011 and payment of the Company’s proportionate interest in Past Costs. During 2010 the Company received, and paid, an invoice for $3,939,003 for its 

share of the Past Costs. In December 2010 the Company received Resolution 578 from the ANH approving our additional 12.5% interest in Block CPO 4 along with the assignment from 

SK bringing our total interest to 37.5% in the Block.

Pursuant to the terms of, and in conjunction with, the Farmout Agreement and the JOA, the Company entered into a separate agreement with Gulf United Energy, Inc. (“Gulf 

United”) whereby the Company waived its right of first refusal under the JOA for the specific purpose of permitting Gulf United to acquire a 12.5% interest in the CPO 4 Block. Under the 

agreement with Gulf United, as a condition of the Company’s agreement to waive its preferential rights, Gulf United agreed to pay to the Company, not later than 30 days following ANH 

approval, (i) the Company’s 12.5% share of Past Costs incurred through July 31, 2010, and (ii) the Company’s 25% share of Seismic Acquisition Costs incurred through July 31, 2010. 

Upon Gulf United receiving ANH approval, it will reimburse us for the $3,939,003 invoiced by SK Energy for Past Costs; plus any additional cost accrued under the terms of the Farmout 

Agreement. At December 31, 2010, the Company has recorded as accounts receivable – other the amount due from Gulf United of $3,939,003. As of December 31, 2010 and through the 

date of this filing, Gulf United had not yet received ANH approval.

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 was modified in 2010 to allow 3-D data to be shot in place of 

the initial 2-D requirement. The Phase 1 seismic acquisition was completed during 2010 and the entire Phase 1 Work Program is estimated to be completed by December of 2011.

For 2011, SK Energy has advised us that they plan to focus on the drilling of three wells on CPO 4. Our budgeted expenditures on the CPO 4 Block for 2011 are approximately 

$20.0 million.

Macaya TEA

During 2010, the Company elected to participate for its percentage interest (12.5%) in the Macaya Technical Evaluation Agreement (the “Macaya TEA”).

The Macaya TEA was entered into by and between the ANH and Hupecol, and encompasses a 195,171 acre region located to the southeast 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.

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As a result of the election to participate, the Company agreed to pay its proportionate share, or 12.5%, of the acquisition costs and costs for the minimum work program 

contained in the Macaya TEA.

LLA 62 Block

During 2010, the Company elected to participate for its percentage interest (1.6%) in the LLA 62 Block in Colombia (the “LLA 62 Block”).

The LLA 62 Block was awarded to Hupecol by the ANH during 2010. The LLA 62 Block is adjacent to the La Cuerva Block operated by Hupecol. The award of the LLA 62 Block 

includes a Phase I commitment to shoot 60 square kilometers of 3D seismic on the block.

As a result of the election to participate the Company agreed to pay its proportionate share (1.6%) of all costs of exploiting the block, except the 3D seismic costs, where the 

Company agreed to pay two times its proportional cost.

NOTE 9—SALE OF OIL AND GAS PROPERTIES

Sale of Caracara Assets – 2008

In June 2008, the Company, through Hupecol Caracara LLC as owner/operator under the Caracara Association Contract, sold all of its interest in the Caracara Association 

Contract and related assets for a total cash consideration of $11,917,418. At December 31, 2007, the estimated proved reserves associated with these assets totaled 787,742 barrels of oil, 

which represented 60.37% of the Company’s estimated proved oil and natural gas reserves. Sales of oil and gas properties under the full cost method of accounting are accounted for as 

adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and reserves. Since the sale of 

these oil and gas properties would significantly alter the relationship, the Company recognized a gain on the sale of $7,615,236 during the year ended December 31, 2008, computed as 

follows:

The carrying value of the properties sold was computed by allocating total capitalized costs within the non-U.S. full cost pool between properties sold and properties retained 

based upon the ratio of proved reserves sold and those proved reserves retained to total estimated proved reserves prior to the sale.

The following table presents pro forma data that reflects revenue, income from continuing operations, net income and income per share for 2008 as if the Caracara transaction had 

occurred at the beginning of the period and excludes the related gain on sale.

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Proceeds from the sale $ 11,917,418

Add: Transfer of asset retirement and other obligations 46,633

Less: Transaction costs (370,908 )

Carrying value of oil and gas properties (3,977,907 )

Carrying value of other assets —

Net gain on sale $ 7,615,236

2008

 

Oil and gas revenue $ 7,616,910

Loss from operations (9,748,235 )

Net income (loss) $ (4,436,584)

Basic loss per share $ (0.16)

Diluted loss per share $ (0.16)

 

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Pursuant to the terms of the sale of the Caracara assets, on the closing date of the sale, a portion of the purchase price was deposited in escrow to settle post-closing 

adjustments under the purchase and sale agreement. The Company’s proportionate interest in the escrow deposit totaled $1,673,551, and was recorded as Escrow receivable. On June 

17, 2009, $1,158,613 of the funds deposited in escrow was released to the Company based on post-closing adjustments. At December 31, 2009, the balance of the funds held in escrow, 

including $514,938 representing the Company’s proportionate interest in the escrow deposit, continued to be held in escrow pending resolution of disputes among Hupecol, the 

purchaser of the Caracara assets and Ecopetrol.

As of December 31, 2010, the balance held in escrow for the sale of the Caracara assets was $267,451. These funds continue to be held pending resolution of disputes among 

Hupecol, the purchaser of the Caracara assets and Ecopetrol.

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

Sale of Unproven Domestic Leasehold Interests

During 2009, the Company received $353,896 from the sale of part of its interest in the Profit Island prospect. The proceeds received were recorded as a reduction of oil and gas 

properties. The Company still retains an interest in both of the prospects. See “Note 8 – Oil and Gas Acquisitions – Domestic Leases.”

During 2010, the Company sold its 2.5% Working Interest and our 1.25% of 8/8’s Overriding Royalty Interest in 6,000 + gross acres in Karnes County, Texas and our right to a 

1.25% ORRI in an AMI covering approximately 50,000 gross acres in Karnes County, Texas for approximately $4.1 million in cash, less customary closing costs. The Company recorded 

a reduction of oil and gas properties of $2,302,299 and recognized a gain on sale of $1,762,066.

Sale of Interest in Hupecol Dorotea and Cabiona, LLC and Hupecol Llanos, LLC

In December 2010, Hupecol Dorotea & Cabiona Holdings, LLC (“Hupecol D&C Holdings”) and Hupecol Llanos Holdings, LLC (“Hupecol Llanos Holdings”) sold all of their 

interests in Hupecol Dorotea and Cabiona, LLC (“HDC, LLC”) and Hupecol Llanos, LLC (“HL, LLC”). The Company owns 12.5% interests in each of Hupecol D&C Holdings and 

Hupecol Llanos Holdings and, in turn, indirect interests in each of HDC, LLC and HL, LLC, which companies hold interests in the Dorotea, Cabiona, Leona and Las Garzas blocks and 

related assets in Colombia.

 HDC, LLC sold for $200 million and HL, LLC sold for $81 million, each subject to certain closing adjustments based on operations between the June 1, 2010 effective date and the 

closing date. Fifteen percent of the sales price of each of HDC, LLC and HL, LLC will be held in escrow to fund potential claims arising from the sale, with escrowed amounts to be 

released over a three year period based on amounts remaining in escrow after any claims. In addition to the fifteen percent escrowed, Hupecol withheld 5% of the proceeds in escrow for 

any contingencies that may arise, and it is expected that the Company will receive the 5% withheld by Hupecol in 2011. Pursuant to its 12.5% ownership interest in each of Hupecol 

D&C Holdings and Hupecol Llanos Holdings, the Company received 12.5% in the net sale proceeds after deduction of commissions and transaction expenses from each sale and 

subject to the escrow hold back. Following completion of the sale of HDC, LLC and HL, LLC, the Company had no continuing interest in the Dorotea, Cabiona, Leona and Las Garzas 

blocks.

At December 31, 2009, the Company’s estimated proved reserves associated with the Dorotea, Cabiona, Leona and Las Garzas blocks totaled 1,178,576 barrels of oil, which 

represented 96.9% of the Company’s estimated proved oil and natural gas reserves. Sales of oil and gas properties under the full cost method of accounting are accounted for as 

adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and reserves. Since the sale of 

these oil and gas properties would significantly alter the relationship, the Company recognized a gain on the sale of $25,397,048 during the year ended December 31, 2010, computed as 

follows:

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Because the Company determined there were substantial economic differences between the properties retained and those sold, the carrying value of the properties sold was 

computed by allocating total capitalized costs within the non-U.S. full cost pool between properties sold and properties retained based upon the relative fair values of the properties.

The following table presents pro forma data that reflects revenue, income from continuing operations, net income and income per share for 2010, 2009, and 2008 as if the HDC, 

LLC and HL, LLC transaction had occurred at the beginning of the period and excludes the related gain on sale.

Pursuant to the terms of the sales of HDL, LLC and HL, LLC, on the closing date of the sale, a portion of the purchase price was deposited in escrow to settle post-closing 

adjustments under the purchase and sale agreement. The Company’s proportionate interest in the escrow deposit totaled $7,069,810, and was recorded as Escrow receivable. As of 

December 31, 2010, the Company is not aware of any claims by the Purchaser that would reduce the escrow receivable.

NOTE 10—GEOGRAPHICAL INFORMATION

The Company currently has operations in two geographical areas, the United States and Colombia. Revenues for the twelve months ended December 31, 2010, 2009 and 2008 and 

Long Lived Assets as of December 31, 2010, 2009 and 2008 attributable to each geographical area are presented below:

NOTE 11—SUBSEQUENT EVENTS

On February 28, 2011 the Company issued to Edwin Broun III, a previous member of the Board of Directors, 31,901 shares of the Company’s common stock via a cashless exercise 

of the options he earned while serving on the Board of Directors.

The Company evaluated subsequent events through March 15, 2011, which is the date the financial statements were issued and there were no other significant events to report.

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Proceeds from the sale $ 34,503,835

Add: Transfer of asset retirement and other obligations 321,798

Less: Transaction costs (5,439,349)

Carrying value of oil and gas properties, net (3,989,236)

 

Net gain on sale $ 25,397,048

2010 2009 2008

Pro-Forma Information

Oil and gas revenue $ 628,595 $ 179,662 $ 410,471

Income (loss) from operations (3,213,162) (4,769,339) (4,092,398)

Net income (loss) $ (10,594,649) $ (1,761,062) $ 1,476,543

 

Basic income (loss) per share $ (0.34) $ (0.06) $ 0.05

 

Diluted income (loss) per share $ (0.34) $ (0.06) $ 0.05

 Year Ended December 31, 2010 Year Ended December 31, 2009 Year Ended December 31, 2008

 Revenues

Long Lived 

Assets, Net Revenues

Long Lived 

Assets, Net Revenues

Long Lived 

Assets, Net

North America $ 206,591 $ 737,066 $ 171,922 $ 2,730,667 $ 410,471 $ 1,708,617

South America 19,302,303 9,954,355 7,944,353 8,625,588 10,211,579 3,554,514

Total $ 19,508,894 $ 10,691,421 $ 8,116,275 $ 11,356,255 $ 10,622,050 $ 5,263,131

 

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NOTE 12—SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

This footnote provides unaudited information required by FASB ASC Topic 932, Extractive Activities—Oil and Gas.

Geographical Data

The following table shows the Company’s oil and gas revenues and lease operating expenses, which excludes the joint venture expenses incurred in South America, by 

geographic area:

Capital Costs

Capitalized costs and accumulated depletion relating to the Company’s oil and gas producing activities as of December 31, 2010, all of which are onshore properties located in the 

United States and Colombia, South America are summarized below:

Amortization Rate

The amortization rate per unit based on barrel equivalents was $10.21 for the United States and $12.25 for South America.

Acquisition, Exploration and Development Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities as of December 31, 2010, 2009 and 2008 are summarized below:

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 2010 2009 2008

Revenues

North America $ 206,591 $ 171,922 $ 410,471

South America 19,302,303 7,944,353 10,211,579

 $ 19,508,894 $ 8,116,275 $ 10,622,050

 

Production Cost

North America $ 54,214 $ 80,717 $ 134,527

South America 8,088,230 4,665,578 3,232,213

 $ 8,142,444 $ 4,746,295 $ 3,336,740

 United States South America Total

Unproved properties not being amortized $ 611,348 $ 9,647,632 $ 10,258,980

 

Proved properties being amortized 851,355 980,383 1,831,738

 

Accumulated depreciation, depletion, amortization and valuation allowances (788,312) (673,660) (1,461,972)

 

Net capitalized costs $ 674,391 $ 9,954,355 $ 10,628,746

 2010

 United States South America

Property acquisition costs:

Proved $ — $ —

Unproved 312,921 —

Exploration costs — 7,017,816

Development costs — 1,331,779

 

Total costs incurred $ 312,921 $ 8,349,595

 

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Reserve Information and Related Standardized Measure of Discounted Future Net Cash Flows

In December 2009, the Company adopted revised oil and gas reserve estimation and disclosure requirements. The primary impact of the new disclosures is to conform the 

definition of proved reserves with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The accounting standards update revised the 

definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period before the end of the year rather than the year-end price, 

must be used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and 

changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technology to estimate proved oil 

and gas reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. The unaudited supplemental information on oil and gas 

exploration and production activities for 2010 and 2009 has been presented in accordance with the new reserve estimation and disclosure rules, which may not be applied 

retrospectively. The 2008 data is presented in accordance with FASB oil and gas disclosure requirements effective during those periods. Disclosures by geographic area include the 

United States and South America, which consists of our interests in Colombia. The supplemental unaudited presentation of proved reserve quantities and related standardized measure 

of discounted future net cash flows provides estimates only and does not purport to reflect realizable values or fair market values of the Company’s reserves. Volumes reported for 

proved reserves are based on reasonable estimates. These estimates are consistent with current knowledge of the characteristics and production history of the reserves. The Company 

emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, 

significant changes to these estimates can be expected as future information becomes available.

Proved reserves are those estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with 

reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be 

recovered through existing wells, equipment, and operating methods.

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 2009

 United States South America

Property acquisition costs:

Proved $ 106,875 $ —

Unproved 1,010,941 2,560,808

Exploration costs 335,070 2,505,497

Development — 1,754,354

 

Total costs incurred $ 1,452,886 $ 6,820,659

 2008

 United States South America

Property acquisition costs:

Proved $ — $ —

Unproved 230,089

Exploration costs 698,738 5,520,901

Development costs — 4,391,625

 

Total costs incurred $ 928,827 $ 9,912,526

 

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The reserve estimates set forth below were prepared by Lonquist & Co., LLC (Lonquist), utilizing reserve definitions and pricing requirements prescribed by the SEC. Lonquist is 

an independent professional engineering firm specializing in the technical and financial evaluation of oil and gas assets. Lonquist’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 and its employees have no 

interest in the Company, and were objective in determining the results of the Company’s reserves. Lonquist used a combination of production performance, offset analogies, seismic 

data and their interpretation, subsurface geologic data and core data, along with estimated future operating and development costs as provided by the Company and based upon 

historical costs adjusted for known future changes in operations or development plans, to estimate our reserves. The Company does not operate any of its oil and gas properties.

Total estimated proved developed and undeveloped reserves by product type and the changes therein are set forth below for the years indicated.

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 United States South America Total

 Gas (mcf) Oil (bbls) Gas (mcf) Oil (bbls) Gas (mcf) Oil (bbls)

Total proved reserves

Balance December 31, 2007 135,649 4,012 — 1,281,227 135,649 1,285,239

Extensions and discoveries — — — 211,310 — 211,310

Revisions of prior estimates (92,127 ) (560 ) — (401,350 ) (92,127 ) (401,910 )

Sales of minerals in place — — — (757,605 ) — (757,605 )

Production (24,748 ) (1,511 ) — (122,107 ) (24,748 ) (123,618 )

 

Balance December 31, 2008 18,774 1,941 — 211,475 18,774 213,416

 

Extensions and discoveries 15,703 44 — 1,104,041 15,703 1,104,085

Purchase of minerals in place 42,685 1,394 — — 42,685 1,394

Revisions of prior estimates 8,792 1,100 — 16,493 8,792 17,593

Production (15,761 ) (1,581 ) — (129,782 ) (15,761 ) (131,363 )

 

Balance December 31, 2009 70,173 2,898 — 1,202,227 70,193 1,205,125

 

Extensions and discoveries — — — 129,197 — 129,197

Purchase of minerals in place — — — — —

Revisions of prior estimates 29,845 4,652 — 26,217 29,845 30,869

Sales of minerals in place — — — (1,036,252) — (1,036,252)

Production (17,798) (1,540) — (260,239) (17,798) (261,779)

 

Balance December 31, 2010 82,220 6,010 — 61,150 82,220 67,160

 

Proved developed reserves

at December 31, 2008 18,774 1,941 — 141,246 18,774 143,187

at December 31, 2009 70,193 2,898 — 307,993 70,193 310,891

at December 31, 2010 82,220 6,010 — 17,202 82,220 23,212

 

Proved undeveloped reserves

at December 31, 2008 — — — 70,229 — 70,229

at December 31, 2009 — — — 894,234 — 894,234

at December 31, 2010 — — — 43,948 — 43,948

 

69
During 2010 and 2009, the Company recorded extensions and discoveries resulting principally from its ongoing drilling operations in Colombia. As of December 31, 2010, our 

proved undeveloped (“PUD”) reserves totaled 43,948 mbbls of oil and 0 mcf of natural gas, for a total of 43,948 mboe. Positive revisions of 129,197 boe in PUD reserves were due to the 

on-going drilling program and subsequent changes in subsurface mapping. None of the PUD reserves as of December 31, 2009 were converted to proved developed producing reserves 

in 2010. All PUD locations are scheduled to be drilled or otherwise converted to proved developed reserves before the end of 2015. None of our PUD locations have been booked for 

longer than five years.

The Company experienced downward revisions in estimated proved natural gas and oil reserves in 2008. The revisions to natural gas reserves during 2008 were primarily 

attributable to a downward revision in volumes of natural gas reserves based on updated well performance from the Company’s North American properties. The revisions to oil reserves 

during 2008 were primarily attributable to downward revisions in the volumes of oil reserves based on updated well performance from the Company’s South American properties.

Sales of reserves in place during 2008 represent the June 2008 transaction whereby the Company, through Hupecol Caracara LLC as owner/operator under the Caracara 

Association Contract, sold all of its interest in the Caracara Association Contract in Colombia.

Sales of reserves in place during 2010 represent the December 2010 transaction whereby entities owned 12.5% by the Company sold entities that held all of the Company’s 

interest in the Dorotea, Cabiona, Leona and Las Garzas blocks in Colombia.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is computed using average first-day-of the-month prices for oil and gas 

during the 12 month period for 2010 and 2009, and using year-end prices for 2008, (with consideration of price changes only to the extent provided by contractual arrangements) to the 

estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved 

reserves, less estimated related future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated), and assuming continuation 

of existing economic conditions. Future income tax expenses give effect to permanent differences and tax credits but do not reflect the impact of continuing operations including 

property acquisitions and exploration. The estimated future cash flows are then discounted using a rate of ten percent a year to reflect the estimated timing of the future cash flows.

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Standard measure of discounted future net cash flows at December 31, 2010:

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 United States South America Total

Future net cash flow $ 900,040 $ 4,724,278 $ 5,624,318

Future production cost (279,710) (2,021,273) (2,300,983)

Future development cost - (636,275) (636,275)

Future income tax - (501,125) (501,125)

10% annual discount for timing of cash flow (180,710) (448,345) (629,055)

Standard measure of discounted future net cash flow relating to proved oil and gas reserves $ 439,620 $ 1,117,260 $ 1,556,880

Changes in standardized measure:

Change due to current year operations

Sales, net of production costs (152,377) (11,214,073) (11,366,450)

Change due to revisions in standardized variables:

Income taxes - (392,431) (392,431)

Accretion of discount 32,397 1,549,659 1,582,056

Net change in sales and transfer price, net of production costs 224,620 22,861,606 23,086,226

Previously estimated development costs incurred during the period - 1,336,231 1,336,231

Changes in estimated future developments costs - 10,235,689 10,235,689

Revision and others 14,680 1,877,525 1,892,205

Discoveries - 728,856 728,856

Sales of reserves in place - (29,750,509) (29,750,509)

Changes in production rates and other (3,691) (10,614,782) (10,618,473)

Net (13,266,600)

Beginning of year 14,823,480

End of year $ 1,556,880

 

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Standard measure of discounted future net cash flows at December 31, 2009

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United States South America Total

Future net cash flow $ 455,522 $ 66,715,086 $ 67,170,608

Future production cost (87,192 ) (36,712,770 ) (36,799,962 )

Future development cost (11,571,920 ) (11,571,920 )

Future income tax — (1,560,871 ) (1,560,871 )

10% annual discount for timing of cash flow (44,363 ) (2,370,012 ) (2,414,375 )

Standard measure of discounted future net cash flow relating to proved oil and gas reserves $ 323,967 $ 14,499,513 $ 14,823,480

Changes in standardized measure:

Change due to current year operations

Sales, net of production costs (91,205 ) (3,278,775 ) (3,369,980 )

Change due to revisions in standardized variables:

Income taxes — (1,312,411 ) (1,312,411 )

Accretion of discount 10,361 351,301 361,662

Net change in sales and transfer price, net of production costs (21,603 ) 3,899,640 3,878,036

Previously estimated development costs incurred during the period 335,070 4,259,860 4,594,930

Changes in estimated future developments costs (335,070 ) (3,526,367 ) (3,861,437 )

Revision and others 70,166 289,606 359,773

Discoveries 51,631 13,602,240 13,653,871

Purchase of reserves in place 189,626 — 189,626

Changes in production rates and other 35,510 (2,857,593 ) (2,822,083 )

Net 11,671,988

Beginning of year 3,151,493

End of year $ 14,823,480

 

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Standard measure of discounted future net cash flows at December 31, 2008

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United States South America Total

Future net cash flow $ 176,794 $ 8,989,877 $ 9,166,671

Future production cost (73,188 ) (4,743,369 ) (4,816,557 )

Future development cost — (733,493 ) (733,493 )

Future income tax — — —

10% annual discount for timing of cash flow (24,125 ) (441,003 ) (465,128 )

Standard measure of discounted future net cash flow relating to proved oil and gas reserves $ 79,481 $ 3,072,012 $ 3,151,493

Changes in standardized measure:

Change due to current year operations Sales, net of production costs (275,944 ) (6,979,366 ) (7,255,310 )

Change due to revisions in standardized variables:

Income taxes — 13,727,868 13,727,868

Accretion of discount 61,004 6,949,779 7,010,783

Net change in sales and transfer price, net of production costs (93,355 ) (11,454,408 ) (11,547,736 )

Previously estimated development costs incurred during the period — 1,830,066 1,830,066

Changes in estimated future developments costs — (641,440 ) (641,440 )

Revision and others (614,417 ) (4,423,721 ) (5,038,138 )

Discoveries — 733,190 733,190

Sales of reserves in place (41,074,257 ) (41,074,257 )

Changes in production rates and other 392,157 (10,937,166 ) (10,545,009 )

Net (52,800,010 )

Beginning of year 55,951,503

End of year $ 3,151,493

 

73
NOTE 13—SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

74

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 Three Months Ended

 March 31, June 30, Sept. 30, Dec. 31,

2010

Operating revenue $ 4,241,395 $ 7,629,274 $ 5,354,499 $ 2,283,726

Income from operations 979,003 876,888 1,411,332 27,043,334

Net income 808,716 990,134 1,171,642 18,059,448

 

Earnings common per share $ 0.03 $ 0.03 $ 0.04 $ 0.58

Earnings common per share assuming dilution 0.03 0.03 0.04 0.56

 

2009

Operating revenue $ 445,142 $ 1,134,118 $ 2,403,996 $ 4,133,019

Income (loss ) from operations (1,481,351) (576,188) 133,242 452,561

Net income (loss) (1,478,320) 112,107 428,578 268,187

 

Earnings (loss) common per share $ (0.05) $ 0.00 $ 0.02 $ 0.01

Earnings (loss) common per share assuming dilution (0.05) 0.00 0.02 0.01

 

2008

Operating revenue $ 2,937,134 $ 3,328,951 $ 2,350,782 $ 2,005,183

Income (loss ) from operations 1,350,211 7,614,307 803,108 (9,671,317)

Net income (loss) 871,721 3,199,802 798,832 (4,405,410)

 

Earnings (loss) common per share $ 0.03 $ 0.11 $ 0.03 $ (0.15)

Earnings (loss) common per share assuming dilution 0.03 0.11 0.03 (0.15)
Exhibit 10.6

EMPLOYMENT AGREEMENT

THIS EMPLOYMENT AGREEMENT (this “Agreement”) is made as of August 13, 2010, by and between HOUSTON AMERICAN ENERGY CORP, a Delaware corporation (the 

“Company”), and KENNETH JEFFERS (the “Executive”) (each a “Party” and, collectively, the “Parties”). Unless otherwise indicated, capitalized terms are defined in Section 0.

The Parties hereto hereby agree as follows:

EMPLOYMENT TERMS

Employment. The Company shall employ the Executive, and the Executive hereby accepts employment with the Company, upon the terms and conditions set forth in this 

Agreement for the period beginning on the date hereof and ending as provided in Section 0 hereof (the “Employment Period”).

Position and Duties.

Generally. During the Employment Period, the Executive will be an employee of the Company and will serve as the Senior Vice President of Exploration of the 

Company. In such capacity, the Executive shall render such management and executive and managerial services to the Company and its Subsidiaries as are commensurate with the 

customary duties, responsibilities and authority of such offices, subject to the power of the Board of Directors of the Company (the “Board”). The Executive shall also perform such 

other services on behalf of the Company as the Board may reasonably direct from time to time.

Duties and Responsibilities. The Executive shall report to the Board and shall devote his best efforts and his full business time and attention to the business and 

affairs of the Company and its Subsidiaries. The Executive shall perform his duties and responsibilities to the best of his abilities in a diligent, trustworthy, businesslike and efficient 

manner. The Executive shall not engage in any other business activities which could reasonably be expected to conflict with the Executive’s duties, responsibilities and obligations 

hereunder. Except in connection with charitable or civic endeavors, the Executive will not serve as a member of the board of directors of any Person, other than the Company or any of 

its Subsidiaries, without the prior approval of the Board. The Executive shall also comply with all policies, rules and regulations of the Company as well as all reasonable directives and 

instructions from the Board. During the Employment Period, the Executive shall bring to the Company all investment or business opportunities relating to the Business of which the 

Executive becomes aware and which are, or may be, within the scope and investment objectives related to the business of the Company or any of its Subsidiaries, which would or may 

be beneficial to the business of the Company or any of its Subsidiaries, or are otherwise competitive with the business of the Company or any of its Subsidiaries. The Company shall 

have the right to purchase in the Executive’s name a “key man” life insurance policy naming the Company and any of its Subsidiaries as the sole beneficiary thereunder and Executive 

shall cooperate with the Company in obtaining such insurance if the Company elects to purchase such insurance.

Compensation.

Salary. Commencing August 13, 2010 and continuing through the Employment Period, the Executive the Company shall pay to the Executive a base salary in the 

amount of $240,000.00 per annum (the “Salary”); provided, however, that, the Board may, at its sole discretion, increase, but not decrease, the Salary. The Salary will be payable by the 

Company in regular installments in accordance with the Company’s general payroll practices and shall be subject to customary withholding for income tax, social security and other 

such taxes.

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1
Discretionary Bonus. In addition to the Salary, the Executive will be eligible to receive a discretionary annual cash bonus (the “Bonus”) from the Company for each 

fiscal year of the Company and its Subsidiaries commencing with the fiscal year ended December 31, 2010 (each, a “Fiscal Year”), payable to the Executive (so long as the Executive is 

employed by the Company on the last day of such Fiscal Year) within thirty (30) days after the Company’s receipt of audited financial statements for such Fiscal Year. Any Bonus will 

be subject to the review and sole discretion of the Board.

Vacation. The Executive shall be entitled to such amount of vacation time each year, as provided under the Company’s prevailing policy, as such policy may be in 

effect from time to time, and consistent with that provided to other senior officers of the Company.

Additional Benefits. During the Employment Period, the Executive shall be entitled to participate in any employee welfare and health benefit plans provided to other 

senior officers of the Company, including, but not limited to, life insurance, health and medical, dental, and disability plans, and other employee benefit plans, including but not limited 

to qualified pension plans and employee stock option plans, which may be established by the Company from time to time for the benefit of other Company employees (collectively 

“Benefits”). Executive shall be required to comply with the conditions attendant to coverage by such plans and shall comply with and be entitled to benefits only in accordance with the 

terms and conditions of such plans as they may be amended from time to time. Nothing herein shall be construed as requiring the Company to establish or continue any particular 

benefit plan in discharge of its obligations under this Agreement.

Expenses. The Company shall reimburse the Executive for all reasonable expenses incurred by him for the benefit of the Company in the course of performing his 

duties under this Agreement that are consistent with the Company’s policies in effect at that time with respect to travel, entertainment and other business expenses; provided that: (i) 

such expenditures are of a nature qualifying them as proper deductions on the federal and state income tax returns of the Company; (ii) the Executive furnishes to the Company 

adequate records and other documentary evidence required by federal and state statutes and regulations issued by the appropriate taxing authorities for the substantiation of each such 

expenditure as an income tax deduction; and (iii) such expenditures otherwise comply with the Company’s requirements with respect to reporting and documentation of such 

reimbursable expenses.

Stock Option Grant. The Company shall, on the commencement of employment, issue to the Executive a stock option to purchase 150,000 shares of common stock on 

the terms set forth in the Stock Option Agreement attached hereto as Exhibit A.

Applicable Withholdings. The Salary, Bonus, Benefits and any other compensation will be subject to all withholdings and deductions required by law and will be 

payable in accordance with the Company’s normal periodic payroll practices.

Term and Termination.

Duration. The Employment Period shall commence on the date of this Agreement and shall continue until the first to occur of: (i) the Executive’s resignation for any 

reason, (ii) the Executive’s death or Disability, or (iii) the third (3rd) anniversary of the date of this Agreement (at such third anniversary or the end of any applicable extension, the 

“Expiration”); provided that the Employment Period shall be extended for additional one (1) year periods if the Company has not delivered to the Executive, at least one (1) month prior 

to the Expiration (if the Executive’s employment with the Company has not terminated prior to such date), a written notice (the “Nonrenewal Notice”) that the Company does not intend 

to extend the Employment Period. If the Company indicates pursuant to the Nonrenewal Notice that it does not intend to extend the Employment Period, the delivery of the Nonrenewal 

Notice and the expression of such intent and the subsequent termination of the Executive’s employment shall not constitute a termination by the Company without Cause.

Termination for Cause The Executive may be terminated at any time for “Cause” by written notice to the Executive, setting forth in reasonable detail the nature of the 

Cause and, in such event, the Company shall be released from any and all further obligations under this Agreement, except that the Company shall be obligated to pay the Executive, or 

the Executive’s heirs and assigns, his Salary and Benefits, and reimbursable expenses owing to the Executive through the date of such termination.

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2
Voluntary Termination. The Executive may voluntarily terminate his employment with the Company upon 30 days prior written notice. In such event, the Company 

shall be released from any and all further obligations under this Agreement, except that, so long as the Executive continues to perform his duties in accordance with this Agreement, the 

Company shall be obligated to pay the Executive the Salary, Benefits and reimbursable expenses owing to the Executive through the date of such termination (such period not to exceed 

30 days from the date of notice).

Termination due to Death or Disability. This Agreement shall terminate upon the death of the Executive, and the Executive may be terminated by reason of “Disability” 

and, in such event, the Company shall be released from any and all further obligations under this Agreement, except that the Company shall be obligated to pay the Executive, or the 

Executive’s heirs or estate, his Salary, Benefits, including accrued vacation, and reimbursable expenses owing to the Executive through the date of such termination.

Severance Upon Termination Without Cause. In the event of termination of employment by the Company without Cause, the Company will continue to pay the 

Executive’s base Salary and healthcare benefits until the earlier to occur of (A) the date which is 12 consecutive months after the date notice of such termination was delivered or (B) 

until the Executive finds employment with total compensation in an amount not less than the then applicable Salary, each in accordance with Company’s general salary payment 

policies. The Executive shall also be entitled to receive all reimbursable expenses, benefits or other entitlements then due and owing to the Executive as of the Termination Date.

Other Rights. Except as set forth in Section 0, all of the Executive’s rights to Benefits and Salary hereunder (if any) which accrue or become payable after the 

termination of the Employment Period shall cease upon such termination. The Company and its Subsidiaries may offset any amounts the Executive owes any of them against any 

amounts the Company owes the Executive hereunder; provided that such offset shall occur only upon the Executive’s termination of employment with the Company.

Obligation to Make Severance Payments. The Company will be obligated to make the severance payments contemplated in this Section 1.4 if the Executive has not 

breached, and only for so long as the Executive does not breach, his obligations under Sections 0, 0, 0, or 0 of this Agreement and executes and delivers to the Company an executed 

release substantially in the form attached hereto as Exhibit B.

Withholding. All amounts payable to Executive as severance hereunder shall be subject to all required withholdings by the Company (including, but not limited to, 

Section 409A of the Internal Revenue Code).

Confidential Information.

The Executive shall not disclose or use at any time, either during his employment with the Company or thereafter, any Confidential Information (as defined below) of 

which the Executive is or becomes aware, whether or not such information is developed by him, except to the extent that i) such disclosure or use is directly related to and required by 

the Executive’s performance during the Employment Period of the duties assigned to the Executive, or ii) the Executive is required by subpoena or similar process to disclose or discuss 

any Confidential Information; provided, that, in such case, the Executive shall promptly inform the Company of such event, shall cooperate with the Company and its Subsidiaries in 

attempting to obtain a protective order or to otherwise restrict such disclosure. At the Company’s expense, the Executive shall take all appropriate steps to safeguard Confidential 

Information and to protect it against disclosure, misuse, espionage, loss and theft. The Executive acknowledges that the Confidential Information obtained by him during the course of 

his employment with the Company is the property of the Company and its Subsidiaries.

The Executive understands that the Company and its Subsidiaries will receive from third parties confidential or proprietary information (“Third Party Information”) 

subject to a duty on the part of the Company and its Subsidiaries to maintain the confidentiality of such information and to use it only for certain limited purposes. During the 

Employment Period and thereafter, and without in any way limiting the provisions of Section 0i) above, the Executive shall hold Third Party Information in the strictest confidence and 

shall not disclose to anyone (other than personnel of the Company or any of its Subsidiaries who need to know such information in connection with their work for the Company and its 

Subsidiaries) or use, except in connection with his work for the Company or any of its Subsidiaries, Third Party Information unless expressly authorized by a member of the Board in 

writing.

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During the Employment Period, the Executive shall not use or disclose any confidential information or trade secrets, if any, of any former employers or any other 

Person to whom the Executive has an obligation of confidentiality, and shall not bring onto the premises of the Company or any of its Subsidiaries any unpublished documents or any 

property belonging to any former employer or any other Person to whom the Executive has an obligation of confidentiality unless consented to in writing by the former employer or 

Person. The Executive shall use in the performance of his duties only information that is (i) generally known and used by Persons with training and experience comparable to the 

Executive’s and that is (x) common knowledge in the industry or (y) is otherwise legally in the public domain, (ii) otherwise provided or developed by the Company or any of its 

Subsidiaries, or (iii) in the case of materials, property or information belonging to any former employer or other Person to whom the Executive has an obligation of confidentiality, 

approved for such use in writing by such former employer or Person.

Inventions and Patents. In the event that the Executive, as part of his activities on behalf of the Company or any of its Subsidiaries, generates, authors or contributes to any 

invention, innovation, design, new development, device, product, method or process or similar or related information (whether or not patentable or reduced to practice or comprising 

Confidential Information), any copyrightable work (whether or not comprising Confidential Information) or any other form of Confidential Information relating directly or indirectly to the 

business of the Company or any of its Subsidiaries as now or hereinafter conducted (collectively, “Intellectual Property”), the Executive acknowledges that such Intellectual Property 

is the exclusive property of the Company and its Subsidiaries and hereby assigns all right, title and interest in and to such Intellectual Property to the Company and its Subsidiaries. 

Any copyrightable work prepared in whole or in part by the Executive will be deemed “a work made for hire” under Section 201(b) of the 1976 Copyright Act, and the Company and its 

Subsidiaries shall own all of the rights comprised in the copyright therein. The Executive shall promptly and fully disclose all Intellectual Property to the Company and shall cooperate 

with the Company and its Subsidiaries to protect the Company’s and its Subsidiaries’ interests in and rights to such Intellectual Property (including, without limitation, providing 

reasonable assistance in securing patent protection and copyright registrations and executing all documents as reasonably requested by the Company, whether such requests occur 

prior to or after termination of the Executive’s employment with the Company).

Delivery of Materials Upon Termination of Employment. As requested by the Company from time to time and upon the termination of the Executive’s employment with the 

Company for any reason, the Executive shall promptly deliver to the Company all copies and embodiments, in whatever form, of all Confidential Information and Intellectual Property in 

the Executive’s possession or within his control (including, but not limited to, written records, notes, photographs, manuals, notebooks, documentation, program listings, flow charts, 

magnetic media, disks, diskettes, tapes and all other materials containing any Confidential Information or Intellectual Property) irrespective of the location or form of such material and, if 

requested by the Company, shall provide the Company with written confirmation that all such materials have been delivered to the Company.

Non-Compete; Non-Solicitation.

The Executive acknowledges and agrees with the Company that the Executive’s services to the Company and its Subsidiaries are unique in nature and that the 

Company and its Subsidiaries would be irreparably damaged if the Executive were to provide similar services to any Person competing with the Company and its Subsidiaries or 

engaged in a similar business. The Executive further acknowledges that in the course of his employment with the Company he will become familiar with the Company’s and its 

Subsidiaries’ trade secrets and with other Confidential Information. During the Noncompete Period, he shall not, directly or indirectly, either for himself or for any other Person, permit 

his name to be used by or participate in any business or enterprise (including, without limitation, any division, group or franchise of a larger organization) that engages or proposes to 

engage in the Business in the Restricted Territory. For purposes of this Agreement, the term “participate in” shall include, without limitation, having any direct or indirect interest in 

any Person, whether as a sole proprietor, owner, stockholder, partner, member, joint venturer, creditor or otherwise, or rendering any direct or indirect service or assistance to any 

Person (whether as a director, officer, supervisor, employee, agent, consultant or otherwise). Nothing herein will prohibit the Executive from mere passive ownership of not more than 

two percent (2%) of the outstanding stock of any class of a publicly-held corporation whose stock is traded on a national securities exchange or in the over-the-counter market. As used 

herein, the phrase “mere passive ownership” shall include voting or otherwise granting any consents or approvals required to be obtained from such Person as an owner of stock or 

other ownership interests in any entity pursuant to the charter or other organizational documents of such entity, but shall not include, without limitation, any involvement in the day-today operations of such entity.

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During the Nonsolicitation Period, the Executive will not directly or indirectly through another Person: (i) induce or attempt to induce any Customer, supplier, licensee, 

or other business relation of the Company or any of its Subsidiaries to cease doing business or reduce its level of business with the Company or any of its Subsidiaries; (ii) induce or 

attempt to induce any employee or any individual performing services as an independent contractor of the Company or any of its Subsidiaries to terminate their employment or 

consultancy with the Company or any of its Subsidiaries; (iii) recruit, solicit or hire any employee or any individual performing services as an independent contractor of the Company or 

any of its Subsidiaries (including during the three (3) months prior to and following the termination of employment of any such employee or independent contractor with the Company 

or any of its Subsidiaries); or (iv) in any way intentionally or negligently interfere with the relationship between any such Customer, supplier, licensee, employee, independent 

contractor or business relation and the Company or any of its Subsidiaries, including, without limitation, knowingly making any negative statements or communications concerning the 

Company or any of its Subsidiaries.

Enforcement.

(a) Without limitation, the Parties agree and intend that the covenants contained in this Agreement shall be deemed to be a series of separate covenants and 

agreements, one for each and every county or political subdivision of each applicable state of the United States with respect to the Restricted Territory. It is the desire and intent of the 

Parties hereto that the provisions of this Agreement be enforced to the fullest extent permissible under the laws and public policies of each jurisdiction in which enforcement is sought. 

Accordingly, if, at the time of enforcement of Sections 0, 0, 0 or 0, a court holds that the restrictions stated herein are unreasonable under circumstances then existing, the Parties agree 

that, to the extent permitted by applicable law, the maximum period, scope or geographical area reasonable under such circumstances will be substituted for the Noncompete Period, 

Nonsolicitation Period, scope or Restricted Territory. Furthermore, such substitution will apply only with respect to the operation of such provision in the particular jurisdiction in which 

such adjudication is made.

(b) Among other matters, because the Executive’s services are unique and because the Executive has access to Confidential Information and Intellectual 

Property, the Parties agree that money damages would be an inadequate remedy for any breach of Sections 0, 0, 0 or 0. Therefore, in the event of a breach or threatened breach of 

Sections 0, 0, 0 or 0, the Company or any of its Subsidiaries or any of their respective successors or assigns may, in addition to other rights and remedies existing in their favor, apply to 

any court of competent jurisdiction for specific performance and/or injunctive or other relief in order to enforce, or prevent any violations of, the provisions hereof (without posting a 

bond or other security). In addition, in the event of an alleged breach or violation by Executive of any of Sections 0, 0, 0 or 0, the restricted periods set forth in such Sections shall be 

tolled until such breach or violation has been cured. The Parties hereby acknowledge and agree that (i) performance of the services of the Executive hereunder may occur in jurisdictions 

other than the jurisdiction whose law the Parties have agreed shall govern the construction, validity and interpretation of this Agreement, (ii) the law of the State of Texas shall govern 

construction, validity and interpretation of this Agreement to the fullest extent possible, and (iii) Sections 0, 0, 0 and 0 shall restrict the Executive only to the extent permitted by 

applicable law. The Executive expressly agrees and acknowledges that the covenants of the Executive contained in Sections 0, 0, 0 and 0 are (x) reasonably necessary for the protection 

of the Company’s interests, (y) made in consideration of (A) the terms of employment under this Agreement and other compensation provided to the Executive by the Company and its 

Subsidiaries and (B) the benefits derived or to be derived, directly or indirectly, by Executive under the Stock Option Agreement, and (z) not unduly restrictive upon the Executive.

Survival. Sections 0, 0, 0, 0 and 0 (and any defined terms related thereto) will survive and continue in full force in accordance with their terms notwithstanding any termination 

of the Employment Period.

DEFINED TERMS

Definitions. For purposes of this Agreement, the following terms will have the following meanings:

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“Affiliate” means, with respect to any Person, any Person controlling, controlled by or under common control with, such Person, including, without limitation, any 

officer, director, member, general partner, manager, employee, agent or subsidiary thereof.

“Business” means the business of the Company involving the acquisition, by lease, purchase or otherwise, of oil and gas properties or interests in oil and gas 

properties, including but not limited to working interests, royalty interests, net revenue interests, production payments or otherwise, and the exploration for, and production of, oil and 

gas from those properties.

“Cause” means, with respect to the Executive, the occurrence of one or more of the following events:

(a) Breach of any provision of this Employment Agreement by the Executive, which breach has not been cured by the Executive after having been given 30 

calendar days notice of such breach;

(b) Neglect or refusal to perform the duties assigned to the Executive under or pursuant to this Employment Agreement, which neglect or refusal has not been 

cured by the Executive after having been given 30 calendar days notice of such breach;

(c) Misconduct by Executive as an employee of the Company, including but not limited to, misappropriating funds or property of the Company, violating any 

policy of the Company including violating any policy set forth in the Company’s employee handbook or manuals; any attempt to obtain any personal profit from any transaction in 

which the Executive has an interest that is adverse to the Company or any breach of the duty of loyalty and fidelity to the Company; or any other act or omission of the Executive which 

substantially impairs the Company’s ability to conduct its ordinary business in its usual manner;

(d) Indictment for a felony or plea of guilty or nolo contendre to a felony;

(e) Acts of dishonesty or moral turpitude by the Executive that are detrimental to the Company or that cause the Company to be in violation of governmental 

regulations that subject the Company either to material sanctions by governmental authority or to material civil liability to its employees or third parties;

(f) Disclosure or use of confidential information of the Company, other than as authorized by the Company and required in the performance of Executive’s 

duties; or

(g) the Executive reports to work under the influence of alcohol or illegal drugs, the use of illegal drugs (whether or not at the workplace) or other repeated 

conduct causing the Company or any of its Subsidiaries or Affiliates public disgrace, disrepute or economic harm.

“Confidential Information” means information that is not generally known to the public and that is used, developed or obtained by the Company or any of its 

Subsidiaries in connection with their businesses, including but not limited to (i) customer lists, project or proposal lists and other related information; (ii) business development, growth 

and other strategic business plans; (iii) properties available for acquisition, financing development or sale; (iv) accounting and business methods, (v) services or products and the 

marketing of such services and products; (vi) fees, costs and pricing structures; (vii) designs; (viii) analysis; (ix) drawings, photographs and reports; (x) computer software, including 

operating systems, applications and program listings, (xi) flow charts, manuals and documentation; (xii) data bases; (xiii) inventions, devices, new developments, methods and 

processes, whether patentable or unpatentable and whether or not reduced to practice; (xiv) copyrightable works; (xv) all technology and trade secrets; (xvi) confidential terms of 

syndicated program agreements, network affiliation agreements and customer relationships; and (xvii) all similar and related information in whatever form. Confidential Information, 

however, does not include any information that has become generally available to the public through no fault of the Executive or that has been approved for release by the Company 

without restriction prior to the date the Executive proposes to disclose or use such information.

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“Customer” means, during the Nonsolicitation Period, for the Company and its Subsidiaries, any Person (a) which was a customer of the Company or any such 

Subsidiary on the Termination Date or (b) to whom there existed an outstanding bid or the issuance of an outstanding bid was contemplated by the Company or any such Subsidiary on 

the Termination Date.

“Disability” means the reasonable, good faith determination by an independent physician selected in good faith by the Board and the Executive that, due to a mental 

or physical impairment or disability, the Executive has been incapable or unable, even with reasonable accommodations, to fully perform the material duties performed by the Executive 

for the Company or its Subsidiaries immediately prior to such disability for a period of at least one hundred eighty (180) consecutive days.

“Noncompete Period” means the Employment Period and the period commencing on the Termination Date and ending on the date which is one year thereafter.

“Nonsolicitation Period” means the Employment Period and the period commencing on the Termination Date and ending on the date which is one year thereafter.

“Person” means an individual, a partnership, a corporation, a limited liability company, an association, a joint stock company, a trust, a joint venture, an 

unincorporated organization, or the United States of America any other nation, any state or other political subdivision thereof, or any entity exercising executive, legislative, judicial, 

regulatory or administrative functions of government.

“Restricted Territory” means, (a) with respect to onshore oil and gas properties and interests, any county or parish, and any adjoining county or parish, and any field 

in which the Company holds oil and gas properties or interests at the Termination Date, and (b) with respect to offshore oil and gas properties and interests, any field in which the 

Company holds oil and gas properties or interests at the Termination Date.

“Subsidiary” means, with respect to any Person, any corporation, limited liability company, partnership, association or business entity of which (a) if a corporation, a 

majority of the total voting power of shares of stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof is at 

the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person or a combination thereof, or (b) if a limited liability company, 

partnership, association or other business entity (other than a corporation), a majority of partnership or other similar ownership interest thereof is at the time owned or controlled, 

directly or indirectly, by any Person or one or more Subsidiaries of that Person or a combination thereof. For purposes hereof, a Person or Persons shall be deemed to have a majority 

ownership interest in a limited liability company, partnership, association or other business entity (other than a corporation) if such Person or Persons shall be allocated a majority of 

limited liability company, partnership, association or other business entity gains or losses or shall be or control any managing director or general partner of such limited liability 

company, partnership, association or other business entity. For purposes hereof, references to a “Subsidiary” of any Person shall be given effect only at such times that such Person 

has one or more Subsidiaries.

“Termination Date” means the date of the Executive’s cessation of employment with the Company.

Other Definitional Provisions.

For purposes of this Agreement, employment by the Company means employment by the Company or any of its Subsidiaries.

Section references contained in this Agreement are references to sections in this Agreement, unless otherwise specified. Each defined term used in this Agreement 

has a comparable meaning when used in its plural or singular form. Each gender-specific term used in this Agreement has a comparable meaning whether used in a masculine, feminine 

or gender-neutral form.

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Whenever the term “including” (whether or not that term is followed by the phrase “but not limited to” or “without limitation” or words of similar effect) is used in this 

Agreement in connection with a listing of items within a particular classification, that listing will be interpreted to be illustrative only and will not be interpreted as a limitation on, or an 

exclusive listing of, the items within that classification.

REVIEW OF EMPLOYMENT AGREEMENT

Review of Employment Agreement. The Executive, for himself and for his successors, heirs and assigns, acknowledges and represents to the Company and the 

Released Parties (as defined in that certain Form of Release, attached hereto as Exhibit B) that (a) this Agreement is executed voluntarily by him, without any duress or undue influence; 

(b) he has had the opportunity to obtain, from legal counsel of his own choosing, full and adequate legal advice as to his legal rights with respect to this Agreement (including the 

Exhibits hereto); and (c) he has read this Agreement (including the Exhibits hereto) in its entirety and fully understands its content and legal effect.

MISCELLANEOUS TERMS

Dispute Resolution.

Except with respect to disputes and claims under Sections 1.5, 1.6, 1.7 and 1.8 hereof (which the Parties hereto may pursue in any court of competent jurisdiction and 

which may be pursued in any court of competent jurisdiction as specified below), any controversy or claim arising out of this Agreement, or the breach thereof, shall be settled by 

arbitration administered by the American Arbitration Association under its National Rules for the Resolution of Employment Disputes. There shall be one arbitrator who shall be 

appointed by the respective Parties or, failing agreement, by the American Arbitration Association in Houston, Texas. The arbitration shall be held in Houston, Texas, and the arbitrator 

shall apply the substantive law of Texas, except that the interpretation and enforcement of this arbitration provision shall be governed by the United States Arbitration Act. Disputes 

about arbitration procedure shall be resolved by the arbitrator or failing agreement, by the American Arbitration Association in Houston, Texas. Except as provided in Section 1.9, the 

award of the arbitrator shall be the sole and exclusive remedy of the Parties and shall be enforceable in any court of competent jurisdiction, subject only to revocation on grounds of 

fraud or clear bias on the part of the arbitrator. The Parties further agree that, unless otherwise determined by the arbitrator, (x) each Party to the arbitration shall bear its own costs and 

expenses (including, without limitation, all attorneys’ fees and expenses, except to the extent otherwise required by applicable law) and (y) all costs and expenses of the arbitration 

proceeding (such as filing fees, the arbitrator’s fees, hearing expenses, etc.) shall be borne equally by the Parties hereto; provided that nothing herein shall be interpreted to preclude 

the arbitrator from allocating the costs and expenses of the Parties and of such proceeding among the Parties in any manner that the arbitrator may lawfully determine to do so. Each 

Party hereto hereby irrevocably submits to the jurisdiction of the District Courts of the State of Texas in Harris County, Texas, and agrees that such courts shall be the exclusive forum 

for the enforcement of any such final judgment, award or determination of the arbitration. Each Party hereto irrevocably consents to service of process by registered mail or personal 

service and waives any objection on the grounds of personal jurisdiction, venue or inconvenience of the forum. Each Party hereto further agrees that each other Party hereto may 

initiate litigation in any court of competent jurisdiction to execute any judicial judgment enforcing or not enforcing any award, judgment or determination of the arbitration.

Notwithstanding the foregoing, prior to any Party hereto instituting any arbitration proceeding hereunder to resolve any claim, such Party first shall submit the claim 

to a mediation proceeding between the Parties hereto which shall be governed by the prevailing procedures of the Federal Mediation and Conciliation Service and shall be conducted in 

Houston, Texas. If the Parties hereto have not agreed in writing to a resolution of the claim pursuant to the mediation within 45 days after the commencement thereof of if any Party 

refuses to participate in the mediation process, then the claim may be submitted to arbitration under Section 4.10 above. Unless otherwise determined by the mediator, each Party hereto 

shall bear its own costs and expenses incurred in connection with the mediation, and all costs and expenses of the mediation proceeding shall be borne equally by the Parties hereto; 

provided that nothing herein shall be interpreted to preclude the mediator from allocating the costs and expenses of the Parties and of such proceeding among the Parties in any manner 

that the arbitrator may lawfully determine to do so.

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Notices. Any notice provided for in this Agreement must be in writing and must be either personally delivered or sent by reputable overnight courier service (charges prepaid) 

or facsimile to the recipient at the address or facsimile number, as applicable, indicated below:

To the Company or the Board:

Houston American Energy Corp

801 Travis, Suite 1425

Houston, Texas 77002

Attention: John F. Terwilliger, CEO

Telephone: (713) 222-6966

Facsimile: (512) 445-2365

with copies to (which shall not constitute notice to the Company):

Michael Sanders, Esq.

20333 S.H. 249, Suite 600

Houston, Texas 77070

Facsimile: (832) 446-2424

To the Executive:

Kenneth Jeffers

2404 Swift Blvd.

Houston, Texas 77030

or such other address or to the attention of such other person as the recipient Party will have specified by prior written notice to the sending Party. Any notice under this Agreement 

will be deemed to have been given when so delivered or sent.

Severability. Whenever possible, each provision of this Agreement will be interpreted in such manner as to be effective and valid under applicable law. If, however, any 

provision of this Agreement is deemed or held to be illegal, invalid or unenforceable by any court of competent jurisdiction, this Agreement shall be considered divisible and inoperative 

as to such provision to the extent it is deemed to be illegal, invalid or unenforceable, and in all other respects this Agreement shall remain in full force and effect; provided, however, 

that if any provision of this Agreement is deemed or held to be illegal, invalid or unenforceable by any court of competent jurisdiction, such illegal, invalid or unenforceable provision 

shall be replaced with a provision that is legal, valid and enforceable and that will achieve, to the greatest extent possible, the economic, business and other purposes of such invalid or 

unenforceable provision. Further, should any provision contained in this Agreement ever be reformed or rewritten by any judicial body of competent jurisdiction, such provision as so 

reformed or rewritten shall be binding upon all parties hereto.

Complete Agreement. This Agreement embodies the complete agreement and understanding among the Parties with regard to the subject matter hereof and supersedes and 

preempts any prior understandings, agreements or representations by or among the Parties, written or oral, which may have related to the subject matter hereof in any way.

Successors and Assigns. This Agreement is intended to bind and inure to the benefit of and be enforceable by the Company, the Executive, and their respective heirs, 

successors and assigns; provided, however, neither Party may assign its respective rights or delegate its obligations hereunder without the prior written consent of the other Party.

Choice of Law. All questions concerning the construction, validity and interpretation of this Agreement will be governed by and construed in accordance with the domestic 

laws of the State of Texas without giving effect to any choice of law or conflict of law provision or rule (whether of the State of Texas or any other jurisdiction) that would cause the 

application of the laws of any jurisdiction other than the State of Texas.

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Remedies. Subject to the provisions of Section 0, each Party will be entitled to enforce its rights under this Agreement specifically, to recover damages and costs caused by 

any breach of any provision of this Agreement and to exercise all other rights existing in its favor. Nothing herein shall prohibit any arbitrator or judicial authority from awarding 

attorneys’ fees or costs to a prevailing Party in any arbitration or other proceeding to the extent that such arbitrator or authority may lawfully do so. The Parties agree and acknowledge 

that money damages may not be an adequate remedy for any breach of the provisions of this Agreement and that, notwithstanding the provisions of Section 0, any Party may in its sole 

discretion apply to any court of law or equity of competent jurisdiction (without posting any bond or deposit) for specific performance and/or other injunctive relief in order to enforce 

or prevent any violations of the provisions of this Agreement.

Amendment and Waiver. The provisions of this Agreement may be amended or waived only with the prior written consent of the Company and the Executive, and no course of 

conduct or failure or delay in enforcing the provisions of this Agreement will affect the validity, binding effect or enforceability of this Agreement.

Construction. The language of this Agreement will be construed simply and according to its fair meaning, and will not be construed for or against any Party hereto as a result 

of the source of its draftsmanship.

Third Party Beneficiaries. This Agreement will not confer any rights or remedies upon any Person other than the parties hereto and their respective successors and permitted 

assigns.

Executive’s Representations. The Executive hereby represents and warrants to the Company that b) the execution, delivery and performance of this Agreement by the 

Executive do not and shall not conflict with, breach, violate or cause a default under any contract, agreement, instrument, order, judgment or decree to which the Executive is a party or 

by which he is bound, c) the Executive is not a party to or bound by any employment agreement, noncompete agreement or confidentiality agreement with any other Person and d) upon 

the execution and delivery of this Agreement by the Company, this Agreement shall be the valid and binding obligation of the Executive, enforceable in accordance with its terms.

Facsimiles and Counterparts. Facsimile transmission of any signed original document and/or retransmission of any signed facsimile transmission will be deemed the same as 

delivery of an original. At the request of either Party, the other Party shall reexecute an original of this document and deliver it to the requesting Party. This Agreement may be executed 

in separate counterparts, each of which is deemed to be an original and all of which taken together constitute one and the same agreement. No party hereto or to any such agreement or 

instrument shall raise the use of a facsimile machine to deliver a signature or the fact that any signature or agreement or instrument was transmitted or communicated through the use of 

a facsimile machine as a defense to the formation of a contract and each such party forever waives any such defense.

IN WITNESS WHEREOF, the parties hereto have executed this Employment Agreement as of the date first written above.

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 THE COMPANY:

 

 HOUSTON AMERICAN ENERGY CORP

 

 By: /s/ John F. Terwilliger

 Name: John F. Terwilliger

 Title: Chief Executive Officer

 

 THE EXECUTIVE:

 

 /s/ Kenneth Jeffers

 KENNETH JEFFERS

 

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RELEASE

I, Kenneth Jeffers (“Releasor”), in consideration of and subject to the performance by Houston American Energy Corp, a Delaware corporation (the “Company”), of its material 

obligations under the Employment Agreement between Releasor and the Company, dated as of August 13, 2010 (the “Employment Agreement”), do hereby release and forever 

discharge as of the date hereof the Company, and its Subsidiaries, all present and former directors, officers, agents, representatives, employees, successors and assigns of the Company 

and its Subsidiaries, and all direct or indirect owners of each of foregoing (other than the undersigned) (collectively, the “Released Parties”) to the extent provided below.

1. I understand that certain of the payments or benefits paid or granted to me under Section 1.4 of the Employment Agreement represent, in part, consideration for signing this 

Release and are not salary, wages or benefits to which I was already entitled. I understand and agree that I will not receive the payments and benefits specified in Section 1.4 of the 

Employment Agreement (other than for any other unpaid compensation benefits and expenses to which I am entitled under Section 1.3 of the Employment Agreement for employment 

prior to termination) unless I execute this Release, do not revoke this Release within the time period permitted hereafter or breach this Release.

2. Except as provided in paragraph 4 below, and except for compensation and benefits and equity ownership in the Company I am entitled to under the terms of the Employment 

Agreement, I knowingly and voluntarily release and forever discharge the Released Parties from any and all claims, controversies, actions, causes of action, cross-claims, counterclaims, demands, debts, compensatory damages, liquidated damages, punitive or exemplary damages, other damages, claims for costs and attorneys’ fees, or liabilities of any nature 

whatsoever in law and in equity, both past and present (through the date of this Release) and whether known or unlawful, suspected, or claimed against the Released Parties which I, 

my spouse, or any of my heirs, executors, administrators or assigns, may have, which arise out of or are connected with my employment with, or my separation from, the Company 

(including, but not limited to, any allegation, claim or violation, arising under: Title VII of the Civil Rights Act of 1964, as amended; the Civil Rights Act of 1991; the Age Discrimination 

in Employment Act of 1967, as amended (including the Older Workers Benefit Protection Act); the Equal Pay Act of 1963 as amended; the Americans with Disabilities Act of 1990; the 

Family and Medical Leave Act of 1993; the Civil Rights Act of 1866, as amended; the Worker Adjustment Retraining and Notification Act; the Employee Retirement Income Security Act 

of 1974; any applicable Executive Order Programs; the Fair Labor Standards Act; or their state or local counterparts; or under any other federal, state or local civil or human rights law, or 

under any other local, state, or federal, law, regulation or ordinance; or under any public policy, contract or tort, or under common law; or arising under any policies, practices or 

procedures of the Company, or any claim for wrongful discharge, breach of contract, infliction of emotional distress, defamation; or any claim for costs, fees, or other expenses 

(including attorneys’ fees incurred in these matters) (all of the foregoing collectively referred to herein as the “Claims”).

3. I represent that I have made no assignment or transfer of any right, claim, demand, cause of action, or other matter covered by paragraph 2 above.

4. I agree that this Release does not waive or release any rights or claims that I may have under the Age Discrimination in Employment Act of 1967 which arise after the date I 

execute this Release. I acknowledge and agree that my separation from employment with the Company in compliance with the terms of the Employment Agreement shall not serve as the 

basis for any claim or action (including, without limitation, any claim under the Age Discrimination in Employment Act of 1967).

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11
5. In signing this Release, I acknowledge and intend that it shall be effective as a bar to each and every one of the Claims hereinabove mentioned or implied. I expressly consent 

that this Release shall be given full force and effect according to each and all of its express terms and provisions, including these relating to unknown and unsuspected Claims 

(notwithstanding any state statute that expressly limits the effectiveness of a general release of unknown, unsuspected and unanticipated Claims), if any, as well as those relating to 

such other Claims hereinabove mentioned or implied. I acknowledge and agree that this waiver is an essential and material term of this Release and that without such waiver the 

Company would not have agreed to the terms of the Employment Agreement. I further agree that in the event I should bring a Claim seeking damages against any Released Party, or in 

the event I should seek to recover against any Released Party in any Claim brought by a governmental agency on my behalf, this Release shall serve as a complete defense to such 

Claims. I further agree that I am not aware of any pending charge or complaint of the type described in paragraph 2 as of the execution of this Release.

6. I agree that neither this Release, nor the furnishing of the consideration for this Release, shall be deemed or construed at any time to be an admission by any Released Party 

or myself of any improper or unlawful conduct.

7. I agree that I will forfeit all cash amounts payable by the Company pursuant to the Employment Agreement that would not have otherwise been paid but for my signing this 

Release if I challenge the validity of this Release. I also agree that if I violate this Release by suing any Released Party, I will pay all costs and expenses of defending against the suit 

incurred by such Released Party, including reasonable attorneys’ fees, and return all payments received by me pursuant to the Employment Agreement.

8. I agree that this Release is confidential and agree not to disclose any information regarding the terms of this Release, except to my immediate family and any tax, legal or other 

counsel I have consulted regarding the meaning or effect hereof or as required by law, and I will instruct each of the foregoing not to disclose the same to anyone.

9. Any non-disclosure provision in this Release does not prohibit or restrict me (or my attorney) from responding to any inquiry about this Release or its underlying facts and 

circumstances by any governmental entity.

l0. I agree to reasonably cooperate with the Company and its Subsidiaries in any internal investigation or administrative; regulatory, or judicial proceeding. I understand and 

agree that my cooperation may include, but not be limited to, making myself available to the Company and its Subsidiaries upon reasonable notice for interviews and factual 

investigations; appearing at the request of the Company or any of its Subsidiaries to give testimony without requiring service of a subpoena or other legal process; volunteering to the 

Company and its Subsidiaries pertinent information; and turning over to the Company and its Subsidiaries all relevant documents that are or may come into my possession all at times 

and on schedules that are reasonably consistent with any other permitted activities and commitments. I understand that in the event the Company or any of its Subsidiaries asks for my 

cooperation in accordance with this provision, the Company will reimburse me solely for reasonable travel expenses related thereto, including lodging and meals, upon my submission 

of receipts.

11. I hereby covenant to each of the Released Parties and agree that I will not, directly or indirectly, make, or solicit or encourage others to make or solicit, any disparaging 

remarks concerning the Released Parties, or any of their products, services, businesses or activities. The promises set forth in this paragraph 11 are subject to applicable legal processes 

compelling truthful statements.

12. The Company hereby covenants that neither the Company nor any of its Subsidiaries will issue or make any public comment, statement, or remark that would reasonably be 

construed as intended to disparage, criticize or denigrate the Executive. The promises set forth in this paragraph 12 are subject to applicable legal processes compelling truthful 

statements.

13. The Parties specifically acknowledge their continuing obligations to one another under the Employment Agreement, including without limitation under Sections 1.4 (as 

applicable), 1.5, 1.6, 1.7 and 1.8 of the Employment Agreement.

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12
14. Whenever possible, each provision of this Release shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Release 

is held to be invalid, illegal or unenforceable in any respect under any applicable law or rule in any jurisdiction, such invalidity, illegality or unenforceability shall not affect any other 

provision or any other jurisdiction, but this Release shall be reformed, construed and enforced in such jurisdiction as if such invalid, illegal or unenforceable provision had never been 

contained herein.

15. Capitalized terms used but not defined herein shall have the meaning given such terms in the Employment Agreement.

BY SIGNING THIS RELEASE, I REPRESENT AND AGREE THAT:

(a) I HAVE READ IT CAREFULLY;

(b) I UNDERSTAND ALL OF ITS TERMS AND KNOW THAT I AM GIVING UP IMPORTANT RIGHTS, INCLUDING BUT NOT LIMITED TO, RIGHTS UNDER THE AGE 

DISCRIMINATION IN EMPLOYMENT ACT OF 1967, AS AMENDED; TITLE VII OF THE CIVIL RIGHTS ACT OF 1964, AS AMENDED; THE EQUAL PAY ACT OF 1963; THE 

AMERICANS WITH DISABILITIES ACT OF 1990; AND THE EMPLOYEE RETIREMENT INCOME SECURITY ACT OF 1974, AS AMENDED;

(c) I VOLUNTARILY CONSENT TO EVERYTHING IN IT;

(d) I HAVE BEEN ADVISED TO CONSULT WITH AN ATTORNEY BEFORE EXECUTING IT AND I HAVE DONE SO OR, AFTER CAREFUL READING AND 

CONSIDERATION, I HAVE CHOSEN NOT TO DO SO OF MY OWN VOLITION;

(e) I HAVE HAD AT LEAST 21 DAYS FROM THE DATE OF MY RECEIPT OF THIS RELEASE, SUBSTANTIALLY IN ITS FINAL FORM ON , , TO CONSIDER IT, AND THE 

CHANGES MADE SINCE THE , VERSION OF THIS RELEASE ARE NOT MATERIAL AND WILL NOT RESTART THE REQUIRED 21-DAY PERIOD;

(f) THE CHANGES TO THE AGREEMENT SINCE , EITHER ARE NOT MATERIAL OR WERE MADE AT MY REQUEST;

(g) I UNDERSTAND THAT I HAVE SEVEN (7) DAYS AFTER THE EXECUTION OF THIS RELEASE TO REVOKE IT AND THAT THIS RELEASE SHALL NOT BECOME 

EFFECTIVE OR ENFORCEABLE UNTIL THE REVOCATION PERIOD HAS EXPIRED;

(h) I HAVE SIGNED THIS RELEASE KNOWINGLY AND VOLUNTARILY AND WITH THE ADVICE OF ANY COUNSEL RETAINED TO ADVISE ME WITH RESPECT TO IT; 

AND

(i) I AGREE THAT THE PROVISIONS OF THIS RELEASE MAY NOT BE AMENDED, WAIVED, CHANGED OR MODIFIED EXCEPT BY AN INSTRUMENT IN WRITING 

SIGNED BY AN AUTHORIZED REPRESENTATIVE OF THE COMPANY AND BY ME.

Acknowledged and agreed as of the date first written above:

13

Filer: Houston American Energy Corp Form Type: 10-K Period: 12/31/10 Job Number: 10-K 12-31-2010 Rev: 1 Sequence: 13

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Date: 9-2-2010 /s/ Kenneth Jeffers

 Kenneth Jeffers

 By: /s/ Kenneth Jeffers

 Name: Kenneth Jeffers

 Title: Senior Vice President of Exploration
Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (File No. 333 -127656), relating to the 2005 Stock Option Plan of Houston 

American Energy Corp., on Form S-3 (File No. 333-134756), on Form S-8 (File No. 333-151824), relating to the 2008 Equity Incentive Plan, and on Form S-3 (File No. 333-161319) of our 

report dated March 15, 2011, relating to the financial statements of Houston American Energy Corp. that appear in the Annual Report on Form 10-K of Houston American Energy for the 

year ended December 31, 2010.

/s/ GBH CPAs, PC

GBH CPAs, PC

Houston, Texas

March 15, 2011

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Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the use of the name Lonquist & Co., LLC and to incorporation by reference of our report, which appears in the annual report on Form 10-K of Houston 

American Energy Corp. for the year ended December 31, 2010, in the Registration Statements of Houston American Energy Corp. on Form S-8 (File No. 333-127656), relating to the 2005 

Stock Option Plan of Houston American Energy Corp., on Form S-3 (File No. 333-134756), on Form S-8 (File No. 333-151824), relating to the 2008 Equity Incentive Plan, of our report 

dated March 15, and on Form S-3 (File No. 333-161319), and to any amendments to those Registration Statements.

/s/ Don E. Charbula, P.E.

Vice President

LONQUIST & CO., LLC

HOUSTON, TEXAS

March 15, 2011

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Exhibit 31.1

SECTION 302

CERTIFICATION

I, John Terwilliger, certify that:

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1. I have reviewed this annual report on Form 10-K of Houston American Energy Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the 

circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respect the financial condition, results of 

operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) 

and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a–15(f) and 15d–15(f)) for the registrant and have:

 a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material 

information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which 

this quarterly report is being prepared;

 b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide 

reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted 

accounting principles;

 c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure 

controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has 

materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the 

audit committee of the registrant’s board of directors:

 a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the 

registrant’s ability to record, process, summarize and report financial information; and

 b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: March 15, 2011 /s/ John F. Terwilliger

 John F. Terwilliger,

 Chief Executive Officer
Exhibit 31.2

SECTION 302

CERTIFICATION

I, James J. Jacobs, certify that:

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1. I have reviewed this annual report on Form 10-K of Houston American Energy Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the 

circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respect the financial condition, results of 

operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) 

and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a–15(f) and 15d–15(f)) for the registrant and have:

 a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material 

information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which 

this quarterly report is being prepared;

 b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide 

reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted 

accounting principles;

 c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure 

controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 e) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has 

materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the 

audit committee of the registrant’s board of directors:

 a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the 

registrant’s ability to record, process, summarize and report financial information; and

 b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: March 15, 2011 /s/ James J. Jacobs

James J. Jacobs,

Chief Financial Officer
Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, John Terwilliger, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report of Houston 

American Energy Corp. on Form 10-K for the year ended December 31, 2010 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that 

information contained in such Form 10-K fairly presents in all material respects the financial condition and results of operations of Houston American Energy Corp.

Filer: Houston American Energy Corp Form Type: 10-K Period: 12/31/10 Job Number: 10-K 12-31-2010 Rev: 1 Sequence: 1

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 By: /s/ John F. Terwilliger

 Name: John F. Terwilliger

 Title: Chief Executive Officer

 Dated: March 15, 2011
Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, James J. Jacobs, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report of Houston 

American Energy Corp. on Form 10-K for the year ended December 31, 2010 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that 

information contained in such Form 10-K fairly presents in all material respects the financial condition and results of operations of Houston American Energy Corp.

Filer: Houston American Energy Corp Form Type: 10-K Period: 12/31/10 Job Number: 10-K 12-31-2010 Rev: 1 Sequence: 1

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Thomson Reuters / EDGARfilings Description: Exhibit 32.2 Henry Del Toro Created using EDGARizer

 By: /s/ James J. Jacobs

 Name: James J. Jacobs

 Title: Chief Financial Officer

 Dated: March 15, 2011
Exhibit 99.2

March 1, 2011

Mr. John F. Terwilliger

Houston American Energy Corporation

801 Travis, Suite 1425

Houston, Texas 77002

Dear Mr. Terwilliger:

Pursuant to your request, we have estimated the future oil and gas Reserves and projected the associated future revenues net to the interests owned by Houston American Energy 

Corporation ("Houston American") as of December 31, 2010. Assets located in Louisiana, Oklahoma, and Texas are included in this report. As shown in the following table, Proved 

Developed Producing ("PDP") and Proved Developed Non-Producing ("PDNP") Reserves were evaluated in this report.

Our conclusions, as of December 31, 2010, are summarized below:

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AUSTIN

3345 Bee Cave Road

Suite 201

Austin. Texas 78746 USA

Tel 512.732.9812

Fax 512.732.9816

www.lonquist.com

HOUSTON

1001 McKinney

Suite 420

Houston, Texas 77002 USA

Tel 713.559.9950

Fax 713.559.9959

 Re: Houston American Energy Corporation

 Year End Reserve Report

 Louisiana, Oklahoma, and Texas

 as of December 31, 2010

 SEC Guideline Case

 Net to Houston American Energy Corporation

 Proved Developed Proved Totai Total Total Grand

SEC Pricing as of December 31, 2010 Producing Non-Producinga Undeveloped Provedb Probable Possible Totalb

Estimated Future Net Oil/Condensate, bbl 3,520 2,500 0 6,010 0 0 6,010

Estimated Future Net Gas, MMcf 49.9 32.3 0 82.2 0 0 82.2

Estimated Future Net NGL, bbl 390 0 0 390 0 0 390

 

Total Future Gross Revenue, $ 533,580 366,460 0 900,040 0 0 900,040

Estimated Future Production Taxes, $ 43,140 30,910 0 74.050 0 0 74,050

Estimated Future Operating Expenses, $ 129,750 75,920 205.660 205,670

Estimated Future Capital Costs, $ 0 0 0 0 0 0 0

Estimated Future Net Revenue ("FNR"), $ 360,690 259,640 0 620.330 0 0 620,330

Discounted FNR at 10%, $ 300,940 138,680 0 439.620 0 0 439,620

Discounted FNR at 15%, $ 278,350 104,050 0 382.400 0 0 382,400

 

Estimated Net Revenues by Year, $

2011 115,550 0 0 115,550 0 0 115,550

2012 86,000 0 0 86.000 0 0 86,000

2013 67,150 0 0 67,150 0 67,150

Subtotal 268,700 0 0 268.700 268,700

Thereafter 91,990 259,640 0 351,630 0 351,630

Total 360,690 259,640 0 620,330 0 620,330

 

Estimated Average Net Production Rate - 2011

Oil/Condensate, B/D 3.4 0 0 3.4 0 3 3.4

Gas, Mcf/D 38.4 0 0 38.4 0 3 38.4

NGL, B/D 0.16 0 0 0.16 0 0 0.16

a Column includes the Proved Developed Non-Producing, Shut-In and Behind-Pipe classifications

b Totals might not match detailed cash flows due to computer rounding

 

 
Houston American Energy Corporation - Year End Reserve Report

SEC Pricing as of December 31, 2009

March 1, 2011

Page 2 of 5

Purpose of Report

This report has been prepared to provide the management of Houston American Energy Corporation with a projection of estimated remaining Reserves and projected future net 

revenues as of December 31, 2010. These estimates have not been adjusted for risk.

Standards of Practice

This report has been prepared in accordance with our understanding of the Securities and Exchange Commission, SX Reg. § 210.4-10, dated November 18, 1981 as amended September 

19, 1989, requiring adherence to definitions of "Proved" oil and gas Reserves. Additionally, at the request of Houston American, and within the most recently adopted and accepted 

SEC guidelines (Modernization of Oil and Gas Reporting; Final Rule; January 14, 2009), we have evaluated the Proved, Probable and Possible Reserves. The SEC oil and gas Reserve 

definitions are attached hereto.

Liquid hydrocarbon volumes are expressed in standard 42-gallon barrels. All natural gas volumes are sales gas expressed at the official pressure and temperature bases of the areas in 

which the gas Reserves are located.

All currencies in this report are expressed in U.S. dollars.

Reserve Estimates

Extrapolation of historical production data was utilized for those producing properties where sufficient data were available to suggest decline trends. Reserves assigned to the remaining 

producing properties and any non-producing assets were determined by analogy to offset wells producing from similar formations or by volumetric analysis. Reserves assigned by 

analogy and volumetric analysis are subject to greater revision than Reserves projected using established performance trends.

As of December 31, 2010, the PDP net remaining Reserves were estimated to be 3,520 barrels of oil/condensate, 390 barrels of natural gas liquids ("NGL") and 49.9 MMcf of gas. The net 

present value, discounted at 10%, of the PDP Reserves was $300,940. Of the total revenue, 51% was derived from oil/condensate and natural gas liquids production. The Reserve life 

index ("R/P") for the PDP Reserves was estimated to be 4.8 years based on a 6:1 conversion rate.

The PDNP Behind-Pipe net remaining Reserves were estimated to be 2,500 barrels of oil/condensate and 32.3 MMcf of gas. The net present value, discounted at 10%, of the PDP 

Reserves was $138,680. Of the total revenue, 53% was derived from oil/condensate production.

The total Proved net remaining Reserves were estimated to be 6,010 barrels of oil/condensate, 390 barrels of natural gas liquids and 82.2 MMcf of gas. The net present value, discounted 

at 10%, of the total Reserves was $439,620. Of the total revenue, 52% was derived from oil, condensate, and natural gas liquids production.

Filer: Houston American Energy Corp Form Type: 10-K Period: 12/31/10 Job Number: 10-K 12-31-2010 Rev: 1 Sequence: 2

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Houston American Energy Corporation - Year End Reserve Report

SEC Pricing as of December 31, 2009

March 1, 2011

Page 3 of 5

Notable Properties

Crown Paper No. 1 (19,100 ft Tusc "G" Sand), East Baton Rouge Parish, LA

The Crown Paper No. 1, located in East Baton Rouge Parish, Louisiana, is operated by Pennington Oil and Gas Interests. The Crown Paper No. 1 is currently producing approximately 

687 Mcf of gas and 39 bbls of condensate per day from the 19,100 ft Tuscaloosa "G" formation. As of December 31, 2010, the estimated net remaining Reserves for this zone were 2,630 

barrels of oil and 39.35 MMcf of gas. The future net revenue, discounted at 10%, of $256,840 represents 58.4% of the total discounted future net revenue.

Crown Paper No. 1 (18,930 ft Tusc "F" Sand), East Baton Rouge Parish, LA

The Crown Paper No. 1, located in East Baton Rouge Parish, Louisiana, is operated by Pennington Oil and Gas Interests. The Crown Paper No. 1 is scheduled to be recompleted in 2015, 

and is estimated to produce approximately 1,000 Mcf of gas and 69 bbls per day from the 18,930 ft Tuscaloosa "F" formation. These Reserves are classified as Proved Developed NonProducing Behind Pipe. As of December 31, 2010 the estimated net remaining Reserves for this zone were 980 barrels of oil and 11.87 MMcf of gas. The future net revenue, discounted at 

10%, of $58,860 represents 13.4% of the total discounted future net revenue.

Crown Paper No. 1 (17,950 ft Tusc "C1" Sand), East Baton Rouge Parish, LA

The Crown Paper No. 1. located in East Baton Rouge Parish, Louisiana, is operated by Pennington Oil and Gas Interests. The Crown Paper No. 1 is scheduled to be recompleted in 2018, 

and is estimated to produce approximately 1,000 Mcf of gas and 69 bbls per day from the 17,950 ft Tuscaloosa "C1" formation. These Reserves are classified as Proved Developed NonProducing Behind Pipe. As of December 31, 2010 the estimated net remaining Reserves for this zone were 980 barrels of oil and 11.92 MMcf of gas. The future net revenue, discounted at 

10%, of $45,380 represents 10.3% of the total discounted future net revenue.

These three properties represent 82% of the future net revenue attributable to Houston American Energy Corporation.

Product Prices and Differentials

The base product prices of $79.79 per barrel and $4.46 per MMbtu utilized herein are reported by the Energy Information Administration for the closing NYMEX West Texas 

Intermediate ("WTI" at Cushing, OK) Contract 1 oil prices on the first trading day of each month averaged over the 2010 calendar year and Gas prices are reported at Henry Hub, LA 

Contract 1. As required by SEC regulations, no price escalations are included in this report. Realized product prices in this report reflect adjustments for heating content, premiums and 

basis differentials. Where applicable, transportation costs have been included.

Operating Costs and Expenditures

Direct lease operating expenses were input as dollars per month into the economic models. These data were supplied by Houston American Energy Corporation. Where applicable, lease 

operating costs were adjusted for non-recurring costs. Operating costs were not escalated in this report.

Severance and ad valorem taxes are deducted as a percentage of gross revenues or as a charge per unit of production. The individual well projections of oil and gas cease when the 

operating expenses exceed the gross revenues.

Filer: Houston American Energy Corp Form Type: 10-K Period: 12/31/10 Job Number: 10-K 12-31-2010 Rev: 1 Sequence: 3

Submission: Document Name: ex99_2.htm Saved: 3/14/2011 13:21:59 Printed: 3/14/2011 15:19:30

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Houston American Energy Corporation - Year End Reserve Report

SEC Pricing as of December 31. 2009

March 1.2011

Page 4 of 5

Values Not Considered

In all cases, we have attempted to account for all deductions from gross revenues except for the following:

No value has been assigned to non-producing acreage or to acreage held by production.

Report Qualifications

Estimates of future revenues were based on projections of recoverable hydrocarbons, rates of production, timing of recompletions and drilling, proration by state and federal agencies, 

operating costs, direct taxes, and product prices. Any unusual combination of the many factors, including weather, political risk or acts of terrorism could result in future receipts being 

considerably less or more than those estimated herein.

THE REVENUES AND PRESENT WORTH OF FUTURE NET REVENUES ARE NOT REPRESENTED TO BE MARKET VALUES EITHER FOR THE INDIVIDUAL PROPERTIES OR 

IN A TOTAL PROPERTY BASIS.

The Reserves and revenues for specific properties should be considered in context with the overall report.

Data Sources

Historical production data were obtained from Houston American Energy Corporation and public sources, such as Lasser Production Data Services, HPDI, LLC, Drillinglnfo.com, and 

IHS Energy Data Services. This production data was generally updated though December 2010.

We retain in our files digital databases for all properties and certain other hard copy information that we believe pertinent. We have not inspected the properties evaluated in this report, 

nor have we conducted independent well tests.

Filer: Houston American Energy Corp Form Type: 10-K Period: 12/31/10 Job Number: 10-K 12-31-2010 Rev: 1 Sequence: 4

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Thomson Reuters / EDGARfilings Description: Exhibit 99.2 Henry Del Toro Created using EDGARizer

 

 • Federal Income Taxes

 • Depreciation, depletion, and/or amortization, if any

 • Costs in excess of revenues of uneconomic leases

 • Plugging and abandonment costs in excess of salvage value

 • Environmental restoration costs, if any

 • Product price hedges, if any

 

 
Houston American Energy Corporation - Year End Reserve Report

SEC Pricing as of December 31, 2009

March 1, 2011

Page 5 of 5

Independent Evaluation

Neither Lonquist & Co., LLC nor any of its employees have any interest or ownership in the subject properties, and neither our employment nor compensation is contingent on our 

findings herein.

Filer: Houston American Energy Corp Form Type: 10-K Period: 12/31/10 Job Number: 10-K 12-31-2010 Rev: 1 Sequence: 5

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Thomson Reuters / EDGARfilings Description: Exhibit 99.2 Henry Del Toro Created using EDGARizer

 

 Sincerely.

 

 LONQUIST & CO., LLC

 Texas Registration No. F-8952

 

 /s/ Lisa B. Hunter

 Lisa B. Hunter, P.E.

 Senior Petroleum Engineer

 Texas License No. 64269

 

 Date Signed: March 1, 2011

 Austin, Texas

 

 
February 23, 2011

Mr. John F. Terwilliger

Houston American Energy Corporation

801 Travis, Suite 1425

Houston, Texas 77002

Dear Mr. Terwilliger:

Pursuant to your request, we have estimated the future hydrocarbon Reserves and projected the associated future revenues net to the interests owned by Houston American Energy 

Corporation (“Houston American”) as of January 1, 2011. The assets evaluated in this report are in the HUPECOL, LLC-operated (“HUPECOL”) Caracara Concession in the Republic of 

Colombia. As shown in the following table, Proved Developed Producing (“PDP”), Proved Developed Non-Producing (“PDNP”), and Proved Undeveloped Reserves (“PUD”) were 

evaluated for this report. Collectively, these are known as 1P Reserves.

Our conclusions, as of January 1, 2011, are summarized below:

a Column includes the Proved Developed Non-Producing, Shut-In and Behind-Pipe classifications

b Totals might not match detailed cash flows due to computer rounding

Filer: Houston American Energy Corp Form Type: 10-K Period: 12/31/10 Job Number: 10-K 12-31-2010 Rev: 1 Sequence: 6

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Thomson Reuters / EDGARfilings Description: Exhibit 99.2 Henry Del Toro Created using EDGARizer

 

Austin

3345 Bee Cave Road

Suite 201

Austin, Texas 78746 USA

Tel 512.732.9812

Fax 512.732.9816

 

Houston

1001 McKinney

Suite 420

Houston, Texas 77002 USA

Tel 513.559.9950

Fax 713.5599959

 Re: Houston American Energy Corporation

 Proved Reserve Update

 Republic of Colombia

 As of January 1, 2011

 SEC Guideline Case

 Net to Houston American Energy Corporation

 Proved Developed Proved Total Total Total Prospective Grand

SEC Pricing as of December 31, 2010 Producing

NonProducinga Undeveloped Provedb Probable Possible Resource Totalb

Estimated Future Net 

Oil/Condensate, bbl 7,431 9,771 43,949 61,151 0 0 0 61,151

Estimated Future Net Gas, MMcf 0 0 0 0 0 0 0 0

Total Future Gross Revenue, $ 574,090 754,898 3,395,290 4,724,278 0 0 0 4,724,278

Estimated Future Production Taxes, 

$ 0 0 0 0 0 0 0 0

Estimated Future Operating 

Expenses, $ 347,879 309,876 1,363,518 2,021,273 0 0 0 2,021,273

Estimated Future Capital Costs, $ 0 9,568 626,707 636,275 0 0 0 636,275

Estimated Future Net Revenue 

("FNR"), $ 226,211 435,454 1,405,065 2,066,730 0 0 0 2,066,730

Discounted FNR at 10%, $ 213,984 340,645 1,063,756 1,618,385 0 0 0 1,618,385

Discounted FNR at 15%, $ 208,686 305,500 936,333 1,450,518 0 0 0 1,450,518

Estimated Net Revenues by Year, $

2011 179,933 78,509 38,656 297,098 0 0 0 297,098

2012 41,175 29,247 22,229 92,650 0 0 0 92,650

2013 5,103 137,119 867,575 1,009,797 0 0 0 1,009,797

Subtotal 226,211 244,875 928,460 1,399,545 0 0 0 1,399,545

Thereafter 0 190,579 476,605 667,185 0 0 0 667,185

Total 226,211 435,454 1,405,065 2,066,730 0 0 0 2,066,730

Estimated Average Net Production 

Rate - 2011

Oil/Condensate, B/D 12 4 9 25 0 0 0 25

Gas, Mcf/D 0 0 0 0 0 0 0 0

 

 
Houston American Energy Corporation

January 1, 2011 Reserve Update

HUPECOL, LLC-Operated Properties

February 23, 2011

Page 2 of 4

Purpose of Report and Standards of Practice

This report was prepared to provide the management of Houston American with a projection of estimated remaining hydrocarbon Reserves and projected future net revenues, effective 

January 1, 2011. These estimates have not been adjusted for risk.

This report has been prepared in accordance with our understanding of the Securities and Exchange Commission (“SEC”), SX Reg. § 210.4-10, dated November 18, 1981 as amended 

September 19, 1989, requiring adherence to definitions of “Proved” oil and gas Reserves. Additionally, this report conforms to the most recently adopted SEC guidelines in the 

Modernization of Oil and Gas Reporting; Final Rule (January 14, 2009). The SEC oil and gas Reserve definitions are attached hereto.

Liquid hydrocarbon volumes are expressed in standard 42-gallon barrels. All natural gas volumes are sales gas expressed at the official pressure and temperature bases of the areas in 

which the gas Reserves are located.

All currencies in this report are expressed in U.S. dollars.

Reserve Estimates

Well-by-well production data in this report were updated through December 31, 2010, where applicable. Extrapolation of historical production data was utilized for those producing 

properties where sufficient data were available to suggest decline trends. In addition to rate vs. time decline curve analysis, oil fraction vs. cumulative oil and water fraction vs. 

cumulative oil data were used to determine Reserves for producing properties, where applicable. Reserves assigned to the remaining producing properties and the non-producing assets 

were determined by analogy to offset wells producing from similar formations or by volumetric analysis. Reserves assigned by analogy and volumetric analysis are subject to greater 

revision than those projected using established performance trends.

Geological interpretations and structural mapping of the productive sands for the Caracara Concession were prepared by L&Co using a base map supplied by HUPECOL. This base map 

was generated primarily with 3D seismic data augmented with subsurface well control. The L&Coprepared structure maps formed the basis for the net pay isochore maps drawn by 

L&Co. The net pay values included in these maps were taken from the independent petrophysical analyses prepared by Lonquist & Co. We planimetered these maps to determine the 

reservoir volume and the results were used in the volumetric analyses.

As of January 1, 2011, the Total Proved net remaining Reserves were estimated to be 61,151 barrels of oil. The net present value, discounted at 10%, of the remaining Reserves was 

$1,618,385. Of the total discounted net revenue, approximately 13% was generated by the Proved Producing Reserves.

Product Prices and Differentials

The base oil price of $79.81 per barrel in this evaluation is the un-weighted arithmetic average of the closing NYMEX West Texas Intermediate (“WTI”) contract 1 oil price on the first 

trading day of the preceding 12-month period as reported by the Energy Information Administration. As required by SEC regulations, no price escalations are included in this report. 

Realized product prices in this report reflect adjustments for basis differentials and include transportation costs, where applicable.

Filer: Houston American Energy Corp Form Type: 10-K Period: 12/31/10 Job Number: 10-K 12-31-2010 Rev: 1 Sequence: 7

Submission: Document Name: ex99_2.htm Saved: 3/14/2011 13:21:59 Printed: 3/14/2011 15:19:30

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Houston American Energy Corporation

January 1, 2011 Reserve Update

HUPECOL, LLC-Operated Properties

February 23, 2011

Page 3 of 4

Operating Costs and Expenditures

Direct well operating expense data for January through December 2010 were supplied by HUPECOL. These direct operating costs, input as dollars per month into the economic models, 

were based on actual expenses and were adjusted for non-recurring costs, where applicable. We have accepted these expense data as correct. Direct operating costs were not escalated 

in this report.

The individual well projections of oil and gas production ceased when the operating expenses exceeded the gross revenues.

Development costs included in this report were provided by HUPECOL and were based on authorizations for expenditures for the proposed work or actual costs for similar projects. The 

timing of investments were also supplied by HUPECOL based their long-range plans and experience in the area. Development costs were not escalated in this report.

Values Not Considered

In all cases, we have attempted to account for all deductions from gross revenues except for the following:

No value has been assigned to non-producing leasehold or to acreage held by production.

Report Qualifications

Estimates of future revenues were based on projections of recoverable hydrocarbons, rates of production, timing of recompletions and drilling, proration by state and federal agencies, 

operating costs, direct taxes, and product prices. Any unusual combination of the many factors, including weather, political risk, or acts of terrorism could result in future receipts being 

considerably less or more than those estimated herein.

THE REVENUES AND PRESENT WORTH OF FUTURE NET REVENUES ARE NOT REPRESENTED TO BE MARKET VALUES EITHER FOR THE INDIVIDUAL PROPERTIES OR 

IN A TOTAL PROPERTY BASIS.

The Reserves and revenues for specific properties should be considered in context with the overall report.

Data Sources

Key data, including well information, geologic interpretations, direct operating costs, historical production data, and realized product prices were supplied by HUPECOL. Ownership 

data were supplied by Houston American. The ownership interests and other factual data were accepted without independent verification.

Filer: Houston American Energy Corp Form Type: 10-K Period: 12/31/10 Job Number: 10-K 12-31-2010 Rev: 1 Sequence: 8

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Thomson Reuters / EDGARfilings Description: Exhibit 99.2 Henry Del Toro Created using EDGARizer

 

1. U.S. or Colombian Income Taxes

2. Depreciation, depletion, and/or amortization, if any

3. Costs in excess of revenues of uneconomic leases

4. Plugging and abandonment costs in excess of salvage value

5. Environmental restoration costs, if any

6. Product price hedges, if any

 

 
Houston American Energy Corporation

January 1, 2011 Reserve Update

HUPECOL, LLC-Operated Properties

February 23, 2011

Page 4 of 4

We retain in our files digital databases for all properties and certain other hard copy information that we believe pertinent. We have not inspected the properties evaluated in this report, 

nor have we conducted independent well tests.

Independent Evaluation

Neither Lonquist & Co., LLC nor any of its employees have any interest or ownership in the subject properties, and neither our employment nor compensation is contingent on our 

findings herein.

Filer: Houston American Energy Corp Form Type: 10-K Period: 12/31/10 Job Number: 10-K 12-31-2010 Rev: 1 Sequence: 9

Submission: Document Name: ex99_2.htm Saved: 3/14/2011 13:21:59 Printed: 3/14/2011 15:19:30

Thomson Reuters / EDGARfilings Description: Exhibit 99.2 Henry Del Toro Created using EDGARizer

 

 Sincerely, 

 

 LONQUIST & CO., LLC

 Texas Registration No. F-8953

 

 /s/ Don E. Charbula

 

 Don E. Charbula, P.E.

 Vice President

 Texas License No. 73435

 Date Signed: February 23, 2011 

 Austin, Texas