HOUSTON AMERICAN ENERGY CORP - Annual Report: 2015 (Form 10-K)

   

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)

☒

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

For the Fiscal Year Ended December 31, 2015

o

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

For the transition period from              to             

Commission File No. 1-32955

HOUSTON AMERICAN ENERGY CORP.
(Exact name of registrant specified in its charter)

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

801 Travis Street, Suite 1425, Houston, Texas 77002
(Address of principal executive offices)(Zip code)

Issuer’s telephone number, including area code: (713) 222-6966

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which each is registered
Common Stock, $0.001 par value	NYSE MKT

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 o No ☒

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 o No ☒

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 ☒ No o

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 o

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. ☒

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 o

Accelerated filer o

Non-accelerated filer o

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 o No ☒

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant on June 30, 2015, based on the closing sales price of the registrant’s common stock on that date, was approximately $8.1 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 8, 2016 was 51,979,945.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company’s Proxy Statement for its 2016 Annual Meeting are incorporated by reference into Part III of this Report.

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business		3
Item 1A.	Risk Factors		13
Item 1B.	Unresolved Staff Comments		23
Item 2.	Properties		23
Item 3.	Legal Proceedings		23
Item 4.	Mine Safety Disclosures		23
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities		24
Item 6.	Selected Financial Data		25
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		25
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		30
Item 8.	Financial Statements and Supplementary Data		30
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		31
Item 9A.	Controls and Procedures		31
Item 9B.	Other Information		31
PART III
Item 10.	Directors, Executive Officers, and Corporate Governance		31
Item 11.	Executive Compensation		32
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		32
Item 13.	Certain Relationships and Related Transactions, and Director Independence		32
Item 14.	Principal Accountant Fees and Services		32
PART IV
Item 15.	Exhibits and Financial Statement Schedules		33
SIGNATURES			34

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

Item 1.

Business

General

Houston American Energy Corp is an independent oil and gas company focused on the development, exploration, exploitation, acquisition, and production of natural gas and crude oil properties in the U.S. Gulf Coast region and in South America. Our oil and gas assets and operations are concentrated primarily in the South American country of Colombia and in the onshore Gulf Coast region, particularly Texas and Louisiana.

We focus on early identification of, and entrance into, existing and emerging resource plays, particularly in South America, the U.S. Gulf Coast and Australia. We typically seek to partner with, or invest in, larger operators in the 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, investing in 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.

Properties

Our exploration and development 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 property interests differ 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, corporate equity interests or other mineral rights. Our percentage interest in each property represents the portion of the interest in the property we share with other partners in the property. Because each property consists of a bundle of assets that may or may not include a working interest in the project, our stated interest in a property simply represents our proportional ownership in the bundle of assets that constitute the property. Therefore, our interest in a property should not be confused with the working interest that we will own when a given well is drilled. Each of our exploration and development projects represents a negotiated transaction between the project partners relating to one or more properties. Our working interest may be higher or lower than our stated interest.

The following table sets forth information relating to our principal properties as of December 31, 2015:

	Net acreage			Average working interest %			Gross producing wells			Net proved reserves (boe)			2015 Net Production
													Oil (bbls)			Natural Gas (mcf)
Oklahoma		4.0			2.4	%		1			681			—			767
Louisiana		92.0			4.9	%		7			16,878			5,805			28,421
Texas		122.5			1.4	%		1			908			263			2,958
Total U.S.		218.5			2.6	%		9			18,467			6,068			32,416
Colombia		49,025.0			12.5	%		—			—			—			—
Total		49,243.5			12.5	%		9			18,467			6,068			32,416

- 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:

•

East Baton Rouge Parish— we hold (i) a 4.557% royalty interest in 2,485 royalty acres, as well as a 3.547% royalty interest in the Crown Paper #01 well, and (ii) a 5% working interest in a 11,000 foot well and 1,300+ net acre lease block.

•

Plaquemines Parish— we hold a 1.8% working interest in the SL 180771 well and 300 gross acre lease block.

•

Vermilion Parish— we hold a 1.5% working interest in a 15,000 foot Discorbis well and 450+ net acre lease block.

•

Iberville Parish— we hold (i) a 3% working interest in a 13,500 foot Cib Haz well and 618 acre lease block, (ii) a 4% working interest before casing point in a test well and a 3% working interest after the casing point, and in future wells, on a 1,129 acre lease block, and (iii) a 10.67% working interest before the casing point and 8% working interest after the casing point in a 102 acre lease block.

•

Assumption Parish – we hold a 5% working interest before payout and 4% working interest after payout in a 15,200 foot Rob L well and 238 acre lease block.

•

Jefferson Davis Parish— we hold a 10.9% working interest before payout and a 9.375% working interest after payout in a 7,000 foot Cris H well.

Texas Properties

Our principal exploration properties in Texas consist of the following:

•

Matagorda County — we hold a 2.71% working interest in the 779 acre Harrison Prospect.

- Colombian Properties:

At December 31, 2015, we held interests in multiple prospects in Colombia covering 392,205 gross acres. We identify our Colombian prospects by the concessions operated.

The following table sets forth information relating to our interests in prospects in Colombia at December 31, 2015:

Property	Operator			Ownership Interest			Total Gross Acres			Total Gross Developed Acres			Gross Productive Wells
Los Picachos		Hupecol			12.5	%		86,235			—			—
Macaya		Hupecol			12.5	%		195,201			—			—
Serrania		Hupecol			12.5	%		110,769			—			—
Total								392,205			—			—

At December 31, 2015, we held interests in three concessions operated by Hupecol Operating Co. in Colombia. The Loc Picachos, Macaya and Serrania concessions are located in the Caguan Putumayo Basin of Colombia. The concessions cover an aggregate area of 392,205 acres. Our 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 a field in a concession.

As of December 31, 2015, no wells had been drilled and no production had taken place on any of the fields in our then existing concessions in Colombia. Our estimated net cost associated with planned operations in Colombia during 2016 is approximately $425,000.

As operator of our various prospects, Hupecol has substantial control over the timing of drilling and selection of prospects to be drilled and we have limited ability to influence the selection of prospects to be drilled or the timing of such drilling operations and have no effective means of controlling the costs of such drilling operations. Accordingly, our drilling budget is subject to fluctuation based on the prospects selected to be drilled by Hupecol, the decisions of Hupecol regarding timing of such drilling operations and the ability of Hupecol to drill and operate wells within estimated budgets.

Serrania Block

Our interest in the Serrania concession was acquired through a Farmout Agreement with the original operator of the block pursuant to which 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 concession.

Seismic work on the Serrania Block was completed in 2010. Drilling preparation and seismic processing work was performed in 2011 and 2012 in connection with the planned drilling of initial test wells on the concession. The National Hydrocarbon Agency of Colombia (the “ANH”) has granted extensions of required development commitments, including drilling of a first test well on the Serrania concession, until conditions in the area allow operations.

During 2015, we, through Hupecol, were provided access to, and secured key approvals and local support for commencement of operations on, the Serrania block and commenced pre-drilling road work and environmental work on the Serrania block.

For 2016, Hupecol has advised us that they plan to complete pre-drill operations and to drill a first exploratory well on the Serrania concession with drilling operations targeted to commence by the end of the first quarter. Subject to prevailing conditions, drilling of a second well on the Serrania concession is planned during 2016. Hupecol had previously advised that those same planned operations would take place during prior years. Hupecol’s plans for 2016 may change based on commodity prices, field conditions and other factors beyond our control or the control of Hupecol.

Los Picachos and Macaya Prospects

Our Los Picachos and Macaya prospects adjoin our Serrania concession. Hupecol has advised us that they plan to begin seismic preparation on the Los Picachos and Macaya concessions during 2016, subject to conditions in the area allowing operations. The ANH has granted extensions of required development commitments, including seismic acquisition, until conditions in the area allow operations.

Planned Australian Investment

In February 2016, we entered into an agreement to acquire, for $1,000,000, a 12.5% equity ownership interest in Tamboran Resources Limited, an Australian oil and gas company (“Tamboran”), with certain anti-dilution rights for a period of nine months. Closing of the planned acquisition of the interest in Tamboran is subject to satisfaction of certain conditions by Tamboran, including the receipt by Tamboran of funding from investors other than Houston American Energy in an amount not less than A$705,000.

Tamboran holds interests ranging from 25% to 100% in blocks covering multi-million acres in Australia. Tamboran’s primary efforts are focused in the Beetaloo/McArthur Basin in the Northern Territory of Australia where an initial well has been drilled and logged and is awaiting completion and commencement of production.

Drilling Activity

During 2015, we participated in the drilling of a total of two gross wells, both in the United States. Both of those wells were classified as exploratory wells and were dry holes. The following table summarizes the number of wells drilled during 2015, 2014, and 2013, excluding any wells drilled under farmout agreements, royalty interest ownership, or any other wells in which we do not have a working interest.

	Year Ended December 31,
	2015						2014						2013
	Gross			Net			Gross			Net			Gross			Net
Development wells, completed as:
Productive		—			—			1			0.1094			—			—
Non-productive		—			—			—			—			—			—
Total development wells		—			—			1			0.1094			—			—
Exploratory wells, completed as:
Productive		—			—			7(1	)		0.6244			1			0.03
Non-productive		2			0.11375			5			1.2095			—			—
Total exploratory wells		2			0.11375			12			1.8339			1			0.03

(1)

Includes one well successfully completed and subsequently shut-in and one well successfully completed and temporarily abandoned.

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, 2015, we had no wells in progress or awaiting hook up.

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, 2015, we owned interests in nine gross wells. As of December 31, 2015, we had ownership interests in productive wells, categorized by geographic area, as follows:

	Oil Wells			Gas Wells
United States
Gross		7			2
Net		0.31			0.16
Colombia
Gross		—			—
Net		—			—
Total
Gross		7			2
Net		0.31			0.16

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, 2015:

	Year Ended December 31,
	2015			2014			2013
Net Production:
Gas (Mcf):
United States		32,146			12,717			9,459
Colombia		—			—			—
Total		32,146			12,717			9,459
Oil (Bbls):
United States		6,068			3,152			2,963
Colombia		—			—			—
Total		6,068			3,152			2,963
Average sales price:
Gas ($ per Mcf)
United States	$	3.23		$	4.80		$	4.32
Colombia		—			—			—
Total	$	3.23		$	4.80		$	4.32
Oil ($ per Bbl)
United States	$	53.64		$	95.95		$	103.36
Colombia		—			—			—
Total	$	53.64		$	95.95		$	103.36
Average production costs ($ per BOE):
United States	$	8.60		$	13.65		$	18.01
Colombia		—			—			—
Total	$	8.60		$	13.65		$	18.01

Natural Gas and Oil Reserves

Reserve Estimates

The following tables sets forth, by country and as of December 31, 2015, 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.

	Reserves (1)
	Oil			Natural Gas			Total (2)
	(bbls)			(mcf)			(boe)
Reserve category
Proved Developed
United States		8,850			57,700			18,467
Colombia		—			—			—
Total Proved Developed Reserves		8,850			57,700			18,467
Proved Undeveloped
United States		—			—			—
Colombia		—			—			—
Total Proved Undeveloped Reserves		—			—			—
Total Proved Reserves		8,850			57,700			18,467

	Proved Developed			Proved Undeveloped			Total Proved
PV-10 (1)	$	254,380		$	—		$	254,380
Standardized measure (3)	$	254,380		$	—		$	254,380

(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, 2015. 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, 2015. The average prices utilized for purposes of estimating our proved reserves were $50.13 per barrel of oil and $2.63 per mcf of natural gas for our US 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.

(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.

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. Lonquist & Co. also prepares reserve estimates for the various Hupecol entities. 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 President for 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 30 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 allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Lonquist & 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.

Proved Undeveloped Reserves

As of December 31, 2015 and 2014, we had no proved undeveloped reserves.

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, 2015:

	Developed						Undeveloped
	Gross			Net			Gross			Net
United States		5,255			184.5			1,229			34
Colombia		—			—			392,205			49,025
Total		5,255			184.5			393,434			49,059

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.

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, 2015, the expiration periods of the gross and net acres that are subject to leases or concessions summarized in the above table of undeveloped acreage.

	Undeveloped Acres Expiring
Twelve Months Ending:	Gross			Net
December 31, 2016		—			—
December 31, 2017		1,229			34
December 31, 2018		—			—
December 31, 2019		—			—
December 31, 2020 and later		392,205			49,025
Total		393,434			49,059

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, 2015, we had no contractual agreements to sell our gas and oil production and all production was sold on spot markets.

Employees

As of December 31, 2015, we had three 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.

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:

•

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.

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

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

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

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

Federal, state and local laws and regulations are increasingly being enacted to address concerns about the effects the emission of “greenhouse gases” may have on the environment and climate worldwide. These effects are widely referred to as “climate change.” Since its December 2009 endangerment finding regarding the emission of greenhouse gases, the EPA has begun regulating sources of greenhouse gas emissions under the federal Clean Air Act. Among several regulations requiring reporting or permitting for greenhouse gas sources, the EPA finalized its “tailoring rule” in May 2010 that determines which stationary sources of greenhouse gases are required to obtain permits to construct, modify or operate on account of, and to implement the best available control technology for, their greenhouse gases. In November 2010, the EPA also finalized its greenhouse gas reporting requirements, beginning in March 2012, for certain oil and gas production facilities.

Moreover, in recent past the U.S. Congress has considered establishing a cap-and-trade program to reduce U.S. emissions of greenhouse gases. Under past proposals, the EPA would issue or sell a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of such legislation, if ever adopted, would be to impose increasing costs on the combustion of carbon-based fuels such as crude oil, refined petroleum products, and natural gas. In addition, while the prospect for such cap-and-trade legislation by the U.S. Congress remains uncertain, several states have adopted, or are in the process of adopting, similar cap-and-trade programs.

As a crude oil and natural gas company, the debate on climate change is relevant to our operations because the equipment we use to explore for, develop and produce crude oil and natural gas emits greenhouse gases. Additionally, the combustion of carbon-based fuels, such as the crude oil and natural gas we sell, emits carbon dioxide and other greenhouse gases. Thus, any current or future federal, state or local climate change initiatives could adversely affect demand for the crude oil and natural gas we produce by stimulating demand for alternative forms of energy that do not rely on the combustion of fossil fuels, and therefore could have a material adverse effect on our business. Although our compliance with any greenhouse gas regulations may result in increased compliance and operating costs, we do not expect the compliance costs for currently applicable regulations to be material. Moreover, while it is not possible at this time to estimate the compliance costs or operational impacts for any new legislative or regulatory developments in this area, we do not anticipate being impacted to any greater degree than other similarly situated competitors.

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. Information contained on our website is not incorporated by reference into this report and you should not consider information contained on our website as part of this report.

Item 1A.

Risk Factors

Our business activities and the value of our securities are subject to significant hazards and risks, including those described below. If any of such events should occur, our business, financial condition, liquidity and/or results of operations could be materially harmed, and holders and purchasers of our securities could lose part or all of their investments.

We have had limited operating revenues and have incurred losses from operations for an extended period.

Since our 2010 sale of certain operating assets in Colombia, we have had limited operating revenues and have incurred recurring losses from operations. Unless and until we are successful in growing our production through drilling, acquisition or otherwise, we expect to continue to experience limited operating revenues and recurring losses from operations.

Our ability to operate profitably and our financial condition are highly dependent on energy prices. A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

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

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

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

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

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

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the level of global oil and natural gas inventories;

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weather conditions;

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technological advances affecting energy consumption; and

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the price and availability of alternative fuels.

Global economic growth drives demand for energy from all sources, including fossil fuels. Should the U.S. and global economies experience weakness, demand for energy may decline. Similarly, should growth in global energy production outstrip demand, excess supplies may arise. Declines in demand and excess supplies may result in accompanying declines in commodity prices and deterioration of our financial position along with our ability to operate profitably and our ability to obtain financing to support operations. With respect to our business, beginning in the second half of 2014 and continuing throughout 2015 and into 2016, declines in demand thought to be associated with slowing economic growth in certain markets coupled with new oil and gas supplies coming on line in recent years has resulted in oil and gas supply exceeding global demand which has, in turn, resulted in a steep decline in prices of oil and natural gas. As a result, our average realized prices for oil and natural gas declined 44% and 33%, respectively from 2014 to 2015. There can be no assurance as to the duration of the current weak price environment, the timing and level of any recovery in prices or the reoccurrence of price weakness in the future.

The ongoing decline in prices has reduced, and any declines that may occur in the future can be expected to reduce, our revenues and profitability as well as the value of our reserves. Such declines adversely affect well and reserve economics and may reduce the amount of oil and natural gas that we can produce economically, resulting in deferral or cancellation of planned drilling and related activities until such time, if ever, as economic conditions improve sufficiently to support such operations. Any 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.

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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delays imposed by or resulting from compliance with regulatory requirements;

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pressure or irregularities in geological formations;

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shortages of or delays in obtaining equipment and qualified personnel;

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equipment failures or accidents;

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adverse weather conditions;

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reductions in oil and natural gas prices;

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title problems; and

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limitations in the market for oil and natural gas.

Cost overruns, curtailments, delays and cancellations of operations as a result of the above factors and other factors common in our industry may materially adversely affect our operating results and financial position and our ability to maintain our interests in prospects.

Our operations in Colombia are subject to uncertainty, delays and other 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.

Armed conflict between government forces and anti-government insurgent groups and illegal paramilitary groups—both funded by the drug trade—has persisted in Colombia for more than 40 years. 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.

Where the local political climate and/or guerilla activity in an area threaten our ability to secure necessary support of the local populace or necessary permits to operate, or our ability to assure the safety of our personnel and/or assets, we have, in the past delayed, and may in the future delay, the commencement of operations on prospects until such concerns are satisfactorily resolved. While our operator works diligently with local and federal officials to overcome such uncertainties and obstacles, there can be no assurance that conditions in the vicinity of our planned operations will ever support exploration and/or development operations with respect to one or multiple prospects. Even though we have conducted successful operations on multiple prospects in Colombia, our current prospects continue to be characterized by political risks and, in fact, our operator has on more than one occasion delayed planned operations on prospects due to such political risks with such delays extending, in some cases, for

multiple years. In the event of continued, or future, delays in operations on prospects arising from political risks, we may experience financial loss associated with our cost of holding prospects, the incurrence of costs associated with addressing political risks or the loss of value associated with our inability to explore and develop potentially valuable prospects.

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 counter-narcotics agreements may result in the loss of certain financial aid and the imposition of trade sanctions.

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 key governmental agencies 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.

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 a number of properties operated by Hupecol and our interest in the assets and operations of Hupecol related entities and ventures represent all of our current assets in Colombia. During 2008, 2010 and 2012, respectively, Hupecol sold its interest in multiple concessions and 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.

In addition to the control exercised by Hupecol with respect to the properties it operates, as minority owners, we are, or may be, subject to substantial control of other properties in Colombia in which we hold interests that are operated by third party operators, other than Hupecol. Our Colombian assets presently consist, and in the future are expected to continue to consist, exclusively of minority, non-operator project interests in certain Colombian assets owned and operated by third party operators. 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 the operators of those properties.

We may be exposed to additional expenses and losses arising from the financial position of our joint interest partners in Colombia.

Our Colombian properties are developed under financial arrangements with various joint interest partners. If other joint interest partners are unable, or unwilling, to satisfy their various obligations relating to prospects, we may be required to pay a proportionately higher share of development costs on those prospects or the prospect may be inadequately capitalized to achieve optimal results.

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.

A substantial percentage of our properties are unproven and undeveloped; therefore the cost of proving and developing our properties and 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 and undeveloped, we require significant capital to prove and develop such properties before they may become productive. Following the sale of our principal producing property in Colombia in March 2012, substantially all of our net acreage was unproven and undeveloped. Because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be successfully drilled and developed to the extent that they result in positive cash flow. Even if we are successful in our drilling and development efforts, it could take several years for a significant portion of our unproven properties to be converted to positive cash flow.

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 potential. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require substantial 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. 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 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 uninsured 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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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;

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abnormally pressured formations;

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

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fires and explosions;

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personal injuries and death; and

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natural disasters.

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. The occurrence of a significant accident or other event that is not fully covered by insurance could have a material adverse effect on our business, results of operations or financial condition.

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:

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the timing and amount of capital expenditures;

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the timing of initiating the drilling and recompleting of wells;

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the extent of operating costs; and

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the level of ongoing production.

Decisions made by our operators may be different than those we would make reflecting priorities different than our priorities and may materially adversely affect our operating results and financial position.

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. If 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.

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, 2010 and 2012 that provided 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. While our reserves, production, operating cash flows and operating profitability have historically grown as properties have been drilled and developed and have fallen following strategic asset divestitures when we are incurring costs to drill and develop properties, there is no assurance that our strategy will produce such results in the future and, in fact, that strategy did not produce new reserves, production, cash flow or profitability when deployed on our CPO 4 prospect. As a result of drilling and other risks, there can be no assurance that our reserve and production growth strategy will allow us to grow, and replace, our acreage position, reserves, production and profitability following divestitures and we may continue to experience large fluctuations in such positions.

Our divestiture strategy exposes us to risks associated with a lack of diversification and a concentration of properties, increased dependence on a small number of properties and disproportionate risk of loss associated with drilling results and operations of one or a small number of properties.

Because a significant element of our strategy has been the opportunistic divestiture of properties and redeployment of resources to new properties, we have historically been focused on development of a small number of geographically concentrated prospects. Accordingly, we lack diversification with respect to the nature and geographic location of our holdings. As a result, we are exposed to higher dependence on individual resource plays and may experience substantial losses should a single individual prospect prove unsuccessful. Absent other operating properties, the failure or underperformance of a single prospect could materially adversely affect our financial resources, reserve and production outlook and profitability. In particular, during 2011 and 2012 we committed a substantial portion of the proceeds received from our 2010 divestiture of Hupecol properties to a drilling program on our CPO 4 prospect. Between 2011 and 2012, we participated in the drilling of three test wells on our CPO 4 prospect, each of which was determined to be noncommercial and, ultimately, plugged and abandoned. Given our focus on

development of the CPO 4 prospect, including the commitment of substantial financial resources and the lack of current production from our other prospects, the failure to complete a commercial well on the prospect materially adversely affected our financial position and operating outlook.

Our audit report includes a “going concern” paragraph; we may need additional financing to support operations and future capital commitments.

As a result of continuing operating losses, low energy prices and financial commitments, our financial statements include a going concern qualification reflecting substantial doubt as to our ability to continue as a going concern. Our estimated drilling budget for 2016 is $425,000, principally relating to the preparation for drilling, and drilling, of one test well on the Serrania prospect. Our drilling budget can vary substantially based on the timing and results of drilling operations as well as determinations to participate in the drilling and development of new prospects. With our planned purchase of an interest in Tamboran Resources, we may be required to seek additional capital, to divest certain assets or to curtail certain expenditures pending the commencement of revenues, if any, from planned drilling operations on the Serrania prospect. We have no commitments to provide any additional financing and there is no guarantee that we will be able to secure additional financing on acceptable terms, or at all, if needed to fully fund our 2016 drilling budget and to support future operations.

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

Market conditions or the unavailability of satisfactory transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business.

We may operate in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. This may be particularly true with respect to our operations in Colombia where infrastructure is limited or, in some cases, non-existent. Such restrictions on our ability to sell our oil or natural gas could have several adverse effects, 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.

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 wrote down the carrying value of our oil and natural gas properties during 2015 and may be required to further write down the carrying value of oil and gas properties in the future. 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, requiring 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.

The present value of future net revenues from our proved reserves, as reported from time to time, should not be assumed to be 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 may be exposed to substantial fines and penalties if we or our partners fail to comply with laws and regulations associated with our activities in foreign countries, including Colombia, regarding U.S. laws such as the Foreign Corrupt Practices Act and local laws prohibiting corrupt payments to governmental officials and other corrupt practices.

Our Colombian assets constitute our principal assets and consist exclusively of minority, non-operator project interests. Third parties act as the operator of each of our oil and gas wells and control all drilling and operating activities conducted with respect to our Colombian properties. Therefore, we have limited control over decisions related to activities on our properties, and we cannot provide assurance that our partners or their employees, contractors or agents will not take actions in violation of applicable anti-corruption laws and regulations. In the course of conducting business in Colombia, we have relied primarily on the representations and warranties made by our operating and non-operating partners in the farmout and joint operating agreements which govern our respective project interests to the effect that:

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each party has not and will not offer or make payments to any person, including a government official, that would violate the laws of the country of operations, the country of formation of any of the partners or the principals described in the Convention on Combating Bribery of Foreign Public Officials in International Business Transactions; and

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each party will maintain adequate internal controls, properly record and report all transactions and comply with the laws applicable to the transaction.

While we periodically inquire as to the continuing accuracy of these representations, as a minority non-operator, we are limited in our ability to assure compliance. Consequently, we cannot provide assurance that the procedural safeguards, if any, adopted by our partners or the representations and warranties contained in these agreements and our reliance on them will protect us from liability should a violation occur. Any violations of the anti-bribery, accounting controls or books and records provisions of the Foreign Corrupt Practices Act by us or our partners could subject us and, where deemed appropriate, individuals, in certain cases, to a broad range of civil and criminal penalties, including but not limited to, imprisonment, injunctive relief, disgorgement, substantial fines or penalties, prohibitions on our ability to offer our products in one or more countries, imposed modifications to business practices and compliance programs, including retention of an independent monitor to oversee compliance, and could also materially damage our reputation, our business and our operating results.

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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require the acquisition of a permit before drilling commences;

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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;

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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

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impose substantial liabilities for pollution resulting from operations.

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

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

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incurring investigatory or remedial obligations; and

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the imposition of injunctive relief.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to 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.

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.

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.

Our success depends on our staff, which is small in size and limited in technical capabilities, and third party consultants, the loss of any of whom could disrupt our business operations.

Our success will depend on our ability to attract and retain key staff members. Our staff is extremely small in size and possesses limited technical capabilities. We do not presently maintain any significant internal technical capabilities but rely on the engineering, geological and other technical skills of our board and, from time to time, third party consultants. If members of our staff should resign or we are unable to attract the necessary personnel, our business operations could be adversely affected.

The price of our common stock may fluctuate significantly, and this may make it difficult to resell common stock when, or at prices, desired.

The price of our common stock constantly changes. We expect that the market price of our common stock will continue to fluctuate.

Our stock price may fluctuate as a result of a variety of factors, many of which are beyond our control. These factors include:

•

quarterly variations in our operating results;

•

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

•

changes in expectations as to our future financial performance;

•

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

•

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

•

future sales of our equity or equity-related securities;

•

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

•

fluctuations in oil and gas prices;

•

departures of key personnel; and

•

regulatory considerations.

Our stock has suffered significant declines over the past several years mirroring, among other things, the delays in drilling and ultimate determination to cease completion efforts on test wells on the CPO 4 prospect and the announcement that the SEC was conducting an investigation of our company and the steep decline in oil and natural gas prices commencing in the second half of 2014.

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.

Continued operating losses and declines in our stock price may result in the loss of our exchange listing.

Our common stock currently trades on the NYSE MKT. The NYSE MKT imposes various quantitative and qualitative requirements to maintain listing, including minimum stock price, market value and stockholders’ equity requirements. As a result of our operating losses in recent years and declining market price and stockholders’ equity, our continued eligibility for listing on the NYSE MKT may be subject to review and, if we are unable to satisfy the continued listing requirements of the NYSE MKT, our common stock may be subject to delisting. In the event of delisting, our stockholders may experience decreased liquidity.

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:

•

authorize our board of directors to issue “blank check” preferred stock, which is preferred stock that can be created and issued by our board of directors, without stockholder approval, with rights senior to those of our common stock;

•

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

•

provide that directors may be removed only for cause; and

•

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

We are also subject to anti-takeover provisions under Delaware law, which could also delay or prevent a change of control. Taken together, these provisions of our charter, 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.

There can be no assurance as to the consummation of our planned investment in Tamboran or our ability to monetize, or timing of monetizing, such planned investment.

In February 2016, we agreed to purchase a 12.5% interest in Tamboran, in order to secure an indirect interest in a portfolio of Australian assets. Closing of the acquisition of such interest is subject to satisfaction of various conditions on the part of Tamboran, including the receipt of funding in an amount not less than A$705,000 from investors other than Houston American Energy. There can be no assurance that the conditions of closing will be satisfied or that we will ultimately acquire the described interest in Tamboran. In order to realize a return of, or return on, our planned investment in Tamboran, we must receive proceeds from dividends or the sale of Tamboran shares. Tamboran is an early stage company that has not to date paid dividends or operated profitably and there is presently no trading market for Tamboran shares. There can be no assurance that Tamboran will ever pay any dividends or other distributions to its shareholders or that we will be able to sell our Tamboran shares if and when we desire to sell. We will be dependent upon the efforts of Tamboran to successfully explore and develop its prospects so as to either

generate profits and cash flow to support dividends or distributions or to generate value that may give rise to potential purchasers of Tamboran shares. Should Tamboran fail to operate profitably or to prove the existence of substantial reserves on its properties or should Tamboran elect to retain profits to support growth or should a market for the shares of Tamboran fail to develop, we may be required to hold any Tamboran shares we may acquire for an indefinite period of time or may realize proceeds from our investment that are less than our proportionate share of the value of Tamboran’s underlying assets or may realize a loss of some or all of our investment.

Item 1B.

Unresolved Staff Comments

Not applicable.

Item 2.

Properties

We currently lease approximately 4,739 square feet of office space in Houston, Texas as our executive offices. Management anticipates that our space will be sufficient for the foreseeable future. The average monthly rental under the lease, which expires on May 31, 2017, is $7,701. A description of our interests in oil and gas properties is included in “Item 1. Business.”

Item 3.

Legal Proceedings

We may from time to time be a party to lawsuits incidental to our business. As of March 8, 2016, we were not aware of any current, pending or threatened litigation or proceedings that could have a material adverse effect on our results of operations, cash flows or financial condition.

Item 4.

Mine Safety Disclosures

Not applicable.

PART II

Item 5.

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

Market Information

Our common stock is listed on the NYSE MKT under the symbol “HUSA.” The following table sets forth the range of high and low sale prices of our common stock for each quarter during the past two fiscal years.

		High			Low
Calendar Year 2015	Fourth Quarter	$	0.20		$	0.16
	Third Quarter		0.23			0.16
	Second Quarter		0.23			0.18
	First Quarter		0.25			0.16
Calendar Year 2014	Fourth Quarter	$	0.32		$	0.12
	Third Quarter		0.49			0.18
	Second Quarter		0.58			0.38
	First Quarter		0.75			0.24

At March 8, 2016, the closing price of the common stock on NYSE MKT was $0.198 per share.

Holders

As of March 8, 2016, there were approximately 879 shareholders of record of our common stock.

Dividends

No dividends were paid during calendar years 2014 or 2015. 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, 2015 with respect to the shares of our common stock that may be issued under our existing equity compensation plans.

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)			Weighted-average exercise price of outstanding options, warrants and rights (b)			Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders (1)		4,432,165		$	2.47			1,567,835
Equity compensation plans not approved by security holders		—			—			—
		4,432,165		$	2.47			1,567,835

(1)

Consists of 51,000 shares reserved for issuance pursuant to outstanding options granted under the Houston American Energy Corp. 2005 Stock Option Plan and 6,000,000 shares reserved for issuance under the Houston American Energy 2008 Equity Incentive Plan.

Issuer Purchases of Equity Securities

On November 13, 2015, we announced that our Board of Directors had authorized the repurchase of up to 3,000,000 shares of our common stock. Any repurchases under the authorization may be made in open market purchases, block trades or privately negotiated transactions, subject to market conditions and our ongoing determination that it is the best use of available cash. During the fourth quarter of 2015, we purchased 190,000 shares of our common stock through open market transactions.

Period	Total number of shares purchased			Average price paid per share			Total number of shares purchased as part of publicly announced plans or programs			Maximum number of shares that may be purchased under the plans or programs
11/13/15 – 12/21/15		190,000		$	0.20			190,000			3,000,000
Total		190,000		$	0.20			190,000			3,000,000

Item 6.

Selected Financial Data

Not applicable.

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

We are an independent energy company focused on the development, exploration, exploitation, acquisition, and production of natural gas and crude oil properties 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

Commodity Pricing

Steep declines in the price of oil and natural gas during 2015 adversely affected our revenues, profitability and financial position, and resulted in an impairment charge with respect to our oil and gas assets. Average realized prices from sales our oil and natural gas declined by 44% and 33%, respectively, from 2014 to 2015.

Drilling and Related Activity

With the weakness in oil and natural gas prices, we curtailed drilling activity during 2015, drilling two domestic wells, both dry holes.

At December 31, 2015, we had no drilling operations in progress.

During 2015, our capital investment expenditures in Colombia related to the preparation and evaluation of our three concessions in Colombia totaled $79,511. Capital expenditures during 2015 related to permitting, pre-drilling road work and environmental work on the Serrania concession. Hupecol, the operator of our Colombian concessions, has advised that they intend to complete pre-drilling work and to drill a first test well on the Serrania concession during the first quarter of 2016. Our estimated share of costs associated with drilling the first test well on the Serrania concession, above and beyond expenditures through December 31, 2015, is approximately $425,000.

Hupecol has also advised that it plans, during 2016, to begin seismic work on the Los Picachos and Macaya concessions.

Hupecol’s plans with respect to our Colombian concessions may change based on field conditions and other factors beyond our control or the control of Hupecol.

Leasehold Developments

During 2015, we disposed of some or all of our interest in three non-producing domestic prospects for which we received $56,705 of proceeds. Proceeds received from disposal of such interests were accounted for as a reduction in capitalized cost of oil and gas properties.

With the continuing weakness in oil and natural gas prices, we are not presently planning additional domestic drilling operations during 2016. We intend to evaluate other opportunities that may arise in the domestic energy sector, including possible acquisitions of non-core assets and other assets that may become available as other operators divest or otherwise address excess leverage and other issues in the current low price environment.

Settlement of SEC Administrative Proceeding

Our prior SEC administrative proceeding was settled in April 2015. As a result of that settlement, among other things, we paid a penalty in the amount of $400,000. The penalty and associated expense were recorded during 2014.

Settlement of Shareholder Class Action Suit

Final settlement of our prior shareholder class action suit was approved in July 2015. As a result of that settlement, among other things, we paid a settlement of $7,000,000 which was fully funded by insurance. The settlement was recorded during 2014. The associated settlement payable, accrued legal fees payable and insurance claim receivable were each reflected as settled on our balance sheet at December 31, 2015.

Changes in Officers and Directors

Under the terms of the settlement of our prior SEC administrative proceeding, John Terwilliger, our prior Chairman and Chief Executive Officer, resigned from all positions as an officer and director of our company.

In connection with the resignation of John Terwilliger: (1) John Boylan, a current director, was appointed Chairman, President and Chief Executive Officer of the company; (2) an additional independent director was appointed to fill the vacancy created by Mr. Terwilliger’s resignation; and (3) we agreed to continue to employ Mr. Terwilliger in a non-executive capacity to assist in the management transition through at least December 31, 2015.

Mr. Boylan’s compensation, in addition to benefits generally provided to company employees, consists of: (1) an annual base salary of $120,000; and (2) a ten-year stock option grant, exercisable at fair market value on the date of grant, to purchase 900,000 shares of our common stock. The stock option vests 1/3 on each of the first three anniversaries of the date of grant subject to accelerated vesting upon either (i) our receipt, on or after the grant date and during the term of Mr. Boylan’s employment, of $10 million or more of aggregate gross proceeds from the sale of equity securities or securities convertible into equity securities, or (ii) our acquisition, on or after the grant date and during the term of Mr. Boylan’s employment, of $10 million or more in aggregate purchase price of oil and gas properties.

Escrow Settlements

During 2015, we received $59,412 in partial settlement of our escrow receivable relating to properties sold in previous years.

Planned Tamboran Investment

In April 2016, we agreed to acquire a 12.5% equity ownership interest in Tamboran Resources Limited for $1,000,000. Closing of the planned acquisition of the interest in Tamboran is subject to satisfaction of certain conditions by Tamboran, including the receipt by Tamboran of funding from investors other than Houston American Energy in an amount not less than $705,000.

Critical Accounting Policies

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

Full Cost Method of Accounting for Oil and Gas Activities. We follow the full cost method of accounting for oil and gas property acquisition, exploration and development activities. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisition, geological and geophysical work, delay rentals, costs of drilling, completing and equipping successful and unsuccessful oil and gas wells and related internal costs that can be directly identified with acquisition, exploration and development activities, but does not include any cost related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized unless significant amounts of oil and gas reserves are involved. No corporate overhead has been capitalized as of December 31, 2015. 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, 2015 and 2014:

	At December 31, 2015			At December 31, 2014
Acquisition costs	$	902,864		$	1,009,620
Evaluation costs		1,976,199			2,576,664
Total	$	2,879,063		$	3,586,284

The carrying value of unevaluated oil and gas prospects includes $79,511 and $2,034,008 expended for properties in South America at December 31, 2015 and December 31, 2014, 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 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. Changes in the subjective assumptions can materially affect the estimated fair value of stock-based compensation and consequently, the related amount recognized on the Statements of Operations.

Results of Operations

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

Oil and Gas Revenues. Total oil and gas revenues increased 18.2%, to $429,435 in 2015 from $363,455 in 2014.

The increase in revenue was due to production from new wells brought on line during 2014, partially offset by a decrease in average sales price.

The following table sets forth the gross and net producing wells, net oil and gas production volumes and average hydrocarbon sales prices for 2015 and 2014:

	2015			2014
Gross producing wells		9			11
Net producing wells		0.47			0.72
Net oil production (Bbls)		6,068			3,152
Net gas production (Mcf)		32,146			12,717
Oil—Average sales price per barrel	$	53.64		$	95.95
Gas—Average sales price per mcf	$	3.23		$	4.80

The decline in gross and net producing wells reflects two wells that were no longer economical to produce.

The change in average sales prices realized reflects fluctuations in global commodity prices. During the fourth quarter of 2014 and continuing through 2015, commodity prices declined sharply.

Oil and gas sales revenues for 2015 and 2014 by region were as follows:

	Colombia			U.S.			Total
2015
Oil sales	$	—		$	325,504		$	325,504
Gas sales	$	—		$	103,931		$	103,931
2014
Oil sales	$	—		$	302,460		$	302,460
Gas sales	$	—		$	60,995		$	60,995

Lease Operating Expenses. Lease operating expenses, excluding joint venture expenses relating to our Colombian operations discussed below, increased 30.8% to $148,067 in 2015 from $113,233 in 2014.

The increase in total lease operating expenses was attributable to operation of new wells brought on production during 2014.

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

	Colombia			U.S.			Total
2015	$	—		$	148,067		$	148,067
2014	$	—		$	113,233		$	113,233

Consistent with our business model and operating history, we experience steep declines in lease operating expenses following strategic divestitures and anticipate lease operating expenses to ramp up to levels consistent with regional costs as new wells are brought on line. With the planned drilling of our Serrania prospect, assuming a successful well is drilled, lease operating expenses in Colombia and overall, are expected to increase in 2016.

Depreciation and Depletion Expense. Depreciation and depletion expense increased by 110% to $756,757 in 2015 from $359,897 in 2014. The increase in depreciation and depletion was due to an increase in the cost pool and increased production attributable to additional wells brought on line during 2014.

Impairment of Oil and Gas Properties. We reported an impairment charge of $1,718,088 during 2015 as compared to an impairment charge of $1,492,148 during 2014. The charges in both years resulted from the effects of steeply lower commodity prices when applying the ceiling test under the full cost method of accounting.

General and Administrative Expenses. General and administrative expense decreased by 31.4% to $1,541,294 in 2015 from $2,246,519 in 2014. The change in general and administrative expense reflects a combination of (1) a reduction in stock compensation of $359,384, (2) a reduction in directors and officers insurance of $238,424, and (3) a reduction in legal fees of $235,172.

Other Income (Expense). Other income (expense) consists of interest earned on cash balances net of other bank fees, currency losses relating to funds held for operations in Colombia and a contingent loss relating to the

Company’s SEC settlement. Net other income (expense) totaled $(76,570) in 2015 as compared to $(392,654) in 2014. The change was attributable to higher interest rates received on bank deposits offset by a currency loss of $97,103 during 2015 and a contingent loss relating to the SEC settlement of $400,000 during 2014.

Income Tax Expense/Benefit. We reported income tax expense of $18,865 in 2015 as compared to $2,183 in 2014.

Financial Condition

Liquidity and Capital Resources. At December 31, 2015, we had a cash balance of $2,123,520 and working capital of $2,384,283 compared to a cash balance of $4,052,212 and working capital of $3,796,817 at December 31, 2014. The decrease in cash and working capital during 2015 was attributable to the operating loss during 2015 and investments in our drilling program.

Cash Flows. Operating activities used $1,837,977 during 2015 compared to $1,747,625 of cash used during 2014. The change in cash used in operations was primarily attributable to a decreased loss during 2015 which was offset by a decrease in non-cash charges and a reduction in accounts payable and accrued expenses.

Investing activities used $52,565 of cash during 2015 compared to $1,778,893 of cash used during 2014. The decrease in cash used in investing activities reflects substantially reduced investments in oil and gas properties, down $3,196,252, and the receipt of $56,705 from the sale of our interest in three non-producing properties, partially offset by a decrease of $59,412 in funds released to us from escrow relating to prior sales of oil and gas interests.

Financing activities used $38,152 of cash during 2015 compared to $0 used during 2014. In 2015, financing activities consisted of open market purchases of 190,000 shares of treasury stock.

Long-Term Liabilities. At December 31, 2015, we had long-term liabilities of $25,262 as compared to $28,147 at December 31, 2014. Long-term liabilities consisted of a reserve for plugging costs.

Capital and Exploration Expenditures. During 2015, we invested $168,680 for the development of oil and gas properties, consisting of (1) preparation and evaluation costs in Colombia of $79,367, and (2) costs on U.S. properties of $89,313. Of the amount invested, we capitalized $89,169 to oil and gas properties subject to amortization, and $144 to oil and gas properties not subject to amortization.

Planned Capital and Exploration Spending. Our principal capital and exploration expenditures relate to ongoing efforts to acquire, drill and complete prospects. We expect that future capital and exploration expenditures will be funded principally through funds on hand.

Our estimated capital expenditure budget for 2016 is approximately $425,000 and relates to pre-drill work for, and drilling of, an initial test well on the Serrania concession. Additionally, in February 2016, we agreed to acquire, for $1,000,000, a 12.5% equity ownership interest in Tamboran. We may consider additional opportunistic investments in other oil and natural gas properties where continued depressed energy prices present favorable opportunities, although we have no present commitment or plans in that regard. Drilling and other plans for 2016 may change based on field conditions and other factors beyond our control or the control of the operators of our prospects and, as such, there can be no assurance as to the timing of these operations or the amount actually spent on such operations.

Depending on the timing and ultimate closing of our planned investment in Tamboran, the timing of drilling operations on the Serrania concession and the timing and amount of receipt of payments from production, if any, from the initial Serrania well, our cash on hand may not be adequate to fully fund our operations during 2016, including our capital expenditure budget. Depending on the ultimate cost and results of our drilling operations, we may require additional capital to fully fund our future drilling budget and operations. If, for any reason, we are unable to fully fund our drilling budget and fail to satisfy commitments reflected therein, we may be subject to penalties or to the possible loss of some of our rights and interests in prospects with respect to which we fail to satisfy funding commitments. 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 fully fund our drilling budget and to support future acquisitions and development activities.

Outlook

Continued low oil and natural gas prices during 2015 and recurring delays in drilling of our Serrania prospect in Colombia have had a significant adverse impact on our business. Our financial statements include a “going

concern” qualification reflecting substantial doubt as to our ability to continue as a going concern. While we have no debt and have reduced our overhead, we continue to operate at a loss in the current low price environment. We have budgeted $425,000 for drilling of a first test well on our Serrania prospect during 2016 and $1,000,000 for the planned 2016 acquisition of an interest in Tamboran Resources Limited. Given those financial commitments and continuing negative cash flow from operations, depending upon the timing and ultimate drilling results on our Serrania prospect, we may be required to seek additional financing or may be divest certain assets in order to support operations until such point, if ever, as our revenues increase sufficiently, either through price increases or the addition of production from Serrania, to cover our operating costs and overhead. We can provide no assurance that our efforts will be sufficient to reverse the trend of operating losses or to provide adequate financial resources to sustain operations and retention of our assets pending attainment of profitable operations.

Contractual Obligations. At December 31, 2015, 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, 2015:

	Payments due by period
	Total			< 1 year			1-3 years			3-5 years			> 5 years
Operating leases	$	136,631		$	96,162		$	40,469		$	—		$	—
Total	$	136,631		$	96,162		$	40,469		$	—		$	—

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. All present and future prospects in Colombia are subject to a 1.5% ORRI in favor of each of a current director and our former Chairman and Chief Executive Officer.

Additionally, during 2013, we adopted our Production Incentive Compensation Plan pursuant to which up to 2% of our share of revenues from qualifying domestic properties may be paid as compensation to recipients of award grants under the plan.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements or guarantees of third party obligations at December 31, 2015.

Inflation

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

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

The price we receive for our oil and gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Crude oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and gas have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for production depends on numerous factors beyond our control.

We have not historically entered into any hedges or other derivative commodity instruments or transactions designed to manage, or limit exposure to oil and gas price volatility.

Item 8.

Financial Statements and Supplementary Data

Our financial statements appear immediately after the signature page of this report. See “Index to Financial Statements” on page F-1.

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A.

Controls and Procedures

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, 2015 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, who also serves as our principal financial officer, concluded that our disclosure controls and procedures were not effective as of December 31, 2015.

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 officer, who also serves as principal financial officer, 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 not effective as of December 31, 2015. Such conclusion reflects our chief executive officer’s assumption of duties of the principal financial officer and the resulting lack of segregation of duties. Until we are able to remedy these material weaknesses, we are relying on third party consultants to assist with financial reporting.

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

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the fourth quarter of 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.

Other Information

Not applicable

PART III

Item 10.

Directors, Executive Officers and Corporate Governance

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

Executive Officers

Our executive officers as of December 31, 2015, and their ages and positions as of that date, are as follows:

Name	Age	Position
John P. Boylan	49	President, Chief Executive Officer and Chairman

John P. Boylan has served as our President, CEO and Chairman since April 2015 and as a director since 2006. Since 2008, Mr. Boylan has owned and operated EJC Ventures, LP, a financial and management consulting firm providing executive and financial management, asset management, corporate finance, risk management, complex

financial reporting, crisis management and turnaround services to the oil and gas industry. Mr. Boylan holds a BBA with a major in Accounting from the University of Texas and an MBA with majors in Finance, Economics and International Business from New York University. Mr. Boylan is a licensed CPA in the State of Texas.

There are no family relationships among the executive officers and directors. Except as otherwise provided in employment agreements, each of the executive officers serves at the discretion of the Board.

Item 11.

Executive Compensation

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.

Item 12.

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

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.

Item 13.

Certain Relationships and Related Transactions, and Director Independence

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.

Item 14.

Principal Accountant Fees and Services

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.

PART IV

Item 15.

Exhibits and Financial Statement Schedules

1. Financial statements. See “Index to Financial Statements” on page F-1.

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	08/03/01	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	08/03/01	4.1
10.1	Houston American Energy Corp. 2005 Stock Option Plan*	8-K	08/16/05	10.1
10.2	Form of Director Stock Option Agreement*	8-K	08/16/05	10.2
10.3	Houston American Energy Corp. 2008 Equity Incentive Plan*	Sch 14A	04/28/08	Ex A
10.4	Form of Change in Control Agreement, dated June 11, 2012*	8-K	06/14/12	10.1
10.5	Production Incentive Compensation Plan*	10-Q	08/14/13	10.1
10.6	Offer Letter – Subscription for fully paid ordinary shares of Tamboran Resources Limited, dated February 22, 2016	8-K	02/24/16	10.1
14.1	Code of Ethics for CEO and Senior Financial Officers	10-KSB	03/26/04	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 and CFO				X
32.1	Section 906 Certification of CEO and CFO				X
99.1	Code of Business Ethics	8-K	07/07/06	99.1
99.2	Report of Lonquist & Co., LLC				X

*

Compensatory plan or arrangement.

SIGNATURES

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

	HOUSTON AMERICAN ENERGY CORP.
Dated: March 17, 2016
	By:	/s/ John P. Boylan
		John P. Boylan President

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.

Signature	Title	Date
/s/ John P. Boylan	Chairman, Chief Executive Officer, President and Director (Principal Executive Officer and Principal Financial Officer)	March 17, 2016
John P. Boylan
/s/ O. Lee Tawes, III	Director	March 17, 2016
O. Lee Tawes, III
/s/ Stephen Hartzell	Director	March 17, 2016
Stephen Hartzell
/s/ Roy Jageman	Director	March 17, 2016
Roy Jageman
/s/ Keith Grimes	Director	March 17, 2016
Keith Grimes

HOUSTON AMERICAN ENERGY CORP.
INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2015 and 2014		F-3
Consolidated Statements of Operations For the Years Ended December 31, 2015 and 2014		F-4
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2015 and 2014		F-5
Consolidated Statements of Cash Flows For the Years Ended December 31, 2015 and 2014		F-6
Notes to Consolidated Financial Statements		F-7

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
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, 2015 and 2014, and the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for the years ended December 31, 2015 and 2014. 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 audit.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, 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, 2015 and 2014, and the results of their operations and their cash flows for the years ended December 31, 2015 and 2014, in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, The Company has suffered recurring losses from operations, which raises substantial doubt about its ability to continue as a going concern. Management’s plans regarding those matters are described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ GBH CPAs, PC
www.gbhcpas.com
Houston, Texas

March 17, 2016

HOUSTON AMERICAN ENERGY CORP.
CONSOLIDATED BALANCE SHEETS

	December 31,
	2015			2014
ASSETS
CURRENT ASSETS
Cash	$	2,123,520		$	4,052,212
Escrow receivable		262,016			321,428
Insurance claim receivable		—			8,612,681
Prepaid expenses and other current assets		38,257			124,960
TOTAL CURRENT ASSETS		2,423,793			13,111,281
PROPERTY AND EQUIPMENT
Oil and gas properties, full cost method
Costs subject to amortization		54,840,599			54,025,617
Costs not being amortized		2,879,063			3,586,284
Office equipment		90,004			90,004
Total		57,809,666			57,701,905
Accumulated depletion, depreciation, amortization, and impairment		(54,676,723	)		(52,201,878	)
PROPERTY AND EQUIPMENT, NET		3,132,943			5,500,027
Other assets		3,167			3,167
TOTAL ASSETS	$	5,559,903		$	18,614,475
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	23,195		$	181,683
Litigation settlement payable		—			7,000,000
Accrued legal fees		—			1,722,681
Contingent liability		—			400,000
Accrued expenses		16,315			10,100
TOTAL CURRENT LIABILITIES		39,510			9,314,464
LONG-TERM LIABILITIES
Reserve for plugging and abandonment costs		25,262			28,147
TOTAL LIABILITIES		64,772			9,342,611
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS’ EQUITY
Preferred stock, par value $0.001; 10,000,000 shares authorized, 0 shares issued and outstanding		—			—
Common stock, par value $0.001; 150,000,000 shares authorized 52,169,945 shares issued and outstanding		52,170			52,170
Additional paid-in capital		66,019,681			65,928,056
Treasury shares, at cost; 190,000 and 0 shares, respectively		(38,152	)		—
Accumulated deficit		(60,538,568	)		(56,708,362	)
TOTAL SHAREHOLDERS’ EQUITY		5,495,131			9,271,864
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	5,559,903		$	18,614,475

HOUSTON AMERICAN ENERGY CORP.
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

	2015			2014
OIL AND GAS REVENUE	$	429,435		$	363,455
EXPENSES OF OPERATIONS
Lease operating expense and severance tax		148,067			113,233
Depreciation and depletion		756,757			359,897
Impairment of oil and gas properties		1,718,088			1,492,148
General and administrative expense		1,541,294			2,356,519
Total operating expenses		4,164,206			4,321,797
Loss from operations		(3,734,771	)		(3,958,342	)
OTHER INCOME (EXPENSE)
Interest income		20,533			7,349
Contingent loss		—			(400,000	)
Currency valuation loss		(97,103	)		—
Other expense		—			(3	)
Total other expense		(76,570	)		(392,654	)
Loss before taxes		(3,811,341	)		(4,350,996	)
Income tax expense (benefit)		18,865			2,183
Net loss	$	(3,830,206	)	$	(4,353,179	)
Basic and diluted net loss per common share outstanding	$	(0.07	)	$	(0.08	)
Basic and diluted weighted average number of common shares outstanding		52,159,726			52,169,945

HOUSTON AMERICAN ENERGY CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2015 and 2014

							Additional Paid-in Capital									Retained Earnings (Deficit)
	Common Stock									Treasury Stock
	Shares			Amount						Shares			Amount						Total
Balance at December 31, 2013		52,169,945		$	52,170		$	65,477,046			—		$	—		$	(52,355,183	)	$	13,174,033
Options issued to directors		—			—			42,676			—			—			—			42,676
Options issued to employees		—			—			371,513			—			—			—			371,513
Restricted stock issued to employees		—			—			36,821			—			—			—			36,821
Net loss		—			—			—			—			—			(4,353,179	)		(4,353,179	)
Balance at December 31, 2014		52,169,945			52,170			65,928,056			—			—			(56,708,362	)		9,271,864
Options issued to directors		—			—			22,938			—			—			—			22,938
Options issued to employees		—			—			68,687			—			—			—			68,687
Acquisition of treasury shares		—			—			—			190,000			(38,152	)		—			(38,152	)
Net loss		—			—			—			—			—			(3,830,206	)		(3,830,206	)
Balance at December 31, 2015		52,169,945		$	52,170		$	66,019,681			190,000		$	(38,152	)	$	(60,538,568	)	$	5,495,131

HOUSTON AMERICAN ENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

	2015			2014
CASH FLOW FROM OPERATING ACTIVITIES
Net loss	$	(3,830,206	)	$	(4,353,179	)
Adjustments to reconcile net loss to net cash provided by (used in) operations
Depreciation and depletion		756,757			359,897
Impairment of oil and gas properties		1,718,088			1,492,148
Stock-based compensation		91,625			451,010
Accretion of asset retirement obligation		1,329			628
Contingent loss		—			400,000
Change in operating assets and liabilities:
Increase in accounts receivable		—			(83,878	)
Increase (decrease) in insurance receivable		8,612,681			(8,612,681	)
Decrease in prepaid expense and other current assets		86,703			5,093
Decrease in accounts payable and accrued expenses		(552,273	)		(129,344	)
Increase (decrease) in settlement payable		(7,000,000	)		7,000,000
Increase (decrease) in accrued legal fees		(1,722,681	)		1,722,681
Net cash used in operations		(1,837,977	)		(1,747,625	)
CASH FLOW FROM INVESTING ACTIVITIES
Payments for acquisition and development of oil and gas properties and assets		(168,680	)		(3,364,932	)
Proceeds from sale of mineral interest		56,705			—
Proceeds from escrow receivable, net		59,412			1,586,039
Net cash provided by (used in) investing activities		(52,563	)		(1,778,893	)
CASH FLOW FROM FINANCING ACTIVITIES
Payment for acquisition of treasury shares		(38,152	)		—
Net cash used in financing activities		(38,152	)		—
INCREASE (DECREASE) IN CASH		(1,928,692	)		(3,526,518	)
Cash, beginning of year		4,052,212			7,578,730
Cash, end of year	$	2,123,520		$	4,052,212
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid	$	—		$	—
Taxes paid	$	18,865		$	192,364
SUPPLEMENTAL NON-CASH INVESTING AND FINANCING ACTIVITIES
Accrued oil and gas development costs	$	—		$	105,241
Net change in estimate of asset retirement obligation	$	4,214		$	19,095