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

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FORWARD-LOOKING STATEMENTS

This annual report on Form 10-K contains forward-looking statements within the meaning of the federal securities laws. These forwarding-looking statements include without limitation statements regarding our expectations and beliefs about the market and industry, our goals, plans, and expectations regarding our properties and drilling activities and results, our intentions and strategies regarding future acquisitions and sales of properties, our intentions and strategies regarding the formation of strategic relationships, our beliefs regarding the future success of our properties, our expectations and beliefs regarding competition, competitors, the basis of competition and our ability to compete, our beliefs and expectations regarding our ability to hire and retain personnel, our beliefs regarding period to period results of operations, our expectations regarding revenues, our expectations regarding future growth and financial performance, our beliefs and expectations regarding the adequacy of our facilities, and our beliefs and expectations regarding our financial position, ability to finance operations and growth and the amount of financing necessary to support operations. These statements are subject to risks and uncertainties that could cause actual results and events to differ materially. 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.

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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.

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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.

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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.

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Productive Wells

Productive wells consist of producing wells and wells capable of production, including shut-in wells. A well bore with multiple completions is counted as only one well. As of December 31, 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

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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.

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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

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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

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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.

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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.

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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:

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

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

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

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

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

• the level of global oil and natural gas inventories;

• weather conditions;

• technological advances affecting energy consumption; and

• the price and availability of alternative fuels.

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.

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Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future success will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Please read “Reserve estimates depend on many assumptions that may turn out to be inaccurate” (below) for a discussion of the uncertainty involved in these processes. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling, including the following:

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

• pressure or irregularities in geological formations;

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

• equipment failures or accidents;

• adverse weather conditions;

• reductions in oil and natural gas prices;

• title problems; and

• limitations in the market for oil and natural gas.

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

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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

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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:

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

• abnormally pressured formations;

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

• fires and explosions;

• personal injuries and death; and

• 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;

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

• the extent of operating costs; and

• 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

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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.

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Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development activities, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

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:

• 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

• 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

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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:

• require the acquisition of a permit before drilling commences;

• restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;

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

• impose substantial liabilities for pollution resulting from operations.

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

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

• incurring investigatory or remedial obligations; and

• 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

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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.

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

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

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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.

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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.

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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.

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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.

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

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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

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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

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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.

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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

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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.

32

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.

33

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

34

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

F-1

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

F-2

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

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

F-3

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

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

F-4

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

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

F-5

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

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

F-6

HOUSTON AMERICAN ENERGY CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

General

Houston American Energy Corp. (a Delaware Corporation) (“the Company” or “HUSA”) was incorporated on April 2, 2001. The Company is engaged, as a non-operating joint owner, in the exploration, development, and production of natural gas, crude oil, and condensate from properties located principally in the Gulf Coast area of the United States and international locations with proven production, which to date has focused on Colombia, South America.

Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date of these consolidated financial statements. The Company has incurred continuing losses, negative operating cash flow and declining cash balances since 2011, including negative operating cash flow of $1,837,977 for the year ended December 31, 2015. These conditions, together with continued low oil and natural gas prices and financial commitments the Company has made relative to its Colombian properties as well as to investments in Australia, raise substantial doubt as to the Company’s ability to continue as a going concern. These financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.

To address these concerns, the Company may seek additional financing or may consider divestiture of certain assets. There can be no assurance that the Company will be successful in its efforts.

Consolidation

The accompanying consolidated financial statements include all accounts of HUSA and its subsidiaries (HAEC Louisiana E&P, Inc. and HAEC Caddo Lake E&P, Inc.). All significant inter-company balances and transactions have been eliminated in consolidation.

General Principles and Use of Estimates

The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America. In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to such potential matters as litigation, environmental liabilities, income taxes, and determination of proved reserves of oil and gas and asset retirement obligations. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

Reclassification

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

Cash and Cash Equivalents

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

Concentration of Credit Risk

Financial instruments that potentially subject the Company to a concentration of credit risk include cash and cash equivalents. The Company had cash deposits of approximately $1.8 million in excess of the FDIC’s current insured limit of $250,000 at December 31, 2015 for interest bearing accounts. The Company has not experienced any losses on its deposits of cash and cash equivalents.

F-7

Marketable Securities – Available for Sale

Management determines the appropriate classification of its investments in marketable securities at the time of purchase and reevaluates such determination at each balance sheet date. Equity securities not classified as trading securities are classified as available-for-sale. Available-for-sale securities are reported at fair value and unrealized gains and losses are included in stockholders' equity. Management determines fair value of its investments based on quoted market prices at each balance sheet date.

Accounts Receivable

Accounts receivable – other and escrow receivables have been evaluated for collectability and are recorded at their net realizable values.

Allowance for Accounts Receivable

The Company regularly reviews outstanding receivables and provides for estimated losses through an allowance for doubtful accounts when necessary. In evaluating the need for an allowance, the Company makes judgments regarding its customers' ability to make required payments, economic events and other factors. As the financial condition of these parties change, circumstances develop or additional information becomes available, an allowance for doubtful accounts may be required. When the Company determines that a customer may not be able to make required payments, the Company increases the allowance through a charge to income in the period in which that determination is made. As of December 31, 2015, the Company evaluated their receivables and determined an allowance was not required.

Oil and Gas Revenues

The Company recognizes sales revenues, net of royalties and net profits interests, based on the amount of gas, oil, and condensate sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when production has been delivered to a pipeline. The Company follows the sales method to account for natural gas imbalances. Sales may result in more or less of the Company’s share of pro-rata production from certain wells. When natural gas sales volumes exceeds the Company’s entitled share and the accumulated overproduced balance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company will record a liability. Historically, sales volumes have not materially differed from the Company’s entitled share of natural gas production and the Company did not have a material imbalance position in terms of volumes or values at December 31, 2015 or 2014.

Oil and Gas Properties

The Company uses the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs for unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. Capitalized costs include lease acquisition, geological and geophysical work, delay rentals, costs of drilling, completing and equipping the wells and any internal costs that are directly related to acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Proceeds from the sale or other disposition of oil and gas properties are generally treated as a reduction in the capitalized costs of oil and gas properties, unless the impact of such a reduction would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.

The Company categorizes its full cost pools as costs subject to amortization and costs not being amortized. The sum of net capitalized costs subject to amortization, including estimated future development and abandonment costs, are amortized using the unit-of-production method. Depletion and amortization for oil and gas properties was $754,892 and $348,197 for the years ended December 31, 2015 and 2014, respectively and accumulated amortization, depreciation and impairment was $54,587,826 and $52,114,846 at December 31, 2015 and 2014, respectively.

Costs Excluded

Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent costs of investments in unproved properties. The Company excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the costs subject to amortization.

F-8

Ceiling Test

Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X. The ceiling test determines a limit, on a country-by-country basis, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment (“DD&A”) and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, calculated for 2015 using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) with consideration of price change only to the extent provided by contractual arrangement, discounted at 10%, net of related tax effects. If capitalized costs exceed this limit, the excess is charged to expense and reflected as additional accumulated DD&A. During the year, the Company impaired oil and gas properties in the amount of $1,718,088.

Furniture and Equipment

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

Depreciation expense for office equipment was $1,865 and $11,700 for 2015 and 2014, respectively, and accumulated depreciation was $88,897 and $87,032 at December 31, 2015 and 2014, respectively.

Asset Retirement Obligations

For the Company, asset retirement obligations (“ARO”) represent the systematic, monthly accretion and depreciation of future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, an adjustment is made to the full cost pool, with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. Although the Company’s domestic policy with respect to ARO is to assign depleted wells to a salvager for the assumption of abandonment obligations before the wells have reached their economic limits, the Company has estimated its future ARO obligation with respect to its domestic operations. The ARO assets, which are carried on the balance sheet as part of the full cost pool, have been included in our amortization base for the purposes of calculating depreciation, depletion and amortization expense. For the purposes of calculating the ceiling test, the future cash outflows associated with settling the ARO liability have been included in the computation of the discounted present value of estimated future net revenues.

Joint Venture Expense

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

Income Taxes

Deferred income taxes are provided on a liability method whereby deferred tax assets and liabilities are established for the difference between the financial reporting and income tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

Stock-Based Compensation

The Company measures the cost of employee services received in exchange for stock and stock options based on the grant date fair value of the awards. The Company determines the fair value of stock option grants using the Black-Scholes option pricing model. The Company determines the fair value of shares of non-vested stock based on the last quoted price of our stock on the date of the share grant. The fair value determined represents the cost for the

F-9

award and is recognized over the vesting period during which an employee is required to provide service in exchange for the award. As share-based compensation expense is recognized based on awards ultimately expected to vest, the Company reduces the expense for estimated forfeitures based on historical forfeiture rates. Previously recognized compensation costs may be adjusted to reflect the actual forfeiture rate for the entire award at the end of the vesting period. Excess tax benefits, if any, are recognized as an addition to paid-in capital.

Preferred Stock

The Company has authorized 10,000,000 shares of preferred stock with a par value of $0.001. The Board of Directors shall determine the designations, rights, preferences, privileges and voting rights of the preferred stock as well as any restrictions and qualifications thereon. No shares of preferred stock have been issued.

Net Income (Loss) Per Share

Basic net income (loss) per share is computed by dividing the net income (loss) attributable to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted net income (loss) per share is computed by dividing the net income (loss) attributable to common shareholders by the weighted-average number of common and common equivalent shares outstanding during the period. Common share equivalents included in the diluted computation represent shares issuable upon assumed exercise of stock options and warrants using the treasury stock and “if converted” method. For periods in which net losses are incurred, weighted average shares outstanding is the same for basic and diluted loss per share calculations, as the inclusion of common share equivalents would have an anti-dilutive effect.

For the year ended December 31, 2015, outstanding options to purchase 4,432,165 shares of common stock were excluded from the calculation of diluted net loss per share because they were anti-dilutive. For the year ended December 31, 2014, outstanding options to purchase 3,392,832 shares of common stock were excluded from the calculation of diluted net loss per share because they were anti-dilutive.

Concentration of Risk

As a non-operator oil and gas exploration and production company, and through its interest in a limited liability company (“Hupecol”) and concessions operated by Hupecol in the South American country of Colombia, the Company is dependent on the personnel, management and resources of Hupecol to operate efficiently and effectively.

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

The Company currently has interests in concessions in Colombia and expects to be active in Colombia for the foreseeable future. The political climate in Colombia is unstable and could be subject to radical change over a very short period of time. In the event of a significant negative change in political and economic stability in the vicinity of the Company’s Colombian operations, the Company may be forced to abandon or suspend its efforts. Either of such events could be harmful to the Company’s expected business prospects.

At December 31, 2015, 67.5% of the Company’s net oil and gas property investment, and 0% of its revenue for the year ended December 31, 2015, was with or derived from interests operated in Colombia.

For 2015, our oil production from the Company’s mineral interests was sold to U.S. oil marketing companies based on the highest bid. The gas production is sold to U.S. natural gas marketing companies based on the highest bid. No purchaser accounted for more than 10% of our oil and gas sales.

The Company reviews accounts receivable balances when circumstances indicate a balance may not be collectible. Based upon the Company’s review, no allowance for uncollectible accounts was deemed necessary at December 31, 2015 and 2014, respectively.

Subsequent Events

The Company evaluated subsequent events for disclosure from December 31, 2015 through the date the consolidated financial statements were issued.

Recent Accounting Developments

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

F-10

NOTE 2—ESCROW RECEIVABLE

At December 31, 2015 and December 31, 2014, the Company’s balance sheet reflected the following escrow receivables relating to various oil and gas properties previously sold by the Company:

	December 31, 2015		December 31, 2014
Tambaqui Escrow	$	—	$	4,331
HDC LLC and HL LLC 15% Escrow		251,125		294,383
HDC LLC and HL LLC 5% Contingency		10,891		11,256
HC LLC 5% Contingency		—		11,458
Total	$	262,016	$	321,428

Changes in escrow receivables during 2015 reflect the release of an aggregate of $59,412 from the various escrow accounts.

NOTE 3—OIL AND GAS PROPERTIES

Evaluated Oil and Gas Properties

Evaluated oil and gas properties subject to amortization at December 31, 2015 included the following:

	United States			South America			Total
Evaluated properties being amortized	$	5,385,898		$	49,454,702		$	54,840,600
Accumulated depreciation, depletion, amortization and impairment		(5,133,124	)		(49,454,702	)		(54,587,826	)
Net capitalized costs	$	252,774		$	—		$	252,774

Evaluated oil and gas properties subject to amortization at December 31, 2014 included the following:

	United States			South America			Total
Evaluated properties being amortized	$	4,570,915		$	49,454,702		$	54,025,617
Accumulated depreciation, depletion, amortization and impairment		(2,660,144	)		(49,454,702	)		(52,114,846	)
Net capitalized costs	$	1,910,771		$	—		$	1,910,771

Unevaluated Oil and Gas Properties

Unevaluated oil and gas properties not subject to amortization at December 31, 2015 included the following:

	United States		South America		Total
Leasehold acquisition costs	$	761,545	$	141,319	$	902,864
Geological, geophysical, screening and evaluation costs		4,143		1,972,056		1,976,199
Total	$	765,688	$	2,113,375	$	2,879,063

Unevaluated oil and gas properties not subject to amortization at December 31, 2014 included the following:

	United States		South America		Total
Leasehold acquisition costs	$	868,301	$	141,319	$	1,009,620
Geological, geophysical, screening and evaluation costs		683,976		1,892,688		2,576,664
Total	$	1,552,277	$	2,034,007	$	3,586,284

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NOTE 4—Asset Retirement Obligations

The following table describes changes in our asset retirement liability during each of the years ended December 31, 2015 and 2014.

	2015			2014
ARO liability at January 1	$	28,147		$	8,414
Accretion expense		1,329			628
Liabilities incurred from drilling		—			20,812
Changes in estimates		(4,214	)		(1,717	)
ARO liability at December 31	$	25,262		$	28,147

NOTE 5—STOCK-BASED COMPENSATION

On August 12, 2005, the Company’s Board of Directors adopted the Houston American Energy Corp. 2005 Stock Option Plan (the “2005 Plan”). The terms of the 2005 Plan allow for the issuance of up to 500,000 options to purchase 500,000 shares of the Company’s common stock.

In 2008, the Company’s Board of Directors adopted the Houston American Energy Corp. 2008 Equity Incentive Plan (the “2008 Plan” and, together with the 2005 Plan, the “Plans”). The terms of the 2008 Plan allowed for the issuance of up to 2,200,000 shares of the Company’s common stock pursuant to the grant of stock options and restricted stock. Persons eligible to participate in the Plans are key employees, consultants and directors of the Company.

During 2012 and 2013, the Company’s board of directors and shareholders adopted amendments to the Company’s 2008 Equity Incentive Plan to increase the shares reserved to 6,000,000 shares.

Stock Option Activity

In 2014, options to purchase an aggregate of 200,000 shares were granted to non-employee directors and options to purchase an aggregate of 600,000 shares were granted to an employee.

The 200,000 options granted to non-employee directors vested 20% on the grant date and vest as to the remaining 80% nine months from the grant date, have a ten-year life and have an exercise price of $0.415 per share. The option grants to non-employee directors were valued on the date of grant at $46,191 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.57%, (2) expected life in years of 4.65, (3) expected stock volatility of 103.6%, and (4) expected dividend yield of 0%. The Company determined the options qualify as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life.

The 600,000 options granted to an employee vest 1/3 on each of the first three anniversaries of the grant date, subject to acceleration of vesting in the event of certain changes in control or the realization of revenues from oil and gas production on the Serrania prospect or receipt of proceeds from the sale of the Serrania prospect, have a ten year life and have an exercise price of $0.415 per share. The option grants to the employee were valued on the date of grant at $126,355 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.57%, (2) expected life in years of 4.65, (3) expected stock volatility of 103.6%, and (4) expected dividend yield of 0%. The Company determined the options qualify as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life.

In 2015, options to purchase an aggregate of 8,333 shares were granted to a new non-employee director, options to purchase an aggregate of 900,000 shares were granted to a new officer and options to purchase an aggregate of 200,000 shares were granted to non-employee directors.

The 8,333 options granted to a new non-employee director vested 20% on the grant date and vest as to the remaining 80% nine months from the grant date, have a ten-year life and have an exercise price of $0.2158 per share. The option grant to the non-employee director was valued on the date of grant at $805 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.36%, (2) expected life in years of 4.98, and (3) expected stock volatility of 106%. The Company determined the option qualifies as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life.

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The 900,000 options granted to an employee have a ten year life and an exercise price of $0.2158 per share and vest 1/3 on each of the first three anniversaries of the grant date, subject to acceleration of vesting in the event of certain changes in control or (i) the receipt of $10 million or more in aggregate gross proceeds from the sale of equity securities or securities convertible into equity securities, or (ii) the acquisition by the Company of $10 million or more in aggregate purchase price of oil and gas properties. The option grant to the employee was valued on the date of grant at $82,000 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of1.36%, (2) expected life in years of 4.98, and (3) expected stock volatility of 106%. The Company determined the option qualifies as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life.

The 200,000 options granted to non-employee directors vested 20% on the grant date and vest as to the remaining 80% nine months from the grant date, have a ten-year life and have an exercise price of $0.2028 per share. The option grants to non-employee directors were valued on the date of grant at $17,370 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.73% (2) expected life in years of 5.01, and (3) expected stock volatility of 105%. The Company determined the options qualify as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life.

Option activity during 2015 and 2014 was as follows:

	Options			Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in Years)		Aggregate Intrinsic Value
Outstanding at December 31, 2013		2,592,832		$	4.07
Granted		800,000		$	0.42
Exercised		—		$	—
Forfeited		—		$	—
Outstanding at December 31, 2014		3,392,832		$	3.21
Granted		1,108,333		$	0.21
Exercised		—		$	—
Forfeited		(69,000	)	$	2.55
Outstanding at December 31, 2015		4,432,165		$	2.47		6.77	$	—

During 2015 and 2014, the Company recognized $91,625 and $414,189, respectively, of stock compensation expense attributable to outstanding stock option grants, including current period grants and unamortized expense associated with prior period grants.

As of December 31, 2015, non-vested options totaled 1,466,666 and total unrecognized stock-based compensation expense related to non-vested stock options was $127,591. The unrecognized expense is expected to be recognized over a weighted average period of 1.83 years. The weighted average remaining contractual term of the outstanding options and exercisable options at December 31, 2015 is 6.77 years and 5.62 years, respectively.

As of December 31, 2015, there were 1,567,835 shares of common stock available for issuance pursuant to future stock or option grants under the Plans.

Restricted Stock Activity

During 2011, the Company granted to officers an aggregate of 45,000 shares of restricted stock, which shares vest over a period of three years. The fair value of $743,400 was determined based on the fair market value of the shares on the date of grant. This value was amortized over the vesting period, and during 2015 and 2014, $0 and $36,821 was amortized to expense respectively. As of December 31, 2014, there was $0 of unrecognized compensation cost related to unvested restricted stock.

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Share-Based Compensation Expense

The following table reflects share-based compensation recorded by the Company for 2015 and 2014:

	2015			2014
Share-based compensation expense included in general and administrative expense	$	91,625		$	451,010
Earnings per share effect of share-based compensation expense	$	(0.00	)	$	(0.01	)

Treasury Stock

We account for repurchases of common stock using the cost method with common stock in treasury classified in the consolidated balance sheets as a reduction of shareholders’ equity. During the year ending December 31, 2015, the Company acquired 190,000 shares of common stock for $38,152.

NOTE 6—TAXES

The following table sets forth a reconciliation of the statutory federal income tax for the years ending December 31, 2015 and 2014.

	2015			2014
Loss before income taxes	$	(3,811,341	)	$	(4,350,996	)
Income tax benefit computed at statutory rates	$	(1,333,969	)	$	(1,523,613	)
Permanent differences, nondeductible expenses		501			141,446
Increase (decrease) in valuation allowance		635,888			(696,514	)
Return to accrual items		(764	)		1,178,681
Other adjustment		717,209			—
NOL adjustment		—			902,183
Tax provision	$	18,865		$	2,183
Total provision
Foreign	$	18,865		$	2,183
Total provision	$	18,865		$	2,183

At December 31, 2015 the Company has a federal tax loss carry forward of $47,415,085 and a foreign tax credit carry forward of $505,745, both of which have been fully reserved.

The tax effects of the temporary differences between financial statement income and taxable income are recognized as a deferred tax asset and liabilities. Significant components of the deferred tax asset and liability as of December 31, 2015 and 2014 are set out below.

	2015			2014
Non-Current Deferred tax assets:
Net operating loss carry forward	$	16,255,870		$	15,764,184
Foreign tax credit carry forward		505,745			486,880
Deferred state tax		23,277			23,277
Stock compensation		3,091,356			3,525,473
Book in excess of tax depreciation, depletion and capitalization methods on oil and gas properties		(713,832	)		(1,524,310	)
Other		(327,600	)		(76,576	)
Total Non-Current Deferred tax assets		18,834,816			18,198,928
Valuation Allowance		(18,834,816	)		(18,198,928	)
Net deferred tax asset	$	—		$	—

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Foreign Income Taxes

The Company owns direct ownership in several properties in Colombia operated by Hupecol. Colombia’s current income tax rate is 25%. During 2015 and 2014, we recorded foreign tax expense of $18,865 and $2,183, respectively.

NOTE 7—RELATED PARTIES

In conjunction with the Company’s efforts to secure oil and gas prospects, financing and services, in lieu of salary or other forms of compensation, during 2005, the Company granted to John F. Terwilliger, a principal shareholder and then Chief Executive Officer, and Orrie L. Tawes, a principal shareholder and Director, overriding royalty interests (ORRI) in select mineral properties of the Company, including all current and future properties in Colombia in which Messrs. Terwilliger and Tawes each hold a 1.5% ORRI. During 2015 and 2014, Mr. Terwilliger received royalty payments relating to those properties totaling $919 and $20,682, respectively, and Mr. Tawes received royalty payments relating to those properties totaling $919 and $20,682, respectively.

NOTE 8—COMMITMENTS AND CONTINGENCIES

Lease Commitment

The Company leases office facilities under an operating lease agreement that expires May 31, 2017. The lease agreement requires future payments as follows:

Year	Amount
2016	$	96,162
2017		40,469
Total	$	136,631

Total rental expense was $95,711 and $88,709 in 2015 and 2014, respectively. The Company does not have any capital leases or other operating lease commitments.

Legal Contingencies

The Company is subject to legal proceedings, claims and liabilities that arise in the ordinary course of its business. The Company accrues for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as further information develops or circumstances change.

Silverman Shareholder Class Action Suit. On April 27, 2012, a purported class action lawsuit was filed in the U.S. District Court for the Southern District of Texas against the Company and certain of its executive officers: Steve Silverman v. Houston American Energy Corp. et al., Case No. 4:12-CV-1332. The complaint generally alleged that, between March 29, 2010 and April 18, 2012, all of the defendants violated Sections 10(b) of the Securities Exchange Act of 1934 and SEC Rule 10b-5 and the individual defendants violated Section 20(a) of the Exchange Act in making materially false and misleading statements including certain statements related to the status and viability of the Tamandua #1 well on the Company’s CPO 4 prospect. Two additional class action lawsuits were filed against us in May 2012. The complaints sought unspecified damages, interest, attorneys’ fees, and other costs. On September 20, 2012, the court consolidated the class action lawsuits and appointed a lead plaintiff and, on November 15, 2012, the lead plaintiffs filed an amended complaint. The amended complaint, among other things, expanded the putative class period to November 9, 2009 to April 18, 2012 and added allegations challenging a November 2009 estimate concerning the CPO 4 prospect. On January 14, 2013, the Company filed a motion to dismiss and, on August 22, 2013, the court granted the motion and dismissed the complaint. The plaintiffs subsequently filed a Notice of Appeal of the dismissal of the complaint. On July 15, 2014, the U.S. Court of Appeals for the Fifth Circuit reversed the dismissal of the case. The appellate court ruling focused on the sufficiency of the pleadings in the case, made no determination regarding the merits of the factual allegations, and remanded the case to the District Court for further proceedings. In October 2014, the parties reached an agreement in principle to settle the consolidated lawsuit. The settlement, which provided for a $7,000,000 payment expected to be fully funded by the Company’s insurance, was subject to preliminary and final approval of the court. The parties submitted the settlement to the court for approval on December 31, 2014. The court signed an order on April 16, 2015 preliminarily approving the settlement. Pursuant to the terms of the settlement, the Company, through its insurer, was required to escrow settlement funds in the

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amount of $7,000,000. In May 2015, the Company's insurer deposited the required funds into an escrow account to fund the settlement. On July 29, 2015, the court rendered a final judgment approving the settlement and dismissed the case with prejudice. As a result, the $7,000,000 litigation settlement payable and the related insurance claim receivable were each reflected as settled in 2015.

SEC Administrative Proceeding. On August 4, 2014, following a multi-year investigation, the SEC instituted administrative cease-and-desist proceedings pursuant to Section 8A of the Securities Act of 1933 and 21C of the Securities Exchange Act of 1934, styled In the Matter of Houston American EnergyCorp., John F.Terwilliger, Jr.,Undiscovered Equities, Inc. and Kevin T.McKnight. The administrative proceeding alleged that Mr. Terwilliger and, in turn, Houston American Energy, made false and misleading statements with respect to the CPO 4 prospect and promoted those statements through Undiscovered Equities and its principal, Kevin McKnight. The SEC was seeking a determination from an administrative law judge as to whether (i) the allegations of the SEC were true; (ii) Houston American Energy and Mr. Terwilliger should be ordered to (A) cease-and-desist from committing or causing violations of Section 10(b) of the Exchange Act and Rule 10b-5 thereunder, (B) pay a civil penalty pursuant to Section 8A(g) of the Securities Act and Section 21B(a) of the Exchange Act, and (C) pay disgorgement pursuant to Section 8A(e) of the Securities Act and Sections 21B(e) and 21C(e) of the Exchange Act; and (iii) Mr. Terwilliger should be prohibited from acting as an officer and director of a public company pursuant to Section 8A(f) of the Securities Act and Section 21C(f) of the Exchange Act.

At December 31, 2014, the administrative proceeding was pending and was scheduled for trial in January 2015. The trial was stayed in January 2015 pending consideration by the Commission of a proposed settlement. On April 16, 2015, the Commission formally approved the settlement. Pursuant to the terms of the settlement, among other things, the Company paid a penalty of $400,000 and the Company’s Chief Executive Officer resigned and paid a penalty of $150,000. The Company, at December 31, 2014, had recorded on its balance sheet a contingent liability, and on its statement of operations a contingent loss of $400,000 relating to the settlement. The Company has an insurance policy that insures for legal fees incurred in connection with the above administrative proceeding. At December 31, 2014, the Company had recorded an insurance claim receivable of $1,612,681 for fees which have been incurred, but not yet reimbursed by its insurance Company. As of December 31, 2015, there was no outstanding insurance claim receivable related to unpaid accrued legal fees.

Environmental Contingencies

The Company’s oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require the Company to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on its results of operations, competitive position or financial condition as well as the industry in general. Under these environmental laws and regulations, the Company could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether the Company was responsible for the release or if its operations were standard in the industry at the time they were performed. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks.

Development Commitments

During the ordinary course of oil and gas prospect development, the Company commits to a proportionate share for the cost of acquiring mineral interests, drilling exploratory or development wells and acquiring seismic and geological information.

Production Incentive Compensation Plan

In August 2013, the Company’s compensation committee adopted a Production Incentive Compensation Plan. The purpose of the Plan is to encourage employees and consultants participating in the Plan to identify and secure for the Company participation in attractive oil and gas opportunities.

F-16

Under that Plan, the committee may establish one or more Pools and designate employees and consultants to participate in those Pools and designate prospects and wells, and a defined percentage of the Company’s revenues from those wells, to fund those Pools. Only prospects acquired on or after establishment of the Plan, and excluding all prospects in Colombia, may be designated to fund a Pool. The maximum percentage of the Company’s share of revenues from a well that may be designated to fund a Pool is 2% (the “Pool Cap”); provided, however, that with respect to wells with a net revenue interest to the 8/8 of less than 73%, the Pool Cap with respect to such wells shall be reduced on a 1-for-1 basis such that no portion of the Company’s revenues from a well may be designated to fund a Pool if the NRI is 71% or less.

Designated participants in a Pool will be assigned a specific percentage out of the Company’s revenues assigned to the Pool and will be paid that percentage of such revenues from all wells designated to such Pool and spud during that participant’s employment or services with the Company. In no event may the percentage assigned to the Company’s chief executive officer relative to any well within a Pool exceed one-half of the applicable Pool Cap for that well. Payouts of revenues funded into Pools shall be made to participants not later than 60 days following year end, subject to the committee’s right to make partial interim payouts. Participants will continue to receive their percentage share of revenues from wells included in a Pool and spud during the term of their employment or service so long as revenues continue to be derived by the Company from those wells even after termination of employment or services of the Participant; provided, however, that a participant’s interest in all Pools shall terminate on the date of termination of employment or services where such termination is for cause.

In the event of certain changes in control of the Company, the acquirer or survivor of such transaction must assume all obligations under the Plan; provided, however, that in lieu of such assumption obligation, the committee may, at its sole discretion, assign overriding royalty interests in wells to substantially mirror the rights of participants under the Plan. Similarly, the committee may, at any time, assign overriding royalty interests in wells in settlement of obligations under the Plan.

The Plan is administered by the Company’s compensation committee which shall consult with the Company’s chief executive officer relative to Pool participants, prospects, wells and interests assign although the committee will have final and absolute authority to make all such determinations.

During 2015, no grants were made under the plan.

The Company records amounts payable under the plan as a reduction to revenue as revenues are recognized from prospects included in pools covered by the plan based on the participants’ interest in such prospect revenues and records the same as accounts payable until such time as such amounts are paid out. The obligation associated with the plan totaled $0 at December 31, 2015.

NOTE 9—SUBSEQUENT EVENTS

In February 2016, the Company agreed to purchase ordinary shares (the “Shares”) of Tamboran Resources Limited, an Australian oil and gas company (“Tamboran”), for $1,000,000. The Shares represent a 12.5% equity ownership interest in Tamboran. Pursuant to the terms of the purchase of the Shares, the Company has certain anti-dilution rights for a period of nine months. Closing of the planned investment is subject to satisfaction of certain conditions on the part of Tamboran, including the receipt by Tamboran of funding from investors other than the Company in an amount not less than A$705,000.

NOTE 10—GEOGRAPHICAL INFORMATION

The Company currently has operations in two geographical areas, the United States and Colombia. Revenues for the years ended December 31, 2015 and 2014 and long-lived assets as of December 31, 2015 and 2014 attributable to each geographical area are presented below:

	2015				2014
	Revenues		Long Lived Assets, Net		Revenues		Long Lived Assets, Net
North America	$	429,435	$	1,019,569	$	363,455	$	3,466,020
South America		—		2,113,374		—		2,034,007
Total	$	429,435	$	3,132,943	$	363,455	$	5,500,027

F-17

NOTE 11—SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

This footnote provides unaudited information required by FASB ASC Topic 932, Extractive Activities—Oil and Gas.

Geographical Data

The following table shows the Company’s oil and gas revenues and lease operating expenses, which excludes the joint venture expenses incurred in South America, by geographic area:

	2015		2014
Revenues
North America	$	429,435	$	363,455
South America		—		—
	$	429,435	$	363,455
Production Cost
North America	$	148,067	$	113,233
South America		—		—
	$	148,067	$	113,233

Capital Costs

Capitalized costs and accumulated depletion relating to the Company’s oil and gas producing activities as of December 31, 2015, all of which are onshore properties located in the United States and Colombia, South America are summarized below:

	United States			South America			Total
Unproved properties not being amortized	$	765,688		$	2,113,375		$	2,879,063
Proved properties being amortized		5,385,898			49,454,702			54,840,600
Accumulated depreciation, depletion, amortization and impairment		(5,133,124	)		(49,454,702	)		(54,587,826	)
Net capitalized costs	$	1,018,462		$	2,113,375		$	3,131,837

Amortization Rate

The amortization rate per unit based on barrel of oil equivalents was $66.08 for the United States and $0 for South America for the year ended December 31, 2015.

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Acquisition, Exploration and Development Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities as of December 31, 2015 and 2014 are summarized below:

	2015
	United States		South America
Property acquisition costs:
Proved	$	16,669	$	—
Unproved		—		—
Exploration costs		72,500		79,511
Development costs		—		—
Total costs incurred	$	89,169	$	79,511

	2014
	United States		South America
Property acquisition costs:
Proved	$	54,716	$	—
Unproved		184,612		9,984
Exploration costs		3,005,469		234,487
Development costs		—		—
Total costs incurred	$	3,244,797	$	244,471

Reserve Information and Related Standardized Measure of Discounted Future Net Cash Flows

In December 2009, the Company adopted revised oil and gas reserve estimation and disclosure requirements. The primary impact of the new disclosures is to conform the definition of proved reserves with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The accounting standards update revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period before the end of the year rather than the year-end price, must be used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technology to estimate proved oil and gas reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. The unaudited supplemental information on oil and gas exploration and production activities has been presented in accordance with the new reserve estimation and disclosure rules. Disclosures by geographic area include the United States and South America, which consists of our interests in Colombia. The supplemental unaudited presentation of proved reserve quantities and related standardized measure of discounted future net cash flows provides estimates only and does not purport to reflect realizable values or fair market values of the Company’s reserves. Volumes reported for proved reserves are based on reasonable estimates. These estimates are consistent with current knowledge of the characteristics and production history of the reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, significant changes to these estimates can be expected as future information becomes available.

Proved reserves are those estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment, and operating methods.

The reserve estimates set forth below were prepared by Lonquist & Co., LLC (“Lonquist”), utilizing reserve definitions and pricing requirements prescribed by the SEC. Lonquist is an independent professional engineering firm specializing in the technical and financial evaluation of oil and gas assets. Lonquist’s report was conducted under the direction of Don E. Charbula, P.E., Vice President of Lonquist. Mr. Charbula holds a BS in Petroleum Engineering

F-19

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 and its employees have no interest in the Company, and were objective in determining the results of the Company’s reserves. Lonquist used a combination of production performance, offset analogies, seismic data and their interpretation, subsurface geologic data and core data, along with estimated future operating and development costs as provided by the Company and based upon historical costs adjusted for known future changes in operations or development plans, to estimate our reserves. The Company does not operate any of its oil and gas properties.

Total estimated proved developed and undeveloped reserves by product type and the changes therein are set forth below for the years indicated.

	United States						South America				Total
	Gas (mcf)			Oil (bbls)			Gas (mcf)		Oil (bbls)		Gas (mcf)			Oil (bbls)
Total proved reserves
Balance December 31, 2013		36,810			11,150			—		—		36,810			11,150
Extensions and discoveries		24,944			32,090			—		—		24,944			32,090
Revisions of prior estimates		23,673			(5,958	)		—		—		23,673			(5,958	)
Production		(12,717	)		(3,152	)		—		—		(12,717	)		(3,152	)
Balance December 31, 2014		72,710			34,130			—		—		72,710			34,130
Revisions to prior estimates		17,136			(19,212	)		—		—		17,136			(19,212	)
Production		(32,146	)		(6,068	)		—		—		(32,146	)		(6,068	)
Balance December 31, 2015		57,700			8,850			—		—		57,700			8,850
Proved developed reserves
at December 31, 2014		72,710			34,130			—		—		72,710			34,130
at December 31, 2015		57,700			8,850			—		—		57,700			8,850
Proved undeveloped reserves
at December 31, 2014		—			—			—		—		—			—
at December 31, 2015		—			—			—		—		—			—

During 2015 and 2014, the Company recorded extensions and discoveries resulting from its ongoing drilling operations in the United States. As of December 31, 2015, the Company had no proved undeveloped (“PUD”) reserves. No PUD reserves as of December 31, 2014 were converted to proved developed producing reserves in 2015.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is computed using average first-day-of the-month prices for oil and gas during the preceding 12 month period (with consideration of price changes only to the extent provided by contractual arrangements), applied to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated related future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated), and assuming continuation of existing economic conditions. Future income tax expenses give effect to permanent differences and tax credits but do not reflect the impact of continuing operations including property acquisitions and exploration. The estimated future cash flows are then discounted using a rate of ten percent a year to reflect the estimated timing of the future cash flows.

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Standardized measure of discounted future net cash flows at December 31, 2015:

	United States			South America		Total
Future cash flows from sales of oil and gas	$	611,520		$	—	$	611,520
Future production cost		(308,020	)		—		(308,020	)
Future net cash flows		303,500			—		303,500
10% annual discount for timing of cash flow		(49,120	)		—		(49,120	)
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	$	254,380		$	—	$	254,380
Changes in standardized measure:
Change due to current year operations
Sales, net of production costs		(281,368	)		—		(285,582	)
Change due to revisions in standardized variables:
Accretion of discount		183,828			—		183,828
Net change in sales and transfer price, net of production costs		(405,129	)		—		(405,129	)
Revision and others		(176,014	)		—		(176,014	)
Changes in production rates and other		(617,498	)		—		(613,285	)
Net		(1,296,181	)		—		(1,296,181	)
Beginning of year		1,550,561			—		1,550,561
End of year	$	254,380		$	—	$	254,380

Standardized measure of discounted future net cash flows at December 31, 2014:

	United States			South America		Total
Future cash flows from sales of oil and gas	$	3,579,990		$	—	$	3,579,990
Future production cost		(1,091,790	)		—		(1,091,790	)
Future income tax		(287,709	)		—		(287,709	)
Future net cash flows		2,200,491			—		2,200,491
10% annual discount for timing of cash flow		(649,930	)		—		(649,930	)
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	$	1,550,561		$	—	$	1,550,561
Changes in standardized measure:
Change due to current year operations
Sales, net of production costs		(250,222	)		—		(250,222	)
Change due to revisions in standardized variables:
Income taxes		(287,709	)		—		(287,709	)
Accretion of discount		112,021			—		112,021
Net change in sales and transfer price, net of production costs		(193,777	)		—		(193,777	)
Discoveries		999,242			—		999,242
Changes in production rates and other		451,971			—		451,971
Net		831,526			—		831,526
Beginning of year		719,035			—		719,035
End of year	$	1,550,561		$	—	$	1,550,561

F-21

NOTE 12—SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

	Three Months Ended
	March 31,			June 30,			Sept. 30,			Dec. 31,
2015
Operating revenue	$	101,971		$	114,122		$	124,448		$	88,894
Loss from operations		(1,191,769	)		(339,488	)		(468,332	)		(1,735,182	)
Net loss		(1,187,064	)		(351,808	)		(463,566	)		(1,827,768	)
Loss per common share – basic	$	(0.02	)	$	(0.01	)	$	(0.01	)	$	(0.04	)
Loss per common share – diluted	$	(0.02	)	$	(0.01	)	$	(0.01	)	$	(0.04	)
2014
Operating revenue	$	106,023		$	67,450		$	56,805		$	133,177
Loss from operations		(536,105	)		(684,728	)		(512,919	)		(2,224,590	)
Net loss		(535,368	)		(683,644	)		(511,653	)		(2,222,514	)
Loss per common share – basic	$	(0.01	)	$	(0.01	)	$	(0.01	)	$	(0.04	)
Loss per common share – diluted	$	(0.01	)	$	(0.01	)	$	(0.01	)	$	(0.04	)

F-22

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (File No. 333-127656) relating to the 2005 Stock Option Plan of Houston American Energy Corp., on Form S-8 (File No. 333-151824) relating to the 2008 Equity Incentive Plan, on Form S-8 (File No. 333-206875) relating to additional shares reserved under the 2008 Equity Incentive Plan, and on Form S-3 (File No. 333-183540) of our report dated March 17, 2016, relating to the consolidated financial statements of Houston American Energy Corp. that appear in the Annual Report on Form 10-K of Houston American Energy for the year ended December 31, 2015.

/s/ GBH CPAs, PC

GBH CPAs, PC
www.gbhcpas.com
Houston, Texas
March 17, 2016

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the use of the name Lonquist & Co., LLC and to incorporation by reference of our report dated February 15, 2016, which appears in the annual report on Form 10-K of Houston American Energy Corp. for the year ended December 31, 2015, in the Registration Statements of Houston American Energy Corp. on Form S-8 (File No. 333-127656), relating to the 2005 Stock Option Plan of Houston American Energy Corp., on Form S-8 (File No. 333-151824), relating to the 2008 Equity Incentive Plan, on Form S-8 (File No. 333-206875) relating to additional shares reserved under the 2008 Equity Incentive Plan, and on Form S-3 (File No. 333-183540), and to any amendments to those Registration Statements.

/s/ Don E. Charbula, P.E.

Don E. Charbula, P.E.
Vice President

LONQUIST & CO., LLC
AUSTIN, TEXAS
March 17, 2016

EX-31.1

Exhibit 31.1

SECTION 302
CERTIFICATION

I, John Boylan, certify that:

1. I have reviewed this annual report on Form 10-K of Houston American Energy Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respect the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a–15(f) and 15d–15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors:

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date: March 17, 2016	/s/ John P. Boylan
	John P. Boylan, Chief Executive Officer and Principal Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER
AND CHIEF FINANCIAL OFFICER
PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, John Boylan, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Annual Report of Houston American Energy Corp. on Form 10-K for the year ended December 31, 2015 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Form 10-K fairly presents in all material respects the financial condition and results of operations of Houston American Energy Corp.

By:	/s/ John P. Boylan
Name:	John P. Boylan
Title:	Chief Executive Officer and Chief Financial Officer
Dated:	March 17, 2016

EX-99.2

Exhibit 99.2

 

February 15, 2016

Houston American Energy Corporation
801 Travis, Suite 1425
Houston, Texas 77002

Re: Houston American Energy Corporation
Year End Reserve Report
Louisiana, Oklahoma and Texas
as of Decemer 31, 2015
SEC Guideline Case

Pursuant to your request, Lonquist & Co., LLC (“L&Co”) has estimated the future oil and gas Reserves and projected the associated future revenues net to the interests owned by Houston American Energy Corporation (“Houston American”) as of December 31, 2015. The assets evaluated in this report are located in Louisiana, Oklahoma and Texas. The Proved Developed Producing (“PDP”) and Probable (“PROB”) Reserves were evaluated in this report.

Our conclusions, as of December 31, 2015, are summarized below:

	Net to Houston American Energy Corporation
	Proved Developed				Proved Undeveloped		Total Provedb		Total Probableb		Total Possibleb		Grand Totalb
SEC Pricing as of December 31, 2015	Producing		Non-Producinga
Estimated Future Net Oil/Condensate, bbl		8,850		0		0		8,850		930		0		9,780
Estimated Future Net Gas, MMcf		57.7		0		0		57.7		11		0		68.7
Estimated Future Net NGL, bbl		100		0		0		100		30		0		130
Total Future Gross Revenue, $		611,520		0		0		611,520		79,630		0		691,150
Estimated Future Production Taxes, $		64,520		0		0		64,520		7,590		0		72,110
Estimated Future Operating Expenses, $		243,490		0		0		243,490		44,570		0		288,060
Estimated Future Capital Costs, $		0		0		0		0		3,750		0		3,750
Estimated Future Net Revenue (“FNR”), $		303,500		0		0		303,500		23,730		0		327,220
Discounted FNR at 10%, $		254,380		0		0		254,380		10,400		0		264,780
Discounted FNR at 15%, $		236,520		0		0		236,520		7,070		0		243,590
Estimated Net Revenues by Year, $
2016		126,540		0		0		126,540		0		0		126,540
2017		62,750		0		0		62,750		0		0		62,750
2018		36,920		0		0		36,920		80		0		37,000
Subtotal		226,210		0		0		226,210		80		0		226,290
Thereafter		77,290		0		0		77,290		23,650		0		100,930
Total		303,500		0		0		303,500		23,730		0		327,220
Estimated Average Net Production Rate, 2016
Oil/Condensate, B/D		9.1		0		0		9.1		0		0		9.1
Gas, Mcf/D		49.9		0		0		49.9		0		0		49.9
NGL, B/D		0.2		0		0		0.2		0		0		0.2

^a Column includes the Proved Developed Non-Producing, shut-in and behind-pipe classifications

^b Totals might not match detailed cash flows due to computer rounding

3345 Bee Cave Road, Suite 201    Austin, Texas 78746 USA    Tel 512.732.9812    Fax 512.732.9816

Houston American Energy Corporation - Year End Reserve Report
SEC Pricing as of December 31, 2015
February 15, 2016
Page 2 of 5

Purpose of Report

This report has been prepared to provide the management of Houston American Energy Corporation with a projection of estimated remaining Reserves and projected future net revenues as of December 31, 2015. These estimates have not been adjusted for risk.

Standards of Practice

This report has been prepared in accordance with our understanding of the Securities and Exchange Commission, SX Reg. § 210.4-10, dated November 18, 1981 as amended September 19, 1989, requiring adherence to definitions of “Proved” oil and gas Reserves. Additionally, at the request of Houston American, and within the most recently adopted and accepted SEC guidelines (Modernization of Oil and Gas Reporting; Final Rule; January 14, 2009), we have evaluated the Proved, Probable and Possible Reserves. The SEC oil and gas Reserve definitions are attached hereto.

Liquid hydrocarbon volumes are expressed in standard 42-gallon barrels. All natural gas volumes are sales gas expressed at the official pressure and temperature bases of the areas in which the gas Reserves are located.

All currencies in this report are expressed in U.S. dollars.

Reserve Esimates

Extrapolation of historical production data was utilized for those producing properties where sufficient data were available to suggest decline trends. Reserves assigned to the remaining producing properties and any non-producing assets were determined by analogy to offset wells producing from similar formations or by volumetric analysis. Reserves assigned by analogy and volumetric analysis are subject to greater revision than Reserves projected using established performance trends.

As of December 31, 2015, the PDP net remaining Reserves were estimated to be 8,850 barrels of oil/condensate, 57.7 MMcf of gas, and 100 barrels of natural gas liquids (“NGL”). The net present value, discounted at 10%, of the PDP Reserves was $254,380. Of the total PDP revenue, 72% was derived from oil/condensate production. The Reserve life index (“R/P”) for the PDP Reserves was estimated to be 2.9 years based on a 6:1 conversion rate.

The PROB net remaining Reserves were estimated to be 930 barrels of oil/condensate, 11.0 MMcf of gas, and 30 barrels of NGLs. The net present value, discounted at 10%, of the PROB Reserves was $10,400. Of the total revenue, 58% was derived from oil/condensate production.

The total Proved plus PROB net remaining Reserves were estimated to be 9,780 barrels of oil/condensate, 68.7 MMcf of gas, and 130 barrels of NGLs. The net present value, discounted at 10%, of the total Reserves was $264,780. Of the total revenue, 71% was derived from oil/condensate production.

3345 Bee Cave Road, Suite 201    Austin, Texas 78746 USA    Tel 512.732.9812    Fax 512.732.9816

Houston American Energy Corporation - Year End Reserve Report
SEC Pricing as of December 31, 2015
February 15, 2016
Page 3 of 5

Product Prices and Differentials

The base product prices of $50.13 per barrel and $2.63 per MMbtu utilized herein are reported by the Energy Information Administration for the closing Contract 1 NYMEX futures oil and gas prices on the first trading day of each month, averaged over the 2015 calendar year. NGL prices in this report were input as 100% of the oil price, and then an NGL price differential was applied on an individual lease basis.

As required by SEC regulations, no price escalations are included in this report. Realized product prices in this report reflect adjustments for heating content, premiums and basis differentials. Where applicable, transportation costs have been included.

Operating Costs and Expenditures

Direct lease operating expenses were input as dollars per month into the economic models. These data were supplied by Houston American Energy Corporation. Where applicable, lease operating costs were adjusted for non-recurring costs. Operating costs were not escalated in this report.

Severance and ad valorem taxes are deducted as a percentage of gross revenues or as a charge per unit of production, where applicable. The individual well projections of oil and gas ceased when the total operating expenses exceed the gross revenues.

Values Not Considered

In all cases, we have attempted to account for all deductions from gross revenues except for the following:

• Federal Income Taxes

• Depreciation, depletion, and/or amortization, if any

• Costs in excess of revenues of uneconomic leases

• Plugging and abandonment costs in excess of salvage value

• Environmental restoration costs, if any

• Product price hedges, if any

No value has been assigned to non-producing acreage held by production.

3345 Bee Cave Road, Suite 201    Austin, Texas 78746 USA    Tel 512.732.9812    Fax 512.732.9816

Houston American Energy Corporation - Year End Reserve Report
SEC Pricing as of December 31, 2015
February 15, 2016
Page 4 of 5

Report Qualifications

This report was prepared using conventional petroleum engineering procedures and techniques as were considered appropriate and necessary. The estimated future net revenues were based on projections of recoverable hydrocarbons, rates of production, timing of recompletions and drilling, proration by state and federal agencies, direct taxes, and product prices. All estimated future net revenues presented in this report are after the deduction of royalties, production costs, and development costs. This evaluation does not include indirect costs such as administrative, overhead, and other miscellaneous expenses. Any unusual combination of many factors including weather, possible changes in regulatory guidelines, political risk or acts of terrorism could result in future receipts being considerably less or more than those estimated herein.

THE REVENUES AND PRESENT WORTH OF FUTURE NET REVENUES PRESENTED HEREIN ARE NOT REPRESENTED TO BE MARKET VALUES EITHER FOR THE INDIVIDUAL PROPERTIES OR ON A TOTAL PROPERTY BASIS.

THE RESERVES AND REVENUE PROJECTIONS PRESENTED HEREIN ARE ONLY VALID AS OF THE EFFECTIVE DATE OF THE REPORT.

The Reserves and revenues for specific properties should be considered in context with the overall report.

Data Sources

Data including basic well information, geological interpretations, realized product prices, operating costs, initial test rates, and ownership interests were supplied by Houston American Energy Corporation. We have accepted these data as correct.

Historical production data were obtained from public sources, such as DrillingInfo.com and the records of the appropriate oil and gas regulatory agency. We retain in our files digital databases for all properties as well as hard copies of other information that we believe to be pertinent.

An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by Lonquist & Co. Possible environmental liability related to the properties has not been investigated nor considered.

3345 Bee Cave Road, Suite 201    Austin, Texas 78746 USA    Tel 512.732.9812    Fax 512.732.9816

Houston American Energy Corporation - Year End Reserve Report
SEC Pricing as of December 31, 2015
February 15, 2016
Page 5 of 5

Independent Evaluation

Neither Lonquist & Co. LLC nor any affiliated company or any of its employees have any interest or ownership in the subject properties and neither our employment to prepare this study nor the compensation is contingent on our findings herein.

	Sincerely.
	LONQUIST & CO., LLC Texas Registration No. F-8952
	Don E. Charbula, P.E. Vice President Texas License No. 73435
	Lisa B. Hunter, P.E. Senior Petroleum Engineer Texas License No. 64269     Date Signed: February 16, 2016 Austin, Texas

3345 Bee Cave Road, Suite 201    Austin, Texas 78746 USA    Tel 512.732.9812    Fax 512.732.9816

HOUSTON AMERICAN ENERGY CORPORATION

Estimated Future Reserves and Revenues
as of December 31, 2015

Selected Oil and Gas Properties
Louisiana, Oklahoma and Texas

SEC Guideline Case

 

TABLE OF CONTENTS

Letter of Transmittal

Area of Interest Map

SEC Definitions for Oil and Gas Reserves

Reserve and Revenue Projections

Summary by Reserve Classification

One-Line Property Listing

Detailed Projections and Production Plots

Proved Developed Producing

Probable – Behind Pipe

XML

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Mar. 08, 2016	Jun. 30, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	HOUSTON AMERICAN ENERGY CORP
Entity Central Index Key	0001156041
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$ 8.1
Entity Common Stock, Shares Outstanding		51,979,945
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015

XML

CONSOLIDATED BALANCE SHEETS - USD ($)	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS
Cash	$ 2,123,520	$ 4,052,212
Escrow receivable	262,016	321,428
Insurance claim receivable	0	8,612,681
Prepaid expenses and other current assets	38,257	124,960
TOTAL CURRENT ASSETS	2,423,793	13,111,281
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
CURRENT LIABILITIES
Accounts payable	23,195	181,683
Litigation settlement payable	0	7,000,000
Accrued legal fees	0	1,722,681
Contingent liability	0	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	$ 0	$ 0
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)	0
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

XML

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
SHAREHOLDERS' EQUITY
Preferred stock, par value (in dollars per share)	$ 0.001	$ 0.001
Preferred stock, authorized (in shares)	10,000,000	10,000,000
Preferred stock, issued (in shares)	0	0
Preferred stock, outstanding (in shares)	0	0
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, authorized (in shares)	150,000,000	150,000,000
Common stock, issued (in shares)	52,169,945	52,169,945
Common stock, outstanding (in shares)	52,169,945	52,169,945
Treasury Stock, Shares (in shares)	190,000	0

XML

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
CONSOLIDATED STATEMENTS OF OPERATIONS [Abstract]
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	0	(400,000)
Currency valuation loss	(97,103)	0
Other expense	0	(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 (in dollars per share)	$ (0.07)	$ (0.08)
Basic and diluted weighted average number of common shares outstanding (in shares)	52,159,726	52,169,945

XML

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY - USD ($)	Common Stock [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Retained Earnings (Deficit) [Member]	Total
Balance at Dec. 31, 2013	$ 52,170	$ 65,477,046	$ 0	$ (52,355,183)	$ 13,174,033
Balance (in shares) at Dec. 31, 2013	52,169,945
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Options issued to directors	$ 0	42,676	0	0	42,676
Options issued to employees	0	371,513	0	0	371,513
Restricted stock issued to employees	0	36,821	0	0	36,821
Net loss	0	0	0	(4,353,179)	(4,353,179)
Balance at Dec. 31, 2014	$ 52,170	65,928,056	0	(56,708,362)	9,271,864
Balance (in shares) at Dec. 31, 2014	52,169,945
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Options issued to directors	$ 0	22,938	0	0	22,938
Options issued to employees	0	68,687	0	0	68,687
Acquisition of treasury shares	0	0	$ (38,152)	0	$ (38,152)
Acquisition of treasury shares (in shares)			190,000		190,000
Net loss	0	0	$ 0	(3,830,206)	$ (3,830,206)
Balance at Dec. 31, 2015	$ 52,170	$ 66,019,681	$ (38,152)	$ (60,538,568)	$ 5,495,131
Balance (in shares) at Dec. 31, 2015	52,169,945		190,000

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 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
Share-based compensation	91,625	451,010
Accretion of asset retirement obligation	1,329	628
Contingent loss	0	400,000
Change in operating assets and liabilities:
Increase in income accounts receivable	0	(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	0
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 [Abstract]
Payment for acquisition of treasury shares	(38,152)	0
Net cash used in financing activities	(38,152)	0
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	0	0
Taxes paid	18,865	192,364
SUPPLEMENTAL NON-CASH INVESTING AND FINANCING ACTIVITIES
Accrued oil and gas development costs	0	105,241
Net change in estimate of asset retirement obligation	$ 4,214	$ 19,095

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NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2015

NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]

NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

General

Houston American Energy Corp. (a Delaware Corporation) (“the Company” or “HUSA”) was incorporated on April 2, 2001. The Company is engaged, as a non-operating joint owner, in the exploration, development, and production of natural gas, crude oil, and condensate from properties located principally in the Gulf Coast area of the United States and international locations with proven production, which to date has focused on Colombia, South America.

Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date of these consolidated financial statements. The Company has incurred continuing losses, negative operating cash flow and declining cash balances since 2011, including negative operating cash flow of $1,837,977 for the year ended December 31, 2015. These conditions, together with continued low oil and natural gas prices and financial commitments the Company has made relative to its Colombian properties as well as to investments in Australia, raise substantial doubt as to the Company’s ability to continue as a going concern. These financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.

To address these concerns, the Company may seek additional financing or may consider divestiture of certain assets. There can be no assurance that the Company will be successful in its efforts.

Consolidation

The accompanying consolidated financial statements include all accounts of HUSA and its subsidiaries (HAEC Louisiana E&P, Inc. and HAEC Caddo Lake E&P, Inc.). All significant inter-company balances and transactions have been eliminated in consolidation.

General Principles and Use of Estimates

The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America. In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to such potential matters as litigation, environmental liabilities, income taxes, and determination of proved reserves of oil and gas and asset retirement obligations. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

Reclassification

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

Cash and Cash Equivalents

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

Concentration of Credit Risk

Financial instruments that potentially subject the Company to a concentration of credit risk include cash and cash equivalents. The Company had cash deposits of approximately $1.8 million in excess of the FDIC’s current insured limit of $250,000 at December 31, 2015 for interest bearing accounts. The Company has not experienced any losses on its deposits of cash and cash equivalents.

Marketable Securities – Available for Sale

Management determines the appropriate classification of its investments in marketable securities at the time of purchase and reevaluates such determination at each balance sheet date. Equity securities not classified as trading securities are classified as available-for-sale. Available-for-sale securities are reported at fair value and unrealized gains and losses are included in stockholders' equity. Management determines fair value of its investments based on quoted market prices at each balance sheet date.

Accounts Receivable

Accounts receivable – other and escrow receivables have been evaluated for collectability and are recorded at their net realizable values.

Allowance for Accounts Receivable

The Company regularly reviews outstanding receivables and provides for estimated losses through an allowance for doubtful accounts when necessary. In evaluating the need for an allowance, the Company makes judgments regarding its customers' ability to make required payments, economic events and other factors. As the financial condition of these parties change, circumstances develop or additional information becomes available, an allowance for doubtful accounts may be required. When the Company determines that a customer may not be able to make required payments, the Company increases the allowance through a charge to income in the period in which that determination is made. As of December 31, 2015, the Company evaluated their receivables and determined an allowance was not required.

Oil and Gas Revenues

The Company recognizes sales revenues, net of royalties and net profits interests, based on the amount of gas, oil, and condensate sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when production has been delivered to a pipeline. The Company follows the sales method to account for natural gas imbalances. Sales may result in more or less of the Company’s share of pro-rata production from certain wells. When natural gas sales volumes exceeds the Company’s entitled share and the accumulated overproduced balance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company will record a liability. Historically, sales volumes have not materially differed from the Company’s entitled share of natural gas production and the Company did not have a material imbalance position in terms of volumes or values at December 31, 2015 or 2014.

Oil and Gas Properties

The Company uses the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs for unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. Capitalized costs include lease acquisition, geological and geophysical work, delay rentals, costs of drilling, completing and equipping the wells and any internal costs that are directly related to acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Proceeds from the sale or other disposition of oil and gas properties are generally treated as a reduction in the capitalized costs of oil and gas properties, unless the impact of such a reduction would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.

The Company categorizes its full cost pools as costs subject to amortization and costs not being amortized. The sum of net capitalized costs subject to amortization, including estimated future development and abandonment costs, are amortized using the unit-of-production method. Depletion and amortization for oil and gas properties was $754,892 and $348,197 for the years ended December 31, 2015 and 2014, respectively and accumulated amortization, depreciation and impairment was $54,587,826 and $52,114,846 at December 31, 2015 and 2014, respectively.

Costs Excluded

Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent costs of investments in unproved properties. The Company excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the costs subject to amortization.

Ceiling Test

Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X. The ceiling test determines a limit, on a country-by-country basis, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment (“DD&A”) and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, calculated for 2015 using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) with consideration of price change only to the extent provided by contractual arrangement, discounted at 10%, net of related tax effects. If capitalized costs exceed this limit, the excess is charged to expense and reflected as additional accumulated DD&A. During the year, the Company impaired oil and gas properties in the amount of $1,718,088.

Furniture and Equipment

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

Depreciation expense for office equipment was $1,865 and $11,700 for 2015 and 2014, respectively, and accumulated depreciation was $88,897 and $87,032 at December 31, 2015 and 2014, respectively.

Asset Retirement Obligations

For the Company, asset retirement obligations (“ARO”) represent the systematic, monthly accretion and depreciation of future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, an adjustment is made to the full cost pool, with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. Although the Company’s domestic policy with respect to ARO is to assign depleted wells to a salvager for the assumption of abandonment obligations before the wells have reached their economic limits, the Company has estimated its future ARO obligation with respect to its domestic operations. The ARO assets, which are carried on the balance sheet as part of the full cost pool, have been included in our amortization base for the purposes of calculating depreciation, depletion and amortization expense. For the purposes of calculating the ceiling test, the future cash outflows associated with settling the ARO liability have been included in the computation of the discounted present value of estimated future net revenues.

Joint Venture Expense

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

Income Taxes

Deferred income taxes are provided on a liability method whereby deferred tax assets and liabilities are established for the difference between the financial reporting and income tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

Stock-Based Compensation

The Company measures the cost of employee services received in exchange for stock and stock options based on the grant date fair value of the awards. The Company determines the fair value of stock option grants using the Black-Scholes option pricing model. The Company determines the fair value of shares of non-vested stock based on the last quoted price of our stock on the date of the share grant. The fair value determined represents the cost for the award and is recognized over the vesting period during which an employee is required to provide service in exchange for the award. As share-based compensation expense is recognized based on awards ultimately expected to vest, the Company reduces the expense for estimated forfeitures based on historical forfeiture rates. Previously recognized compensation costs may be adjusted to reflect the actual forfeiture rate for the entire award at the end of the vesting period. Excess tax benefits, if any, are recognized as an addition to paid-in capital.

Preferred Stock

The Company has authorized 10,000,000 shares of preferred stock with a par value of $0.001. The Board of Directors shall determine the designations, rights, preferences, privileges and voting rights of the preferred stock as well as any restrictions and qualifications thereon. No shares of preferred stock have been issued.

Net Income (Loss) Per Share

Basic net income (loss) per share is computed by dividing the net income (loss) attributable to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted net income (loss) per share is computed by dividing the net income (loss) attributable to common shareholders by the weighted-average number of common and common equivalent shares outstanding during the period. Common share equivalents included in the diluted computation represent shares issuable upon assumed exercise of stock options and warrants using the treasury stock and “if converted” method. For periods in which net losses are incurred, weighted average shares outstanding is the same for basic and diluted loss per share calculations, as the inclusion of common share equivalents would have an anti-dilutive effect.

For the year ended December 31, 2015, outstanding options to purchase 4,432,165 shares of common stock were excluded from the calculation of diluted net loss per share because they were anti-dilutive. For the year ended December 31, 2014, outstanding options to purchase 3,392,832 shares of common stock were excluded from the calculation of diluted net loss per share because they were anti-dilutive.

Concentration of Risk

As a non-operator oil and gas exploration and production company, and through its interest in a limited liability company (“Hupecol”) and concessions operated by Hupecol in the South American country of Colombia, the Company is dependent on the personnel, management and resources of Hupecol to operate efficiently and effectively.

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

The Company currently has interests in concessions in Colombia and expects to be active in Colombia for the foreseeable future. The political climate in Colombia is unstable and could be subject to radical change over a very short period of time. In the event of a significant negative change in political and economic stability in the vicinity of the Company’s Colombian operations, the Company may be forced to abandon or suspend its efforts. Either of such events could be harmful to the Company’s expected business prospects.

At December 31, 2015, 67.5% of the Company’s net oil and gas property investment, and 0% of its revenue for the year ended December 31, 2015, was with or derived from interests operated in Colombia.

For 2015, our oil production from the Company’s mineral interests was sold to U.S. oil marketing companies based on the highest bid. The gas production is sold to U.S. natural gas marketing companies based on the highest bid. No purchaser accounted for more than 10% of our oil and gas sales.

The Company reviews accounts receivable balances when circumstances indicate a balance may not be collectible. Based upon the Company’s review, no allowance for uncollectible accounts was deemed necessary at December 31, 2015 and 2014, respectively.

Subsequent Events

The Company evaluated subsequent events for disclosure from December 31, 2015 through the date the consolidated financial statements were issued.

Recent Accounting Developments

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

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ESCROW RECEIVABLE

12 Months Ended

Dec. 31, 2015

ESCROW RECEIVABLE [Abstract]

ESCROW RECEIVABLE

NOTE 2—ESCROW RECEIVABLE

At December 31, 2015 and December 31, 2014, the Company’s balance sheet reflected the following escrow receivables relating to various oil and gas properties previously sold by the Company:

	December 31, 2015		December 31, 2014
Tambaqui Escrow	$	—	$	4,331
HDC LLC and HL LLC 15% Escrow		251,125		294,383
HDC LLC and HL LLC 5% Contingency		10,891		11,256
HC LLC 5% Contingency		—		11,458
Total	$	262,016	$	321,428

Changes in escrow receivables during 2015 reflect the release of an aggregate of $59,412 from the various escrow accounts.

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OIL AND GAS PROPERTIES

12 Months Ended

Dec. 31, 2015

OIL AND GAS PROPERTIES [Abstract]

OIL AND GAS PROPERTIES

NOTE 3—OIL AND GAS PROPERTIES

Evaluated Oil and Gas Properties

Evaluated oil and gas properties subject to amortization at December 31, 2015 included the following:

	United States			South America			Total
Evaluated properties being amortized	$	5,385,898		$	49,454,702		$	54,840,600
Accumulated depreciation, depletion, amortization and impairment		(5,133,124	)		(49,454,702	)		(54,587,826	)
Net capitalized costs	$	252,774		$	—		$	252,774

Evaluated oil and gas properties subject to amortization at December 31, 2014 included the following:

	United States			South America			Total
Evaluated properties being amortized	$	4,570,915		$	49,454,702		$	54,025,617
Accumulated depreciation, depletion, amortization and impairment		(2,660,144	)		(49,454,702	)		(52,114,846	)
Net capitalized costs	$	1,910,771		$	—		$	1,910,771

Unevaluated Oil and Gas Properties

Unevaluated oil and gas properties not subject to amortization at December 31, 2015 included the following:

	United States		South America		Total
Leasehold acquisition costs	$	761,545	$	141,319	$	902,864
Geological, geophysical, screening and evaluation costs		4,143		1,972,056		1,976,199
Total	$	765,688	$	2,113,375	$	2,879,063

Unevaluated oil and gas properties not subject to amortization at December 31, 2014 included the following:

	United States		South America		Total
Leasehold acquisition costs	$	868,301	$	141,319	$	1,009,620
Geological, geophysical, screening and evaluation costs		683,976		1,892,688		2,576,664
Total	$	1,552,277	$	2,034,007	$	3,586,284

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ASSET RETIREMENT OBLIGATION

12 Months Ended

Dec. 31, 2015

ASSET RETIREMENT OBLIGATION [Abstract]

ASSET RETIREMENT OBLIGATION

NOTE 4—Asset Retirement Obligations

The following table describes changes in our asset retirement liability during each of the years ended December 31, 2015 and 2014.

	2015			2014
ARO liability at January 1	$	28,147		$	8,414
Accretion expense		1,329			628
Liabilities incurred from drilling		—			20,812
Changes in estimates		(4,214	)		(1,717	)
ARO liability at December 31	$	25,262		$	28,147

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STOCK-BASED COMPENSATION

12 Months Ended

Dec. 31, 2015

STOCK-BASED COMPENSATION [Abstract]

STOCK-BASED COMPENSATION

NOTE 5—STOCK-BASED COMPENSATION

On August 12, 2005, the Company’s Board of Directors adopted the Houston American Energy Corp. 2005 Stock Option Plan (the “2005 Plan”). The terms of the 2005 Plan allow for the issuance of up to 500,000 options to purchase 500,000 shares of the Company’s common stock.

In 2008, the Company’s Board of Directors adopted the Houston American Energy Corp. 2008 Equity Incentive Plan (the “2008 Plan” and, together with the 2005 Plan, the “Plans”). The terms of the 2008 Plan allowed for the issuance of up to 2,200,000 shares of the Company’s common stock pursuant to the grant of stock options and restricted stock. Persons eligible to participate in the Plans are key employees, consultants and directors of the Company.

During 2012 and 2013, the Company’s board of directors and shareholders adopted amendments to the Company’s 2008 Equity Incentive Plan to increase the shares reserved to 6,000,000 shares.

Stock Option Activity

In 2014, options to purchase an aggregate of 200,000 shares were granted to non-employee directors and options to purchase an aggregate of 600,000 shares were granted to an employee.

The 200,000 options granted to non-employee directors vested 20% on the grant date and vest as to the remaining 80% nine months from the grant date, have a ten-year life and have an exercise price of $0.415 per share. The option grants to non-employee directors were valued on the date of grant at $46,191 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.57%, (2) expected life in years of 4.65, (3) expected stock volatility of 103.6%, and (4) expected dividend yield of 0%. The Company determined the options qualify as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life.

The 600,000 options granted to an employee vest 1/3 on each of the first three anniversaries of the grant date, subject to acceleration of vesting in the event of certain changes in control or the realization of revenues from oil and gas production on the Serrania prospect or receipt of proceeds from the sale of the Serrania prospect, have a ten year life and have an exercise price of $0.415 per share. The option grants to the employee were valued on the date of grant at $126,355 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.57%, (2) expected life in years of 4.65, (3) expected stock volatility of 103.6%, and (4) expected dividend yield of 0%. The Company determined the options qualify as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life.

In 2015, options to purchase an aggregate of 8,333 shares were granted to a new non-employee director, options to purchase an aggregate of 900,000 shares were granted to a new officer and options to purchase an aggregate of 200,000 shares were granted to non-employee directors.

The 8,333 options granted to a new non-employee director vested 20% on the grant date and vest as to the remaining 80% nine months from the grant date, have a ten-year life and have an exercise price of $0.2158 per share. The option grant to the non-employee director was valued on the date of grant at $805 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.36%, (2) expected life in years of 4.98, and (3) expected stock volatility of 106%. The Company determined the option qualifies as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life.

The 900,000 options granted to an employee have a ten year life and an exercise price of $0.2158 per share and vest 1/3 on each of the first three anniversaries of the grant date, subject to acceleration of vesting in the event of certain changes in control or (i) the receipt of $10 million or more in aggregate gross proceeds from the sale of equity securities or securities convertible into equity securities, or (ii) the acquisition by the Company of $10 million or more in aggregate purchase price of oil and gas properties. The option grant to the employee was valued on the date of grant at $82,000 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of1.36%, (2) expected life in years of 4.98, and (3) expected stock volatility of 106%. The Company determined the option qualifies as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life.

The 200,000 options granted to non-employee directors vested 20% on the grant date and vest as to the remaining 80% nine months from the grant date, have a ten-year life and have an exercise price of $0.2028 per share. The option grants to non-employee directors were valued on the date of grant at $17,370 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.73% (2) expected life in years of 5.01, and (3) expected stock volatility of 105%. The Company determined the options qualify as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life.

Option activity during 2015 and 2014 was as follows:

	Options			Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in Years)		Aggregate Intrinsic Value
Outstanding at December 31, 2013		2,592,832		$	4.07
Granted		800,000		$	0.42
Exercised		—		$	—
Forfeited		—		$	—
Outstanding at December 31, 2014		3,392,832		$	3.21
Granted		1,108,333		$	0.21
Exercised		—		$	—
Forfeited		(69,000	)	$	2.55
Outstanding at December 31, 2015		4,432,165		$	2.47		6.77	$	—

During 2015 and 2014, the Company recognized $91,625 and $414,189, respectively, of stock compensation expense attributable to outstanding stock option grants, including current period grants and unamortized expense associated with prior period grants.

As of December 31, 2015, non-vested options totaled 1,466,666 and total unrecognized stock-based compensation expense related to non-vested stock options was $127,591. The unrecognized expense is expected to be recognized over a weighted average period of 1.83 years. The weighted average remaining contractual term of the outstanding options and exercisable options at December 31, 2015 is 6.77 years and 5.62 years, respectively.

As of December 31, 2015, there were 1,567,835 shares of common stock available for issuance pursuant to future stock or option grants under the Plans.

Restricted Stock Activity

During 2011, the Company granted to officers an aggregate of 45,000 shares of restricted stock, which shares vest over a period of three years. The fair value of $743,400 was determined based on the fair market value of the shares on the date of grant. This value was amortized over the vesting period, and during 2015 and 2014, $0 and $36,821 was amortized to expense respectively. As of December 31, 2014, there was $0 of unrecognized compensation cost related to unvested restricted stock.

Share-Based Compensation Expense

The following table reflects share-based compensation recorded by the Company for 2015 and 2014:

	2015			2014
Share-based compensation expense included in general and administrative expense	$	91,625		$	451,010
Earnings per share effect of share-based compensation expense	$	(0.00	)	$	(0.01	)

Treasury Stock

We account for repurchases of common stock using the cost method with common stock in treasury classified in the consolidated balance sheets as a reduction of shareholders’ equity. During the year ending December 31, 2015, the Company acquired 190,000 shares of common stock for $38,152.

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TAXES

12 Months Ended

Dec. 31, 2015

TAXES [Abstract]

TAXES

NOTE 6—TAXES

The following table sets forth a reconciliation of the statutory federal income tax for the years ending December 31, 2015 and 2014.

	2015			2014
Loss before income taxes	$	(3,811,341	)	$	(4,350,996	)
Income tax benefit computed at statutory rates	$	(1,333,969	)	$	(1,523,613	)
Permanent differences, nondeductible expenses		501			141,446
Increase (decrease) in valuation allowance		635,888			(696,514	)
Return to accrual items		(764	)		1,178,681
Other adjustment		717,209			—
NOL adjustment		—			902,183
Tax provision	$	18,865		$	2,183
Total provision
Foreign	$	18,865		$	2,183
Total provision	$	18,865		$	2,183

At December 31, 2015 the Company has a federal tax loss carry forward of $47,415,085 and a foreign tax credit carry forward of $505,745, both of which have been fully reserved.

The tax effects of the temporary differences between financial statement income and taxable income are recognized as a deferred tax asset and liabilities. Significant components of the deferred tax asset and liability as of December 31, 2015 and 2014 are set out below.

	2015			2014
Non-Current Deferred tax assets:
Net operating loss carry forward	$	16,255,870		$	15,764,184
Foreign tax credit carry forward		505,745			486,880
Deferred state tax		23,277			23,277
Stock compensation		3,091,356			3,525,473
Book in excess of tax depreciation, depletion and capitalization methods on oil and gas properties		(713,832	)		(1,524,310	)
Other		(327,600	)		(76,576	)
Total Non-Current Deferred tax assets		18,834,816			18,198,928
Valuation Allowance		(18,834,816	)		(18,198,928	)
Net deferred tax asset	$	—		$	—

Foreign Income Taxes

The Company owns direct ownership in several properties in Colombia operated by Hupecol. Colombia’s current income tax rate is 25%. During 2015 and 2014, we recorded foreign tax expense of $18,865 and $2,183, respectively.

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RELATED PARTIES

12 Months Ended

Dec. 31, 2015

RELATED PARTIES [Abstract]

RELATED PARTIES

NOTE 7—RELATED PARTIES

In conjunction with the Company’s efforts to secure oil and gas prospects, financing and services, in lieu of salary or other forms of compensation, during 2005, the Company granted to John F. Terwilliger, a principal shareholder and then Chief Executive Officer, and Orrie L. Tawes, a principal shareholder and Director, overriding royalty interests (ORRI) in select mineral properties of the Company, including all current and future properties in Colombia in which Messrs. Terwilliger and Tawes each hold a 1.5% ORRI. During 2015 and 2014, Mr. Terwilliger received royalty payments relating to those properties totaling $919 and $20,682, respectively, and Mr. Tawes received royalty payments relating to those properties totaling $919 and $20,682, respectively.

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Dec. 31, 2015

COMMITMENTS AND CONTINGENCIES [Abstract]

COMMITMENTS AND CONTINGENCIES

NOTE 8—COMMITMENTS AND CONTINGENCIES

Lease Commitment

The Company leases office facilities under an operating lease agreement that expires May 31, 2017. The lease agreement requires future payments as follows:

Year	Amount
2016	$	96,162
2017		40,469
Total	$	136,631

Total rental expense was $95,711 and $88,709 in 2015 and 2014, respectively. The Company does not have any capital leases or other operating lease commitments.

Legal Contingencies

The Company is subject to legal proceedings, claims and liabilities that arise in the ordinary course of its business. The Company accrues for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as further information develops or circumstances change.

Silverman Shareholder Class Action Suit. On April 27, 2012, a purported class action lawsuit was filed in the U.S. District Court for the Southern District of Texas against the Company and certain of its executive officers: Steve Silverman v. Houston American Energy Corp. et al., Case No. 4:12-CV-1332. The complaint generally alleged that, between March 29, 2010 and April 18, 2012, all of the defendants violated Sections 10(b) of the Securities Exchange Act of 1934 and SEC Rule 10b-5 and the individual defendants violated Section 20(a) of the Exchange Act in making materially false and misleading statements including certain statements related to the status and viability of the Tamandua #1 well on the Company’s CPO 4 prospect. Two additional class action lawsuits were filed against us in May 2012. The complaints sought unspecified damages, interest, attorneys’ fees, and other costs. On September 20, 2012, the court consolidated the class action lawsuits and appointed a lead plaintiff and, on November 15, 2012, the lead plaintiffs filed an amended complaint. The amended complaint, among other things, expanded the putative class period to November 9, 2009 to April 18, 2012 and added allegations challenging a November 2009 estimate concerning the CPO 4 prospect. On January 14, 2013, the Company filed a motion to dismiss and, on August 22, 2013, the court granted the motion and dismissed the complaint. The plaintiffs subsequently filed a Notice of Appeal of the dismissal of the complaint. On July 15, 2014, the U.S. Court of Appeals for the Fifth Circuit reversed the dismissal of the case. The appellate court ruling focused on the sufficiency of the pleadings in the case, made no determination regarding the merits of the factual allegations, and remanded the case to the District Court for further proceedings. In October 2014, the parties reached an agreement in principle to settle the consolidated lawsuit. The settlement, which provided for a $7,000,000 payment expected to be fully funded by the Company’s insurance, was subject to preliminary and final approval of the court. The parties submitted the settlement to the court for approval on December 31, 2014. The court signed an order on April 16, 2015 preliminarily approving the settlement. Pursuant to the terms of the settlement, the Company, through its insurer, was required to escrow settlement funds in the amount of $7,000,000. In May 2015, the Company's insurer deposited the required funds into an escrow account to fund the settlement. On July 29, 2015, the court rendered a final judgment approving the settlement and dismissed the case with prejudice. As a result, the $7,000,000 litigation settlement payable and the related insurance claim receivable were each reflected as settled in 2015.

SEC Administrative Proceeding. On August 4, 2014, following a multi-year investigation, the SEC instituted administrative cease-and-desist proceedings pursuant to Section 8A of the Securities Act of 1933 and 21C of the Securities Exchange Act of 1934, styled In the Matter of Houston American EnergyCorp., John F.Terwilliger, Jr.,Undiscovered Equities, Inc. and Kevin T.McKnight. The administrative proceeding alleged that Mr. Terwilliger and, in turn, Houston American Energy, made false and misleading statements with respect to the CPO 4 prospect and promoted those statements through Undiscovered Equities and its principal, Kevin McKnight. The SEC was seeking a determination from an administrative law judge as to whether (i) the allegations of the SEC were true; (ii) Houston American Energy and Mr. Terwilliger should be ordered to (A) cease-and-desist from committing or causing violations of Section 10(b) of the Exchange Act and Rule 10b-5 thereunder, (B) pay a civil penalty pursuant to Section 8A(g) of the Securities Act and Section 21B(a) of the Exchange Act, and (C) pay disgorgement pursuant to Section 8A(e) of the Securities Act and Sections 21B(e) and 21C(e) of the Exchange Act; and (iii) Mr. Terwilliger should be prohibited from acting as an officer and director of a public company pursuant to Section 8A(f) of the Securities Act and Section 21C(f) of the Exchange Act.

At December 31, 2014, the administrative proceeding was pending and was scheduled for trial in January 2015. The trial was stayed in January 2015 pending consideration by the Commission of a proposed settlement. On April 16, 2015, the Commission formally approved the settlement. Pursuant to the terms of the settlement, among other things, the Company paid a penalty of $400,000 and the Company’s Chief Executive Officer resigned and paid a penalty of $150,000. The Company, at December 31, 2014, had recorded on its balance sheet a contingent liability, and on its statement of operations a contingent loss of $400,000 relating to the settlement. The Company has an insurance policy that insures for legal fees incurred in connection with the above administrative proceeding. At December 31, 2014, the Company had recorded an insurance claim receivable of $1,612,681 for fees which have been incurred, but not yet reimbursed by its insurance Company. As of December 31, 2015, there was no outstanding insurance claim receivable related to unpaid accrued legal fees.

Environmental Contingencies

The Company’s oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require the Company to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on its results of operations, competitive position or financial condition as well as the industry in general. Under these environmental laws and regulations, the Company could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether the Company was responsible for the release or if its operations were standard in the industry at the time they were performed. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks.

Development Commitments

During the ordinary course of oil and gas prospect development, the Company commits to a proportionate share for the cost of acquiring mineral interests, drilling exploratory or development wells and acquiring seismic and geological information.

Production Incentive Compensation Plan

In August 2013, the Company’s compensation committee adopted a Production Incentive Compensation Plan. The purpose of the Plan is to encourage employees and consultants participating in the Plan to identify and secure for the Company participation in attractive oil and gas opportunities.

Under that Plan, the committee may establish one or more Pools and designate employees and consultants to participate in those Pools and designate prospects and wells, and a defined percentage of the Company’s revenues from those wells, to fund those Pools. Only prospects acquired on or after establishment of the Plan, and excluding all prospects in Colombia, may be designated to fund a Pool. The maximum percentage of the Company’s share of revenues from a well that may be designated to fund a Pool is 2% (the “Pool Cap”); provided, however, that with respect to wells with a net revenue interest to the 8/8 of less than 73%, the Pool Cap with respect to such wells shall be reduced on a 1-for-1 basis such that no portion of the Company’s revenues from a well may be designated to fund a Pool if the NRI is 71% or less.

Designated participants in a Pool will be assigned a specific percentage out of the Company’s revenues assigned to the Pool and will be paid that percentage of such revenues from all wells designated to such Pool and spud during that participant’s employment or services with the Company. In no event may the percentage assigned to the Company’s chief executive officer relative to any well within a Pool exceed one-half of the applicable Pool Cap for that well. Payouts of revenues funded into Pools shall be made to participants not later than 60 days following year end, subject to the committee’s right to make partial interim payouts. Participants will continue to receive their percentage share of revenues from wells included in a Pool and spud during the term of their employment or service so long as revenues continue to be derived by the Company from those wells even after termination of employment or services of the Participant; provided, however, that a participant’s interest in all Pools shall terminate on the date of termination of employment or services where such termination is for cause.

In the event of certain changes in control of the Company, the acquirer or survivor of such transaction must assume all obligations under the Plan; provided, however, that in lieu of such assumption obligation, the committee may, at its sole discretion, assign overriding royalty interests in wells to substantially mirror the rights of participants under the Plan. Similarly, the committee may, at any time, assign overriding royalty interests in wells in settlement of obligations under the Plan.

The Plan is administered by the Company’s compensation committee which shall consult with the Company’s chief executive officer relative to Pool participants, prospects, wells and interests assign although the committee will have final and absolute authority to make all such determinations.

During 2015, no grants were made under the plan.

The Company records amounts payable under the plan as a reduction to revenue as revenues are recognized from prospects included in pools covered by the plan based on the participants’ interest in such prospect revenues and records the same as accounts payable until such time as such amounts are paid out. The obligation associated with the plan totaled $0 at December 31, 2015

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SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2015

SUBSEQUENT EVENTS [Abstract]

SUBSEQUENT EVENTS

NOTE 9—SUBSEQUENT EVENTS

In February 2016, the Company agreed to purchase ordinary shares (the “Shares”) of Tamboran Resources Limited, an Australian oil and gas company (“Tamboran”), for $1,000,000. The Shares represent a 12.5% equity ownership interest in Tamboran. Pursuant to the terms of the purchase of the Shares, the Company has certain anti-dilution rights for a period of nine months. Closing of the planned investment is subject to satisfaction of certain conditions on the part of Tamboran, including the receipt by Tamboran of funding from investors other than the Company in an amount not less than A$705,000.

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GEOGRAPHICAL INFORMATION

12 Months Ended

Dec. 31, 2015

GEOGRAPHICAL INFORMATION [Abstract]

GEOGRAPHICAL INFORMATION

NOTE 10—GEOGRAPHICAL INFORMATION

The Company currently has operations in two geographical areas, the United States and Colombia. Revenues for the years ended December 31, 2015 and 2014 and long-lived assets as of December 31, 2015 and 2014 attributable to each geographical area are presented below:

	2015				2014
	Revenues		Long Lived Assets, Net		Revenues		Long Lived Assets, Net
North America	$	429,435	$	1,019,569	$	363,455	$	3,466,020
South America		—		2,113,374		—		2,034,007
Total	$	429,435	$	3,132,943	$	363,455	$	5,500,027

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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

12 Months Ended

Dec. 31, 2015

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) [Abstract]

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

NOTE 11—SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)

This footnote provides unaudited information required by FASB ASC Topic 932, Extractive Activities—Oil and Gas.

Geographical Data

The following table shows the Company’s oil and gas revenues and lease operating expenses, which excludes the joint venture expenses incurred in South America, by geographic area:

	2015		2014
Revenues
North America	$	429,435	$	363,455
South America		—		—
	$	429,435	$	363,455
Production Cost
North America	$	148,067	$	113,233
South America		—		—
	$	148,067	$	113,233

Capital Costs

Capitalized costs and accumulated depletion relating to the Company’s oil and gas producing activities as of December 31, 2015, all of which are onshore properties located in the United States and Colombia, South America are summarized below:

	United States			South America			Total
Unproved properties not being amortized	$	765,688		$	2,113,375		$	2,879,063
Proved properties being amortized		5,385,898			49,454,702			54,840,600
Accumulated depreciation, depletion, amortization and impairment		(5,133,124	)		(49,454,702	)		(54,587,826	)
Net capitalized costs	$	1,018,462		$	2,113,375		$	3,131,837

Amortization Rate

The amortization rate per unit based on barrel of oil equivalents was $66.08 for the United States and $0 for South America for the year ended December 31, 2015.

Acquisition, Exploration and Development Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities as of December 31, 2015 and 2014 are summarized below:

	2015
	United States		South America
Property acquisition costs:
Proved	$	16,669	$	—
Unproved		—		—
Exploration costs		72,500		79,511
Development costs		—		—
Total costs incurred	$	89,169	$	79,511

	2014
	United States		South America
Property acquisition costs:
Proved	$	54,716	$	—
Unproved		184,612		9,984
Exploration costs		3,005,469		234,487
Development costs		—		—
Total costs incurred	$	3,244,797	$	244,471

Reserve Information and Related Standardized Measure of Discounted Future Net Cash Flows

In December 2009, the Company adopted revised oil and gas reserve estimation and disclosure requirements. The primary impact of the new disclosures is to conform the definition of proved reserves with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The accounting standards update revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period before the end of the year rather than the year-end price, must be used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The rules also allow for the use of reliable technology to estimate proved oil and gas reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. The unaudited supplemental information on oil and gas exploration and production activities has been presented in accordance with the new reserve estimation and disclosure rules. Disclosures by geographic area include the United States and South America, which consists of our interests in Colombia. The supplemental unaudited presentation of proved reserve quantities and related standardized measure of discounted future net cash flows provides estimates only and does not purport to reflect realizable values or fair market values of the Company’s reserves. Volumes reported for proved reserves are based on reasonable estimates. These estimates are consistent with current knowledge of the characteristics and production history of the reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, significant changes to these estimates can be expected as future information becomes available.

Proved reserves are those estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment, and operating methods.

The reserve estimates set forth below were prepared by Lonquist & Co., LLC (“Lonquist”), utilizing reserve definitions and pricing requirements prescribed by the SEC. Lonquist is an independent professional engineering firm specializing in the technical and financial evaluation of oil and gas assets. Lonquist’s report was conducted under the direction of Don E. Charbula, P.E., Vice President of Lonquist. 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 and its employees have no interest in the Company, and were objective in determining the results of the Company’s reserves. Lonquist used a combination of production performance, offset analogies, seismic data and their interpretation, subsurface geologic data and core data, along with estimated future operating and development costs as provided by the Company and based upon historical costs adjusted for known future changes in operations or development plans, to estimate our reserves. The Company does not operate any of its oil and gas properties.

Total estimated proved developed and undeveloped reserves by product type and the changes therein are set forth below for the years indicated.

	United States						South America				Total
	Gas (mcf)			Oil (bbls)			Gas (mcf)		Oil (bbls)		Gas (mcf)			Oil (bbls)
Total proved reserves
Balance December 31, 2013		36,810			11,150			—		—		36,810			11,150
Extensions and discoveries		24,944			32,090			—		—		24,944			32,090
Revisions of prior estimates		23,673			(5,958	)		—		—		23,673			(5,958	)
Production		(12,717	)		(3,152	)		—		—		(12,717	)		(3,152	)
Balance December 31, 2014		72,710			34,130			—		—		72,710			34,130
Revisions to prior estimates		17,136			(19,212	)		—		—		17,136			(19,212	)
Production		(32,146	)		(6,068	)		—		—		(32,146	)		(6,068	)
Balance December 31, 2015		57,700			8,850			—		—		57,700			8,850
Proved developed reserves
at December 31, 2014		72,710			34,130			—		—		72,710			34,130
at December 31, 2015		57,700			8,850			—		—		57,700			8,850
Proved undeveloped reserves
at December 31, 2014		—			—			—		—		—			—
at December 31, 2015		—			—			—		—		—			—

During 2015 and 2014, the Company recorded extensions and discoveries resulting from its ongoing drilling operations in the United States. As of December 31, 2015, the Company had no proved undeveloped (“PUD”) reserves. No PUD reserves as of December 31, 2014 were converted to proved developed producing reserves in 2015.

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is computed using average first-day-of the-month prices for oil and gas during the preceding 12 month period (with consideration of price changes only to the extent provided by contractual arrangements), applied to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated related future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated), and assuming continuation of existing economic conditions. Future income tax expenses give effect to permanent differences and tax credits but do not reflect the impact of continuing operations including property acquisitions and exploration. The estimated future cash flows are then discounted using a rate of ten percent a year to reflect the estimated timing of the future cash flows.

Standardized measure of discounted future net cash flows at December 31, 2015:

	United States			South America		Total
Future cash flows from sales of oil and gas	$	611,520		$	—	$	611,520
Future production cost		(308,020	)		—		(308,020	)
Future net cash flows		303,500			—		303,500
10% annual discount for timing of cash flow		(49,120	)		—		(49,120	)
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	$	254,380		$	—	$	254,380
Changes in standardized measure:
Change due to current year operations
Sales, net of production costs		(281,368	)		—		(285,582	)
Change due to revisions in standardized variables:
Accretion of discount		183,828			—		183,828
Net change in sales and transfer price, net of production costs		(405,129	)		—		(405,129	)
Revision and others		(176,014	)		—		(176,014	)
Changes in production rates and other		(617,498	)		—		(613,285	)
Net		(1,296,181	)		—		(1,296,181	)
Beginning of year		1,550,561			—		1,550,561
End of year	$	254,380		$	—	$	254,380

Standardized measure of discounted future net cash flows at December 31, 2014:

	United States			South America		Total
Future cash flows from sales of oil and gas	$	3,579,990		$	—	$	3,579,990
Future production cost		(1,091,790	)		—		(1,091,790	)
Future income tax		(287,709	)		—		(287,709	)
Future net cash flows		2,200,491			—		2,200,491
10% annual discount for timing of cash flow		(649,930	)		—		(649,930	)
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	$	1,550,561		$	—	$	1,550,561
Changes in standardized measure:
Change due to current year operations
Sales, net of production costs		(250,222	)		—		(250,222	)
Change due to revisions in standardized variables:
Income taxes		(287,709	)		—		(287,709	)
Accretion of discount		112,021			—		112,021
Net change in sales and transfer price, net of production costs		(193,777	)		—		(193,777	)
Discoveries		999,242			—		999,242
Changes in production rates and other		451,971			—		451,971
Net		831,526			—		831,526
Beginning of year		719,035			—		719,035
End of year	$	1,550,561		$	—	$	1,550,561

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SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

12 Months Ended

Dec. 31, 2015

SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) [Abstract]

SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

NOTE 12—SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

	Three Months Ended
	March 31,			June 30,			Sept. 30,			Dec. 31,
2015
Operating revenue	$	101,971		$	114,122		$	124,448		$	88,894
Loss from operations		(1,191,769	)		(339,488	)		(468,332	)		(1,735,182	)
Net loss		(1,187,064	)		(351,808	)		(463,566	)		(1,827,768	)
Loss per common share – basic	$	(0.02	)	$	(0.01	)	$	(0.01	)	$	(0.04	)
Loss per common share – diluted	$	(0.02	)	$	(0.01	)	$	(0.01	)	$	(0.04	)
2014
Operating revenue	$	106,023		$	67,450		$	56,805		$	133,177
Loss from operations		(536,105	)		(684,728	)		(512,919	)		(2,224,590	)
Net loss		(535,368	)		(683,644	)		(511,653	)		(2,222,514	)
Loss per common share – basic	$	(0.01	)	$	(0.01	)	$	(0.01	)	$	(0.04	)
Loss per common share – diluted	$	(0.01	)	$	(0.01	)	$	(0.01	)	$	(0.04	)

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NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2015

NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]

Going Concern

Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date of these consolidated financial statements. The Company has incurred continuing losses, negative operating cash flow and declining cash balances since 2011, including negative operating cash flow of $1,837,977 for the year ended December 31, 2015. These conditions, together with continued low oil and natural gas prices and financial commitments the Company has made relative to its Colombian properties as well as to investments in Australia, raise substantial doubt as to the Company’s ability to continue as a going concern. These financial statements do not include any adjustments that might be necessary if the Company is unable to continue as a going concern.

To address these concerns, the Company may seek additional financing or may consider divestiture of certain assets. There can be no assurance that the Company will be successful in its efforts.

Consolidation

Consolidation

The accompanying consolidated financial statements include all accounts of HUSA and its subsidiaries (HAEC Louisiana E&P, Inc. and HAEC Caddo Lake E&P, Inc.). All significant inter-company balances and transactions have been eliminated in consolidation.

General Principles and Use of Estimates

General Principles and Use of Estimates

The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America. In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to such potential matters as litigation, environmental liabilities, income taxes, and determination of proved reserves of oil and gas and asset retirement obligations. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

Reclassification

Reclassification

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

Cash and Cash Equivalents

Cash and Cash Equivalents

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

Concentration of Credit Risk

Concentration of Credit Risk

Financial instruments that potentially subject the Company to a concentration of credit risk include cash and cash equivalents. The Company had cash deposits of approximately $1.8 million in excess of the FDIC’s current insured limit of $250,000 at December 31, 2015 for interest bearing accounts. The Company has not experienced any losses on its deposits of cash and cash equivalents.

Marketable Securities - Available for Sale

Marketable Securities – Available for Sale

Management determines the appropriate classification of its investments in marketable securities at the time of purchase and reevaluates such determination at each balance sheet date. Equity securities not classified as trading securities are classified as available-for-sale. Available-for-sale securities are reported at fair value and unrealized gains and losses are included in stockholders' equity. Management determines fair value of its investments based on quoted market prices at each balance sheet date.

Accounts Receivable

Accounts Receivable

Accounts receivable – other and escrow receivables have been evaluated for collectability and are recorded at their net realizable values.

Allowance for Accounts Receivable

Allowance for Accounts Receivable

The Company regularly reviews outstanding receivables and provides for estimated losses through an allowance for doubtful accounts when necessary. In evaluating the need for an allowance, the Company makes judgments regarding its customers' ability to make required payments, economic events and other factors. As the financial condition of these parties change, circumstances develop or additional information becomes available, an allowance for doubtful accounts may be required. When the Company determines that a customer may not be able to make required payments, the Company increases the allowance through a charge to income in the period in which that determination is made. As of December 31, 2015, the Company evaluated their receivables and determined an allowance was not required.

Oil and Gas Revenues

Oil and Gas Revenues

The Company recognizes sales revenues, net of royalties and net profits interests, based on the amount of gas, oil, and condensate sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when production has been delivered to a pipeline. The Company follows the sales method to account for natural gas imbalances. Sales may result in more or less of the Company’s share of pro-rata production from certain wells. When natural gas sales volumes exceeds the Company’s entitled share and the accumulated overproduced balance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company will record a liability. Historically, sales volumes have not materially differed from the Company’s entitled share of natural gas production and the Company did not have a material imbalance position in terms of volumes or values at December 31, 2015 or 2014.

Oil and Gas Properties

Oil and Gas Properties

The Company uses the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs for unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. Capitalized costs include lease acquisition, geological and geophysical work, delay rentals, costs of drilling, completing and equipping the wells and any internal costs that are directly related to acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Proceeds from the sale or other disposition of oil and gas properties are generally treated as a reduction in the capitalized costs of oil and gas properties, unless the impact of such a reduction would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.

The Company categorizes its full cost pools as costs subject to amortization and costs not being amortized. The sum of net capitalized costs subject to amortization, including estimated future development and abandonment costs, are amortized using the unit-of-production method. Depletion and amortization for oil and gas properties was $754,892 and $348,197 for the years ended December 31, 2015 and 2014, respectively and accumulated amortization, depreciation and impairment was $54,587,826 and $52,114,846 at December 31, 2015 and 2014, respectively.

Costs Excluded

Costs Excluded

Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent costs of investments in unproved properties. The Company excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the costs subject to amortization.

Ceiling Test

Ceiling Test

Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X. The ceiling test determines a limit, on a country-by-country basis, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment (“DD&A”) and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, calculated for 2015 using the average oil and natural gas sales price received by the Company as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) with consideration of price change only to the extent provided by contractual arrangement, discounted at 10%, net of related tax effects. If capitalized costs exceed this limit, the excess is charged to expense and reflected as additional accumulated DD&A. During the year, the Company impaired oil and gas properties in the amount of $1,718,088.

Furniture and Equipment

Furniture and Equipment

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

Depreciation expense for office equipment was $1,865 and $11,700 for 2015 and 2014, respectively, and accumulated depreciation was $88,897 and $87,032 at December 31, 2015 and 2014, respectively.

Asset Retirement Obligations

Asset Retirement Obligations

For the Company, asset retirement obligations (“ARO”) represent the systematic, monthly accretion and depreciation of future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, an adjustment is made to the full cost pool, with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. Although the Company’s domestic policy with respect to ARO is to assign depleted wells to a salvager for the assumption of abandonment obligations before the wells have reached their economic limits, the Company has estimated its future ARO obligation with respect to its domestic operations. The ARO assets, which are carried on the balance sheet as part of the full cost pool, have been included in our amortization base for the purposes of calculating depreciation, depletion and amortization expense. For the purposes of calculating the ceiling test, the future cash outflows associated with settling the ARO liability have been included in the computation of the discounted present value of estimated future net revenues.

Joint Venture Expense

Joint Venture Expense

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

Income Taxes

Income Taxes

Deferred income taxes are provided on a liability method whereby deferred tax assets and liabilities are established for the difference between the financial reporting and income tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.

Stock-Based Compensation

Stock-Based Compensation

The Company measures the cost of employee services received in exchange for stock and stock options based on the grant date fair value of the awards. The Company determines the fair value of stock option grants using the Black-Scholes option pricing model. The Company determines the fair value of shares of non-vested stock based on the last quoted price of our stock on the date of the share grant. The fair value determined represents the cost for the award and is recognized over the vesting period during which an employee is required to provide service in exchange for the award. As share-based compensation expense is recognized based on awards ultimately expected to vest, the Company reduces the expense for estimated forfeitures based on historical forfeiture rates. Previously recognized compensation costs may be adjusted to reflect the actual forfeiture rate for the entire award at the end of the vesting period. Excess tax benefits, if any, are recognized as an addition to paid-in capital.

Preferred Stock

Preferred Stock

The Company has authorized 10,000,000 shares of preferred stock with a par value of $0.001. The Board of Directors shall determine the designations, rights, preferences, privileges and voting rights of the preferred stock as well as any restrictions and qualifications thereon. No shares of preferred stock have been issued.

Net Income (Loss) Per Share

Net Income (Loss) Per Share

Basic net income (loss) per share is computed by dividing the net income (loss) attributable to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted net income (loss) per share is computed by dividing the net income (loss) attributable to common shareholders by the weighted-average number of common and common equivalent shares outstanding during the period. Common share equivalents included in the diluted computation represent shares issuable upon assumed exercise of stock options and warrants using the treasury stock and “if converted” method. For periods in which net losses are incurred, weighted average shares outstanding is the same for basic and diluted loss per share calculations, as the inclusion of common share equivalents would have an anti-dilutive effect.

For the year ended December 31, 2015, outstanding options to purchase 4,432,165 shares of common stock were excluded from the calculation of diluted net loss per share because they were anti-dilutive. For the year ended December 31, 2014, outstanding options to purchase 3,392,832 shares of common stock were excluded from the calculation of diluted net loss per share because they were anti-dilutive.

Concentration of Risk

Concentration of Risk

As a non-operator oil and gas exploration and production company, and through its interest in a limited liability company (“Hupecol”) and concessions operated by Hupecol in the South American country of Colombia, the Company is dependent on the personnel, management and resources of Hupecol to operate efficiently and effectively.

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

The Company currently has interests in concessions in Colombia and expects to be active in Colombia for the foreseeable future. The political climate in Colombia is unstable and could be subject to radical change over a very short period of time. In the event of a significant negative change in political and economic stability in the vicinity of the Company’s Colombian operations, the Company may be forced to abandon or suspend its efforts. Either of such events could be harmful to the Company’s expected business prospects.

At December 31, 2015, 67.5% of the Company’s net oil and gas property investment, and 0% of its revenue for the year ended December 31, 2015, was with or derived from interests operated in Colombia.

For 2015, our oil production from the Company’s mineral interests was sold to U.S. oil marketing companies based on the highest bid. The gas production is sold to U.S. natural gas marketing companies based on the highest bid. No purchaser accounted for more than 10% of our oil and gas sales.

The Company reviews accounts receivable balances when circumstances indicate a balance may not be collectible. Based upon the Company’s review, no allowance for uncollectible accounts was deemed necessary at December 31, 2015 and 2014, respectively.

Subsequent Events

Subsequent Events

The Company evaluated subsequent events for disclosure from December 31, 2015 through the date the consolidated financial statements were issued.

Recent Accounting Developments

Recent Accounting Developments

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

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ESCROW RECEIVABLE (Tables)

12 Months Ended

Dec. 31, 2015

ESCROW RECEIVABLE [Abstract]

Escrow receivables relating to oil and gas properties

At December 31, 2015 and December 31, 2014, the Company’s balance sheet reflected the following escrow receivables relating to various oil and gas properties previously sold by the Company:

	December 31, 2015		December 31, 2014
Tambaqui Escrow	$	—	$	4,331
HDC LLC and HL LLC 15% Escrow		251,125		294,383
HDC LLC and HL LLC 5% Contingency		10,891		11,256
HC LLC 5% Contingency		—		11,458
Total	$	262,016	$	321,428

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OIL AND GAS PROPERTIES (Tables)

12 Months Ended

Dec. 31, 2015

OIL AND GAS PROPERTIES [Abstract]

Schedule of evaluated oil and gas properties subject to amortization

Evaluated Oil and Gas Properties

Evaluated oil and gas properties subject to amortization at December 31, 2015 included the following:

	United States			South America			Total
Evaluated properties being amortized	$	5,385,898		$	49,454,702		$	54,840,600
Accumulated depreciation, depletion, amortization and impairment		(5,133,124	)		(49,454,702	)		(54,587,826	)
Net capitalized costs	$	252,774		$	—		$	252,774

Evaluated oil and gas properties subject to amortization at December 31, 2014 included the following:

	United States			South America			Total
Evaluated properties being amortized	$	4,570,915		$	49,454,702		$	54,025,617
Accumulated depreciation, depletion, amortization and impairment		(2,660,144	)		(49,454,702	)		(52,114,846	)
Net capitalized costs	$	1,910,771		$	—		$	1,910,771

Schedule of unevaluated oil and gas properties not subject to amortization

Unevaluated Oil and Gas Properties

Unevaluated oil and gas properties not subject to amortization at December 31, 2015 included the following:

	United States		South America		Total
Leasehold acquisition costs	$	761,545	$	141,319	$	902,864
Geological, geophysical, screening and evaluation costs		4,143		1,972,056		1,976,199
Total	$	765,688	$	2,113,375	$	2,879,063

Unevaluated oil and gas properties not subject to amortization at December 31, 2014 included the following:

	United States		South America		Total
Leasehold acquisition costs	$	868,301	$	141,319	$	1,009,620
Geological, geophysical, screening and evaluation costs		683,976		1,892,688		2,576,664
Total	$	1,552,277	$	2,034,007	$	3,586,284

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ASSET RETIREMENT OBLIGATION (Tables)

12 Months Ended

Dec. 31, 2015

ASSET RETIREMENT OBLIGATION [Abstract]

Schedule of changes in our asset retirement liability

The following table describes changes in our asset retirement liability during each of the years ended December 31, 2015 and 2014.

	2015			2014
ARO liability at January 1	$	28,147		$	8,414
Accretion expense		1,329			628
Liabilities incurred from drilling		—			20,812
Changes in estimates		(4,214	)		(1,717	)
ARO liability at December 31	$	25,262		$	28,147

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STOCK-BASED COMPENSATION (Tables)

12 Months Ended

Dec. 31, 2015

STOCK-BASED COMPENSATION [Abstract]

Option activity

Option activity during 2015 and 2014 was as follows:

	Options			Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in Years)		Aggregate Intrinsic Value
Outstanding at December 31, 2013		2,592,832		$	4.07
Granted		800,000		$	0.42
Exercised		—		$	—
Forfeited		—		$	—
Outstanding at December 31, 2014		3,392,832		$	3.21
Granted		1,108,333		$	0.21
Exercised		—		$	—
Forfeited		(69,000	)	$	2.55
Outstanding at December 31, 2015		4,432,165		$	2.47		6.77	$	—

Share-based compensation expense

The following table reflects share-based compensation recorded by the Company for 2015 and 2014:

	2015			2014
Share-based compensation expense included in general and administrative expense	$	91,625		$	451,010
Earnings per share effect of share-based compensation expense	$	(0.00	)	$	(0.01	)

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TAXES (Tables)

12 Months Ended

Dec. 31, 2015

TAXES [Abstract]

Reconciliation of the statutory federal income tax

The following table sets forth a reconciliation of the statutory federal income tax for the years ending December 31, 2015 and 2014.

	2015			2014
Loss before income taxes	$	(3,811,341	)	$	(4,350,996	)
Income tax benefit computed at statutory rates	$	(1,333,969	)	$	(1,523,613	)
Permanent differences, nondeductible expenses		501			141,446
Increase (decrease) in valuation allowance		635,888			(696,514	)
Return to accrual items		(764	)		1,178,681
Other adjustment		717,209			—
NOL adjustment		—			902,183
Tax provision	$	18,865		$	2,183
Total provision
Foreign	$	18,865		$	2,183
Total provision	$	18,865		$	2,183

Significant components of the deferred tax asset and liability

The tax effects of the temporary differences between financial statement income and taxable income are recognized as a deferred tax asset and liabilities. Significant components of the deferred tax asset and liability as of December 31, 2015 and 2014 are set out below.

	2015			2014
Non-Current Deferred tax assets:
Net operating loss carry forward	$	16,255,870		$	15,764,184
Foreign tax credit carry forward		505,745			486,880
Deferred state tax		23,277			23,277
Stock compensation		3,091,356			3,525,473
Book in excess of tax depreciation, depletion and capitalization methods on oil and gas properties		(713,832	)		(1,524,310	)
Other		(327,600	)		(76,576	)
Total Non-Current Deferred tax assets		18,834,816			18,198,928
Valuation Allowance		(18,834,816	)		(18,198,928	)
Net deferred tax asset	$	—		$	—

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COMMITMENTS AND CONTINGENCIES (Tables)

12 Months Ended

Dec. 31, 2015

COMMITMENTS AND CONTINGENCIES [Abstract]

Future payments under lease agreement

The Company leases office facilities under an operating lease agreement that expires May 31, 2017. The lease agreement requires future payments as follows:

Year	Amount
2016	$	96,162
2017		40,469
Total	$	136,631

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GEOGRAPHICAL INFORMATION (Tables)

12 Months Ended

Dec. 31, 2015

GEOGRAPHICAL INFORMATION [Abstract]

Revenues and long-lived assets attributable to each geographical area

The Company currently has operations in two geographical areas, the United States and Colombia. Revenues for the years ended December 31, 2015 and 2014 and long-lived assets as of December 31, 2015 and 2014 attributable to each geographical area are presented below:

	2015				2014
	Revenues		Long Lived Assets, Net		Revenues		Long Lived Assets, Net
North America	$	429,435	$	1,019,569	$	363,455	$	3,466,020
South America		—		2,113,374		—		2,034,007
Total	$	429,435	$	3,132,943	$	363,455	$	5,500,027

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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Tables)

12 Months Ended

Dec. 31, 2015

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) [Abstract]

Oil and gas revenues and lease operating expenses

This footnote provides unaudited information required by FASB ASC Topic 932, Extractive Activities—Oil and Gas.

Geographical Data

The following table shows the Company’s oil and gas revenues and lease operating expenses, which excludes the joint venture expenses incurred in South America, by geographic area:

	2015		2014
Revenues
North America	$	429,435	$	363,455
South America		—		—
	$	429,435	$	363,455
Production Cost
North America	$	148,067	$	113,233
South America		—		—
	$	148,067	$	113,233

Capitalized costs and accumulated depletion relating to oil and gas producing activities

Capitalized costs and accumulated depletion relating to the Company’s oil and gas producing activities as of December 31, 2015, all of which are onshore properties located in the United States and Colombia, South America are summarized below:

	United States			South America			Total
Unproved properties not being amortized	$	765,688		$	2,113,375		$	2,879,063
Proved properties being amortized		5,385,898			49,454,702			54,840,600
Accumulated depreciation, depletion, amortization and impairment		(5,133,124	)		(49,454,702	)		(54,587,826	)
Net capitalized costs	$	1,018,462		$	2,113,375		$	3,131,837

Costs incurred in oil and gas property acquisition, exploration and development activities

Costs incurred in oil and gas property acquisition, exploration and development activities as of December 31, 2015 and 2014 are summarized below:

	2015
	United States		South America
Property acquisition costs:
Proved	$	16,669	$	—
Unproved		—		—
Exploration costs		72,500		79,511
Development costs		—		—
Total costs incurred	$	89,169	$	79,511

	2014
	United States		South America
Property acquisition costs:
Proved	$	54,716	$	—
Unproved		184,612		9,984
Exploration costs		3,005,469		234,487
Development costs		—		—
Total costs incurred	$	3,244,797	$	244,471

Total estimated proved developed and undeveloped reserves by product type

Total estimated proved developed and undeveloped reserves by product type and the changes therein are set forth below for the years indicated.

	United States						South America				Total
	Gas (mcf)			Oil (bbls)			Gas (mcf)		Oil (bbls)		Gas (mcf)			Oil (bbls)
Total proved reserves
Balance December 31, 2013		36,810			11,150			—		—		36,810			11,150
Extensions and discoveries		24,944			32,090			—		—		24,944			32,090
Revisions of prior estimates		23,673			(5,958	)		—		—		23,673			(5,958	)
Production		(12,717	)		(3,152	)		—		—		(12,717	)		(3,152	)
Balance December 31, 2014		72,710			34,130			—		—		72,710			34,130
Revisions to prior estimates		17,136			(19,212	)		—		—		17,136			(19,212	)
Production		(32,146	)		(6,068	)		—		—		(32,146	)		(6,068	)
Balance December 31, 2015		57,700			8,850			—		—		57,700			8,850
Proved developed reserves
at December 31, 2014		72,710			34,130			—		—		72,710			34,130
at December 31, 2015		57,700			8,850			—		—		57,700			8,850
Proved undeveloped reserves
at December 31, 2014		—			—			—		—		—			—
at December 31, 2015		—			—			—		—		—			—

Standardized measure of discounted future net cash flows

Standardized measure of discounted future net cash flows at December 31, 2015:

	United States			South America		Total
Future cash flows from sales of oil and gas	$	611,520		$	—	$	611,520
Future production cost		(308,020	)		—		(308,020	)
Future net cash flows		303,500			—		303,500
10% annual discount for timing of cash flow		(49,120	)		—		(49,120	)
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	$	254,380		$	—	$	254,380
Changes in standardized measure:
Change due to current year operations
Sales, net of production costs		(281,368	)		—		(285,582	)
Change due to revisions in standardized variables:
Accretion of discount		183,828			—		183,828
Net change in sales and transfer price, net of production costs		(405,129	)		—		(405,129	)
Revision and others		(176,014	)		—		(176,014	)
Changes in production rates and other		(617,498	)		—		(613,285	)
Net		(1,296,181	)		—		(1,296,181	)
Beginning of year		1,550,561			—		1,550,561
End of year	$	254,380		$	—	$	254,380

Standardized measure of discounted future net cash flows at December 31, 2014:

	United States			South America		Total
Future cash flows from sales of oil and gas	$	3,579,990		$	—	$	3,579,990
Future production cost		(1,091,790	)		—		(1,091,790	)
Future income tax		(287,709	)		—		(287,709	)
Future net cash flows		2,200,491			—		2,200,491
10% annual discount for timing of cash flow		(649,930	)		—		(649,930	)
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	$	1,550,561		$	—	$	1,550,561
Changes in standardized measure:
Change due to current year operations
Sales, net of production costs		(250,222	)		—		(250,222	)
Change due to revisions in standardized variables:
Income taxes		(287,709	)		—		(287,709	)
Accretion of discount		112,021			—		112,021
Net change in sales and transfer price, net of production costs		(193,777	)		—		(193,777	)
Discoveries		999,242			—		999,242
Changes in production rates and other		451,971			—		451,971
Net		831,526			—		831,526
Beginning of year		719,035			—		719,035
End of year	$	1,550,561		$	—	$	1,550,561

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SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Tables)

12 Months Ended

Dec. 31, 2015

SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) [Abstract]

Summarized quarterly financial information

NOTE 12—SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

	Three Months Ended
	March 31,			June 30,			Sept. 30,			Dec. 31,
2015
Operating revenue	$	101,971		$	114,122		$	124,448		$	88,894
Loss from operations		(1,191,769	)		(339,488	)		(468,332	)		(1,735,182	)
Net loss		(1,187,064	)		(351,808	)		(463,566	)		(1,827,768	)
Loss per common share – basic	$	(0.02	)	$	(0.01	)	$	(0.01	)	$	(0.04	)
Loss per common share – diluted	$	(0.02	)	$	(0.01	)	$	(0.01	)	$	(0.04	)
2014
Operating revenue	$	106,023		$	67,450		$	56,805		$	133,177
Loss from operations		(536,105	)		(684,728	)		(512,919	)		(2,224,590	)
Net loss		(535,368	)		(683,644	)		(511,653	)		(2,222,514	)
Loss per common share – basic	$	(0.01	)	$	(0.01	)	$	(0.01	)	$	(0.04	)
Loss per common share – diluted	$	(0.01	)	$	(0.01	)	$	(0.01	)	$	(0.04	)

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NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Going Concern [Abstract]
Net cash used in operations	$ (1,837,977)	$ (1,747,625)
Concentration of Credit Risk [Abstract]
Cash deposits in excess of the FDIC's current insured limit	1,800,000
Current insured limit on interest bearing accounts	$ 250,000
Ceiling Test [Abstract]
Discount rate, net of related tax effects	10.00%
Impairment of oil and gas properties	$ 1,718,088	1,492,148
Property, Plant and Equipment [Line Items]
Depletion and amortization	756,757	359,897
Accumulated amortization, depreciation and impairment	$ 54,676,723	$ 52,201,878
Preferred Stock [Abstract]
Preferred stock, authorized (in shares)	10,000,000	10,000,000
Preferred stock, par value (in dollars per share)	$ 0.001	$ 0.001
Concentration Risk [Line Items]
Percentage of sales to a single buyer	10.00%
Allowance for uncollectible accounts	$ 0	$ 0
Oil and Gas Properties [Member]
Property, Plant and Equipment [Line Items]
Depletion and amortization	754,892	348,197
Accumulated amortization, depreciation and impairment	54,587,826	52,114,846
Furniture and Equipment [Member]
Property, Plant and Equipment [Line Items]
Depletion and amortization	1,865	11,700
Accumulated amortization, depreciation and impairment	$ 88,897	$ 87,032
Furniture and Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Useful life of the assets	3 years
Furniture and Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Useful life of the assets	5 years
Oil and Gas Property Investment [Member] | Hupecol Operating LLC [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	67.50%
Revenue [Member] | Hupecol Operating LLC [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	0.00%
Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)	4,432,165	3,392,832

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ESCROW RECEIVABLE (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Escrow receivables relating to oil and gas properties [Abstract]
Escrow receivables - Total	$ 262,016	$ 321,428
Tambaqui Escrow [Member]
Escrow receivables relating to oil and gas properties [Abstract]
Escrow receivables - Total	0	4,331
HDC LLC and HL LLC 15% Escrow [Member]
Escrow receivables relating to oil and gas properties [Abstract]
Escrow receivables - Total	$ 251,125	$ 294,383
Escrow receivables, percentage	15.00%	15.00%
HDC LLC and HL LLC 5% Contingency [Member]
Escrow receivables relating to oil and gas properties [Abstract]
Escrow receivables - Total	$ 10,891	$ 11,256
Escrow receivables, percentage	5.00%	5.00%
HC LLC 5% Contingency [Member]
Escrow receivables relating to oil and gas properties [Abstract]
Escrow receivables - Total	$ 0	$ 11,458
Escrow receivables, percentage	5.00%	5.00%
Various Escrow Accounts [Member]
Escrow receivables relating to oil and gas properties [Abstract]
Proceeds from settlement of escrow account	$ 59,412

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OIL AND GAS PROPERTIES (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Evaluated oil and gas properties subject to amortization [Abstract]
Evaluated properties being amortized	$ 54,840,600	$ 54,025,617
Accumulated depreciation, depletion, amortization and impairment	(54,587,826)	(52,114,846)
Net capitalized costs	252,774	1,910,771
United States [Member]
Evaluated oil and gas properties subject to amortization [Abstract]
Evaluated properties being amortized	5,385,898	4,570,915
Accumulated depreciation, depletion, amortization and impairment	(5,133,124)	(2,660,144)
Net capitalized costs	252,774	1,910,771
South America [Member]
Evaluated oil and gas properties subject to amortization [Abstract]
Evaluated properties being amortized	49,454,702	49,454,702
Accumulated depreciation, depletion, amortization and impairment	(49,454,702)	(49,454,702)
Net capitalized costs	$ 0	$ 0

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OIL AND GAS PROPERTIES, Capital costs of Unproved Properties Excluded from Amortization (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Unevaluated oil and gas properties not subject to amortization [Abstract]
Leasehold acquisition costs	$ 902,864	$ 1,009,620
Geological, geophysical, screening and evaluation costs	1,976,199	2,576,664
Total	2,879,063	3,586,284
United States [Member]
Unevaluated oil and gas properties not subject to amortization [Abstract]
Leasehold acquisition costs	761,545	868,301
Geological, geophysical, screening and evaluation costs	4,143	683,976
Total	765,688	1,552,277
South America [Member]
Unevaluated oil and gas properties not subject to amortization [Abstract]
Leasehold acquisition costs	141,319	141,319
Geological, geophysical, screening and evaluation costs	1,972,056	1,892,688
Total	$ 2,113,375	$ 2,034,007

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ASSET RETIREMENT OBLIGATION (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Changes in our asset retirement liability [Roll Forward]
ARO liability at January 1	$ 28,147	$ 8,414
Accretion expense	1,329	628
Liabilities incurred from drilling	0	20,812
Liabilities settled-assets sold	0	0
Changes in estimates	(4,214)	(1,717)
ARO liability at December 31	$ 25,262	$ 28,147

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STOCK-BASED COMPENSATION (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options granted (in shares)	1,108,333	800,000
Exercise price of options granted (in dollars per share)	$ 0.21	$ 0.42
Stock compensation amortized expense	$ 91,625	$ 451,010
Acquisition of treasury stock (in shares)	190,000
Acquisition of treasury stock amount	$ (38,152)
Options [Roll Forward]
Outstanding at beginning of the period (in shares)	3,392,832	2,592,832
Granted (in shares)	1,108,333	800,000
Exercised (in shares)	0	0
Forfeited (in shares)	(69,000)	0
Outstanding at end of the period (in shares)	4,432,165	3,392,832
Weighted-Average Exercise Price [Roll Forward]
Outstanding at beginning of the period (in dollars per share)	$ 3.21	$ 4.07
Granted (in dollars per share)	0.21	0.42
Exercised (in dollars per share)	0	0
Forfeited (in dollars per share)	2.55	0
Outstanding at end of the period (in dollars per share)	$ 2.47	$ 3.21
Weighted Average Remaining Contractual Term [Abstract]
Weighted average remaining contractual term of the outstanding options	6 years 9 months 7 days
Aggregate Intrinsic Value [Abstract]
Outstanding at end of the period	$ 0
Weighted average remaining contractual term of the outstanding options	6 years 9 months 7 days
New non-employee director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options granted (in shares)	8,333
Stock option vesting percentage	20.00%
Percentage of stock options expected to vest	80.00%
Option vesting period	10 years
Exercise price of options granted (in dollars per share)	$ 0.2158
Total value of options granted	$ 805
Risk free interest rate	1.36%
Stock option expected life	4 years 11 months 23 days
Expected stock volatility	106.00%
Options [Roll Forward]
Granted (in shares)	8,333
Weighted-Average Exercise Price [Roll Forward]
Granted (in dollars per share)	$ 0.2158
Aggregate Intrinsic Value [Abstract]
Vesting period of restricted stock award granted to officers	10 years
Employee [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options granted (in shares)	900,000	600,000
Stock option vesting percentage	33.00%	33.00%
Option vesting period	10 years	10 years
Exercise price of options granted (in dollars per share)	$ 0.2158	$ 0.415
Total value of options granted	$ 82,000	$ 126,355
Risk free interest rate	1.36%	1.57%
Stock option expected life	4 years 11 months 23 days	4 years 7 months 24 days
Expected stock volatility	106.00%	103.60%
Expected dividend yield		0.00%
Minimum aggregate gross proceeds from the sale of equity securities under vesting condition	$ 10,000,000
Minimum aggregate purchase price of oil and gas properties under vesting condition	$ 10,000,000
Options [Roll Forward]
Granted (in shares)	900,000	600,000
Weighted-Average Exercise Price [Roll Forward]
Granted (in dollars per share)	$ 0.2158	$ 0.415
Aggregate Intrinsic Value [Abstract]
Vesting period of restricted stock award granted to officers	10 years	10 years
Non-employee directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options granted (in shares)	200,000	200,000
Stock option vesting percentage	20.00%	20.00%
Percentage of stock options expected to vest	80.00%	80.00%
Option vesting period	10 years	10 years
Exercise price of options granted (in dollars per share)	$ 0.2028	$ 0.415
Total value of options granted	$ 17,370	$ 46,191
Risk free interest rate	1.73%	1.57%
Stock option expected life	5 years 4 days	4 years 7 months 24 days
Expected stock volatility	105.00%	103.60%
Expected dividend yield		0.00%
Options [Roll Forward]
Granted (in shares)	200,000	200,000
Weighted-Average Exercise Price [Roll Forward]
Granted (in dollars per share)	$ 0.2028	$ 0.415
Aggregate Intrinsic Value [Abstract]
Vesting period of restricted stock award granted to officers	10 years	10 years
2005 Stock Option Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of options authorized (in shares)	500,000
Number of shares of common stock authorized (in shares)	500,000
2008 Equity Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares of common stock authorized (in shares)	2,200,000
Amendments to 2008 Equity Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares of common stock authorized (in shares)	6,000,000
Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation amortized expense	$ 91,625	$ 414,189
Weighted Average Remaining Contractual Term [Abstract]
Weighted average remaining contractual term of the outstanding options	6 years 9 months 7 days
Aggregate Intrinsic Value [Abstract]
Unvested options outstanding (in shares)	1,466,666
Weighted average period for recognition of compensation expense	1 year 9 months 29 days
Weighted average remaining contractual term of the outstanding options	6 years 9 months 7 days
Weighted average remaining contractual term of the exercisable options	5 years 7 months 13 days
Unrecognized stock-based compensation expense related to non-vested stock options	$ 127,591
Shares available for issuance (in shares)	1,567,835
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock compensation amortized expense	$ 0	$ 36,821
Aggregate Intrinsic Value [Abstract]
Fair market value of the shares on date of grant			$ 743,400
Unrecognized compensation cost related to unvested restricted stock	$ 0
Restricted Stock [Member] | Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vesting period			3 years
Aggregate Intrinsic Value [Abstract]
Restricted stock granted to officers (in shares)			45,000
Vesting period of restricted stock award granted to officers			3 years

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STOCK-BASED COMPENSATION, Allocation of Recognized Period Costs (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Share-based compensation expense [Abstract]
Share-based compensation expense included in general and administrative expense	$ 91,625	$ 451,010
General and administrative expense [Member]
Share-based compensation expense [Abstract]
Share-based compensation expense included in general and administrative expense	$ 91,625	$ 451,010
Earnings per share effect of share based compensation expense (in dollars per share)	$ 0	$ (0.01)

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TAXES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of the statutory federal income tax [Abstract]
Loss before income taxes	$ (3,811,341)	$ (4,350,996)
Income tax benefit computed at statutory rates	(1,333,969)	(1,523,613)
Permanent differences, nondeductible expenses	501	141,446
Increase (decrease) in valuation allowance	635,888	(696,514)
Return to accrual items	(764)	1,178,681
Other adjustment	717,209	0
NOL adjustment	0	902,183
Tax provision	18,865	2,183
Total Provision [Abstract]
Foreign	18,865	2,183
Tax provision	18,865	2,183
Federal tax loss carry forward	47,415,085
Foreign tax credit carry forward	505,745
Non-Current Deferred tax assets [Abstract]
Net operating loss carry forward	16,255,870	15,764,184
Foreign tax credit carry forward	505,745	486,880
Deferred state tax	23,277	23,277
Stock compensation	3,091,356	3,525,473
Book in excess of tax depreciation, depletion, and capitalization methods on oil and gas properties	(713,832)	(1,524,310)
Other	(327,600)	(76,576)
Total Non-Current Deferred tax assets	18,834,816	18,198,928
Valuation Allowance	(18,834,816)	(18,198,928)
Net deferred tax asset	$ 0	$ 0
Foreign Income Taxes [Member]
Income Tax Contingency [Line Items]
Colombia's current income tax rate	25.00%

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RELATED PARTIES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
John F. Terwilliger [Member]
Related Party Transaction [Line Items]
Overriding royalty interests owned	1.50%
Royalty payments	$ 919	$ 20,682
Orrie L. Tawes [Member]
Related Party Transaction [Line Items]
Overriding royalty interests owned	1.50%
Royalty payments	$ 919	$ 20,682

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COMMITMENTS AND CONTINGENCIES (Details)		1 Months Ended	12 Months Ended
	Apr. 16, 2015 USD ($)	Aug. 31, 2013	Dec. 31, 2015 USD ($) Lawsuit	Dec. 31, 2014 USD ($)	May. 15, 2015 USD ($)
Lease Commitment [Abstract]
Operating lease agreement expiration date			May 31, 2017
Future payments under lease agreement [Abstract]
2016			$ 96,162
2017			40,469
Total			136,631
Total rental expense			$ 95,711	$ 88,709
Loss Contingencies [Line Items]
Additional class action lawsuits | Lawsuit			2
Litigation settlement payable recorded as contingent liability			$ 0	7,000,000
Contingent liability			0	400,000
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Description of production incentive compensation plan		The maximum percentage of the Company’s share of revenues from a well that may be designated to fund a Pool is 2% (the “Pool Cap”); provided, however, that with respect to wells with a net revenue interest to the 8/8 of less than 73%, the Pool Cap with respect to such wells shall be reduced on a 1-for-1 basis such that no portion of the Company’s revenues from a well may be designated to fund a Pool if the NRI is 71% or less.
Maximum percentage of revenue to fund a pool from a well		2.00%
Maximum percentage of revenue from a well considered for pool cap one		73.00%
Maximum percentage of revenue from a well considered for pool cap two		71.00%
Period consider for payout of revenues to participants		60 days
Production Based Compensation Plan [Member]
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Grants issued under plan			0
Reduction of revenue associated with plan			0
Chief Executive Officer [Member]
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Maximum percentage of pool cap related to well assigned		50.00%
Silverman Shareholder Class Action Suit [Member]
Loss Contingencies [Line Items]
Increase in insurance receivable			7,000,000
Litigation settlement payable recorded as contingent liability					$ 7,000,000
SEC Administrative Proceeding [Member]
Loss Contingencies [Line Items]
Increase in insurance receivable			$ 0	1,612,681
Litigation settlement payable	$ (400,000)
Amount of penalty paid by Chief Executive Officer	$ 150,000
Contingent liability				$ 400,000

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SUBSEQUENT EVENTS (Details) - Subsequent Event [Member] - Tamboran Resources Limited [Member]	1 Months Ended
	Feb. 29, 2016 USD ($)
Subsequent Event [Line Items]
Purchase of an ordinary shares	$ 1,000,000
Percentage of equity ownership interest	12.50%
Period of anti-dilution rights	9 months
Minimum [Member]
Subsequent Event [Line Items]
Amount required for funding from investors	$ 705,000

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GEOGRAPHICAL INFORMATION (Details)	3 Months Ended								12 Months Ended
	Dec. 31, 2015 USD ($) Area	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Sep. 30, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2015 USD ($) Area	Dec. 31, 2014 USD ($)
Revenues from External Customers and Long-Lived Assets [Line Items]
Number of geographical areas in which entity operates | Area	2								2
Revenues and long-lived assets attributable to each geographical area [Abstract]
Revenue	$ 88,894	$ 124,448	$ 114,122	$ 101,971	$ 133,177	$ 56,805	$ 67,450	$ 106,023	$ 429,435	$ 363,455
Long Lived Assets, Net	3,132,943				5,500,027				3,132,943	5,500,027
North America [Member]
Revenues and long-lived assets attributable to each geographical area [Abstract]
Revenue									429,435	363,455
South America [Member]
Revenues and long-lived assets attributable to each geographical area [Abstract]
Revenue									0	0
Reportable Geographical Components [Member] | North America [Member]
Revenues and long-lived assets attributable to each geographical area [Abstract]
Revenue									429,435	363,455
Long Lived Assets, Net	1,019,569				3,466,020				1,019,569	3,466,020
Reportable Geographical Components [Member] | South America [Member]
Revenues and long-lived assets attributable to each geographical area [Abstract]
Revenue									0	0
Long Lived Assets, Net	$ 2,113,374				$ 2,034,007				$ 2,113,374	$ 2,034,007

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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenue	$ 88,894	$ 124,448	$ 114,122	$ 101,971	$ 133,177	$ 56,805	$ 67,450	$ 106,023	$ 429,435	$ 363,455
Production Cost									148,067	113,233
North America [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenue									429,435	363,455
Production Cost									148,067	113,233
South America [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenue									0	0
Production Cost									$ 0	$ 0

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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED), Capitalized costs and accumulated depleiton relating to oil and gas producing activities (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved properties not being amortized	$ 2,879,063	$ 3,586,284
Proved properties being amortized	54,840,600	54,025,617
Accumulated depreciation, depletion, amortization and impairment	(54,587,826)	(52,114,846)
Net capitalized costs	3,131,837
United States [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved properties not being amortized	765,688	1,552,277
Proved properties being amortized	5,385,898	4,570,915
Accumulated depreciation, depletion, amortization and impairment	(5,133,124)	(2,660,144)
Net capitalized costs	1,018,462
South America [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved properties not being amortized	2,113,375	2,034,007
Proved properties being amortized	49,454,702	49,454,702
Accumulated depreciation, depletion, amortization and impairment	(49,454,702)	$ (49,454,702)
Net capitalized costs	$ 2,113,375

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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED), Amortization expense per unit of production, estimating reserves and future cash flows (Details)	12 Months Ended
	Dec. 31, 2015 Boe $ / shares	Dec. 31, 2014 Boe
Amortization Expense Per Equivalent Unit of Production or Per Dollar of Gross Revenue [Line Items]
Period of average prices used in calculating proved oil and gas reserves	12 months
Minimum experience of Vice President of independent professional engineering firm	30 years
Period of average prices used in calculating future cash inflows related to standardized measure of discounted future net cash flows	12 months
Total proved undeveloped reserve | Boe	0	0
Discount rate of estimated future cash flows	10.00%
United States [Member]
Amortization Expense Per Equivalent Unit of Production or Per Dollar of Gross Revenue [Line Items]
Amortization rate per unit (in dollars per share)	66.08
South America [Member]
Amortization Expense Per Equivalent Unit of Production or Per Dollar of Gross Revenue [Line Items]
Amortization rate per unit (in dollars per share)	0

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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED), Costs related to property acquisition and E&D activities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
United States [Member]
Property acquisition costs [Abstract]
Proved	$ 16,669	$ 54,716
Unproved	0	184,612
Exploration costs	72,500	3,005,469
Development costs	0	0
Total costs incurred	89,169	3,244,797
South America [Member]
Property acquisition costs [Abstract]
Proved	0	0
Unproved	0	9,984
Exploration costs	79,511	234,487
Development costs	0	0
Total costs incurred	$ 79,511	$ 244,471

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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED), Proved developed and undeveloped reserves by product type (Details) bbl in Millions	12 Months Ended
	Dec. 31, 2015 MMcf bbl	Dec. 31, 2014 MMcf bbl
Gas [Member]
Total proved reserves [Abstract]
Balance at beginning of the period | MMcf	72,710	36,810
Extensions and discoveries | MMcf		24,944
Revisions of prior estimates | MMcf	17,136	23,673
Production | MMcf	(32,146)	(12,717)
Balance at end of the period | MMcf	57,700	72,710
Proved developed reserves | MMcf	57,700	72,710
Proved undeveloped reserves | MMcf	0	0
Oil [Member]
Total proved reserves [Abstract]
Balance at beginning of the period | bbl	34,130	11,150
Extensions and discoveries | bbl		32,090
Revisions of prior estimates | bbl	(19,212)	(5,958)
Production | bbl	(6,068)	(3,152)
Balance at end of the period | bbl	8,850	34,130
Proved developed reserves | bbl	8,850	34,130
Proved undeveloped reserves | bbl	0	0
United States [Member] | Gas [Member]
Total proved reserves [Abstract]
Balance at beginning of the period | MMcf	72,710	36,810
Extensions and discoveries | MMcf		24,944
Revisions of prior estimates | MMcf	17,136	23,673
Production | MMcf	(32,146)	(12,717)
Balance at end of the period | MMcf	57,700	72,710
Proved developed reserves | MMcf	57,700	72,710
Proved undeveloped reserves | MMcf	0	0
United States [Member] | Oil [Member]
Total proved reserves [Abstract]
Balance at beginning of the period | bbl	34,130	11,150
Extensions and discoveries | bbl		32,090
Revisions of prior estimates | bbl	(19,212)	(5,958)
Production | bbl	(6,068)	(3,152)
Balance at end of the period | bbl	8,850	34,130
Proved developed reserves | bbl	8,850	34,130
Proved undeveloped reserves | bbl	0	0
South America [Member] | Gas [Member]
Total proved reserves [Abstract]
Balance at beginning of the period | MMcf	0	0
Extensions and discoveries | MMcf		0
Purchase of minerals in place | MMcf	0	0
Production | MMcf	0	0
Balance at end of the period | MMcf	0	0
Proved developed reserves | MMcf	0	0
Proved undeveloped reserves | MMcf	0	0
South America [Member] | Oil [Member]
Total proved reserves [Abstract]
Balance at beginning of the period | bbl	0	0
Extensions and discoveries | bbl		0
Revisions of prior estimates | bbl	0	0
Production | bbl	0	0
Balance at end of the period | bbl	0	0
Proved developed reserves | bbl	0	0
Proved undeveloped reserves | bbl	0	0

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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED), Discounted future net cash flows relating to proved oil and gas reserves (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Standardized measure of discounted future net cash flows [Abstract]
Future cash flows from sales of oil and gas			$ 611,520	$ 3,579,990
Future production cost			(308,020)	(1,091,790)
Future income tax				(287,709)
Future net cash flows			303,500	2,200,491
10% annual discount for timing of cash flow			(49,120)	(649,930)
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	$ 254,380	$ 1,550,561	254,380	1,550,561
Changes in standardized measure [Roll Forward]
Change due to current year operations Sales, net of production costs	(285,582)	(250,222)
Change due to revisions in standardized variables [Abstract]
Income taxes		(287,709)
Accretion of discount	183,828	112,021
Net change in sales and transfer price, net of production costs	(405,129)	(193,777)
Revision and others	(176,014)
Discoveries		999,242
Changes in production rates and other	(613,285)	451,971
Net	(1,296,181)	831,526
Beginning of year	1,550,561	719,035
End of year	254,380	1,550,561
United States [Member]
Standardized measure of discounted future net cash flows [Abstract]
Future cash flows from sales of oil and gas			611,520	3,579,990
Future production cost			(308,020)	(1,091,790)
Future income tax				(287,709)
Future net cash flows			303,500	2,200,491
10% annual discount for timing of cash flow			(49,120)	(649,930)
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	1,550,561	1,550,561	254,380	1,550,561
Changes in standardized measure [Roll Forward]
Change due to current year operations Sales, net of production costs	(281,368)	(250,222)
Change due to revisions in standardized variables [Abstract]
Income taxes		(287,709)
Accretion of discount	183,828	112,021
Net change in sales and transfer price, net of production costs	(405,129)	(193,777)
Revision and others	(176,014)
Discoveries		999,242
Changes in production rates and other	(617,498)	451,971
Net	(1,296,181)	831,526
Beginning of year	1,550,561	719,035
End of year	254,380	1,550,561
South America [Member]
Standardized measure of discounted future net cash flows [Abstract]
Future cash flows from sales of oil and gas			0	0
Future production cost			0	0
Future income tax				0
Future net cash flows			0	0
10% annual discount for timing of cash flow			0	0
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	0	0	$ 0	$ 0
Changes in standardized measure [Roll Forward]
Change due to current year operations Sales, net of production costs	0	0
Change due to revisions in standardized variables [Abstract]
Income taxes		0
Accretion of discount	0	0
Net change in sales and transfer price, net of production costs	0	0
Revision and others	0
Discoveries		0
Changes in production rates and other	0	0
Net	0	0
Beginning of year	0	0
End of year	$ 0	$ 0

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SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014
Summarized quarterly financial information [Abstract]
Operating revenue	$ 88,894	$ 124,448	$ 114,122	$ 101,971	$ 133,177	$ 56,805	$ 67,450	$ 106,023	$ 429,435	$ 363,455
Loss from operations	(1,735,182)	(468,332)	(339,488)	(1,191,769)	(2,224,590)	(512,919)	(684,728)	(536,105)	3,734,771	3,958,342
Net loss	$ (1,827,768)	$ (463,566)	$ (351,808)	$ (1,187,064)	$ (2,222,514)	$ (511,653)	$ (683,644)	$ (535,368)	$ (3,830,206)	$ (4,353,179)
loss per common share - basic (in dollars per share)	$ (0.04)	$ (0.01)	$ (0.01)	$ (0.02)	$ (0.04)	$ (0.01)	$ (0.01)	$ (0.01)
loss per common share - diluted (in dollars per share)	$ (0.04)	$ (0.01)	$ (0.01)	$ (0.02)	$ (0.04)	$ (0.01)	$ (0.01)	$ (0.01)