UNITED
STATES
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, 2023
For
the transition period from to
Commission
File No. 1-32955
HOUSTON
AMERICAN ENERGY CORP.
(Exact
name of registrant specified in its charter)
801
Travis Street, Suite 1425, Houston, Texas77002
(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 Trading Symbol Name of each exchange on which registered
Common Stock, $0.001 par value HUSA NYSE American
Securities
registered pursuant to Section 12(g) of the Act:
None
(Title
of Class)
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒
Indicate
by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes ☐ No
☒
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 ☐
Indicate
by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). Yes ☒ No ☐
Indicate
by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting
company or an emerging growth company. See definition of “accelerated filer,” “large accelerated filer,” “smaller
reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer ☒
Smaller reporting company ☒ Emerging growth company ☐
If
an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying
with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate
by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness
of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered
public accounting firm that prepared or issued its audit report. ☐
If
securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant
included in the filing reflect the correction of an error to previously issued financial statements ☐
Indicate
by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation
received by any of the registrant’s executive officers during the relevant recovery period pursuant to o § 240.10D-1(b). ☐
Indicate
by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The
aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant on June 30, 2023, based on
the closing sales price of the registrant’s common stock on that date, was approximately $21.4 million. Shares of common stock
held by each current executive officer and director and by each person known by the registrant to own 10% 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 April 1, 2024 was 10,906,353.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions
of the Company’s Proxy Statement for its 2024 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 24
Item 1C. Cybersecurity 25
Item 2. Properties 25
Item 3. Legal Proceedings 25
Item 4. Mine Safety Disclosures 25
PART II
Item 6. Reserved 26
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 32
Item 8. Financial Statements and Supplementary Data 32
Item 9A. Controls and Procedures 32
Item 9B. Other Information 33
Item 9C Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 33
PART III
Item 10. Directors, Executive Officers, and Corporate Governance 33
Item 11. Executive Compensation 33
Item 14. Principal Accountant Fees and Services 33
PART IV
Item 15. Exhibit and Financial Statement Schedules 34
SIGNATURES 35
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. Our principal properties, and operations, are in the U.S. Permian Basin and the South American
country of Colombia. Additionally, we have properties in the Louisiana U.S. Gulf Coast region.
We
focus on early identification of, and opportunistic entrance into, existing and emerging resource plays. We do not operate properties
but typically seek to partner with, or invest along-side, 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,
identifying stranded blocks and partnering with, investing along-side 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 the Texas Permian Basin, the South American country of Colombia and the onshore Louisiana Gulf Coast region.
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, owned
mineral interests, leasehold positions, lease options, working interests in leases, partnership or limited liability company interests,
corporate equity interests or other mineral rights. Our percentage interest in each property represents the portion of the interest in
the property we share with other partners in the property. Because each property consists of a bundle of assets that may or may not include
a working interest in the project, our stated interest in a property simply represents our proportional ownership in the bundle of assets
that constitute the property. Therefore, our interest in a property should not be confused with the working interest that we will own
when a given well is drilled. Each of our exploration and development projects represents a negotiated transaction between the project
partners relating to one or more properties. Our working interest may be higher or lower than our stated interest.
The following table sets forth information
relating to our principal properties as of December 31, 2023:
Average Gross Net proved 2023 Net Production
In
2023, our net acreage in the U.S. decreased as a result of lease expirations in Yoakum County, Texas (46 net acres). In Colombia, our
net acreage position decreased (down 35,179 net acres) as a result of the relinquishment of our rights in our legacy Los Picachos and
Macaya blocks.
-
United States Properties:
In
the United States, our principal properties and operations are located in the on-shore Permian Basin and Gulf Coast region of Louisiana.
Texas
Properties – Permian Basin
Reeves
County. We hold a 18.1% average working interest in 320 gross acres in Reeves County, Texas, consisting of (1) the 160 gross acre
Johnson Lease, in which we hold a 25% working interest, subject to a proportionate 5% back-in after payout, and (2) the 160 gross acre
O’Brien Lease, in which we hold an average 11.2% working interest. Our Reeves County acreage lies within the Delaware sub-basin
of the Permian Basin, with resource potential in the Wolfcamp, Bone Spring and Avalon formations. During 2017, we drilled and completed
our initial wells on both lease blocks, the Johnson State #1H well and the O’Brien #3H well, both horizontally drilled and hydraulically
fractured wells in the Wolfcamp A formation. The Johnson #1H well and O’Brien #3H well were both placed on gas lift during 2021
and were producing at December 31, 2023. For the year ended December 31, 2023, our production in Reeves County totaled 4,381 barrels
of oil and 57,360 mcf of natural gas.
As
of December 31, 2023, no additional development or drilling operations are planned with respect to our Reeves County acreage.
Yoakum
County. We hold a 15.9% average working interest, subject to a proportionate 10% back-in after payout, in an approximately 360 gross
acre block in Yoakum County, Texas. Our Yoakum County acreage lies within the Midland sub-basin of the Permian Basin.
During
2019, we drilled the Frost #1H well, the first well on our Yoakum County acreage. The well was horizontally drilled, hydraulically fractured
in the San Andres Formation and completed and commenced production in mid-2019. A second well on our Yoakum County acreage, the Frost
#2H well, was horizontally drilled, hydraulically fractured in the San Andres Formation and completed and commenced production during
the third quarter of 2020. For the year ended December 31, 2023, our production in Yoakum County totaled 3,590 barrels of oil.
As
of December 31, 2023, no additional development or drilling operations are planned with respect to our Yoakum County acreage.
Louisiana
Properties
Our
sole property in Louisiana consists of a 23.4% mineral interest in 2,485 gross acres in East Baton Rouge Parish.
There
are no present wells, or plans to conduct drilling operations, on our Louisiana acreage.
-
Colombian Properties:
At
December 31, 2023, we held interests in a single block, through our equity investment in Hupecol Meta, LLC, operated by Hupecol Operating
and affiliates, in Colombia covering 639,405 gross acres. We identify our Colombian prospect as the Venus Exploration Area within the
CPO-11 block and remainder of the CPO-11 block.
The
following table sets forth information relating to our interests in prospects in Colombia at December 31, 2023:
The
CPO-11 concession, including the Venus Exploration Area, is located in the Llanos Basin and is owned and operated by Hupecol Meta.
CPO-11
During
2019, we acquired a two percent ownership interest in Hupecol Meta, LLC (“Hupecol Meta”). Hupecol Meta owns the 639,405 gross
acre CPO-11 block in the Llanos Basin in Colombia. The CPO-11 block is comprised of the 69,128 acre Venus Exploration area and 570,277
acres which was 50% farmed out by Hupecol to Parex Resources. In 2021, Hupecol Meta increased its ownership interest in the CPO-11 block
and we agreed to contribute $99,716. In 2022, we acquired additional interests in Hupecol Meta for an aggregate of $657,638. As a result
of our acquisition of additional interests in 2021 and 2022, our ownership interest in Hupecol Meta was approximately 18% at December
31, 2023. Through our ownership interest in Hupecol Meta, at December 31, 2023, we hold an approximately 16% interest in the Venus Exploration
Area and an approximately 8% interest in the remainder of the CPO-11 block.
The
CPO-11 block covers almost 1,000 square miles with multiple identified leads and prospects. During 2023, in the Venus Exploration Area,
Hupecol Meta drilled and completed the Venus 1-H horizontal well and the Venus 2-H ST1 well. At December 31, 2023, the Saturno ST1 and Venus 2A wells, both vertical wells, and the Venus 1-H and Venus 2-H ST1 wells, both horizontal wells, were on production in the Venus Exploration Area of
the CPO-11 block.
Hupecol
Meta has (i) proposed to relinquish approximately 62,139 gross acres within the Venus Exploration Area, decreasing its holding within
that area to approximately 7,157 gross, and 1,145 net, acres; and (ii) agreed to acquire the 50% interest in the CPO-11 block farmed
out to Parex Resources, which would increase Hupecol Meta’s net acreage position in the block to 91,244 acres. The relinquishment
of such acreage and acquisition of the Parex interest are both subject to approval of the Colombian hydrocarbons agency, or ANH.
Our
equity investment in Hupecol Meta is accounted for at cost and, accordingly, this report
does not include any reserves, production and operating results of Hupecol Meta.
In
late 2023, Hupecol advised that it intends to evaluate potential monetization of its assets in Colombia, including the interest in
the CPO-11 block held by Hupecol Meta. Pending the outcome of Hupecol’s evaluation of, and potential efforts regarding,
monetization of the CPO-11 block, we plan to drill one additional vertical well on the CPO-11
block by mid-2024 but otherwise have no planned drilling operations, or other planned operations, in Colombia and we expect
to continue to operate our existing wells on the CPO-11 block. There is no assurance as to the timing or outcome of Hupecol’s
potential monetization of assets.
Drilling
Activity
During
2023, we, through Hupecol Meta, drilled two wells in Colombia. The following table summarizes the number of wells drilled during 2023,
2022 and 2021, excluding any wells drilled under farmout agreements, royalty interest ownership, or any other wells in which we do not
have a working interest (direct or indirect).
Year Ended December 31,
Gross Net Gross Net Gross Net
Development wells, completed as:
Productive 2 0.32 — — — —
Non-productive — — — — — —
Total development wells 2 0.32 — — — —
Exploratory wells, completed as:
Productive — — 1 0.16 — —
Non-productive — — 1 0.16 — —
Total exploratory wells — — 2 0.32 — —
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, 2023, we had no drilling operations in progress.
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, 2023, we owned interests in 8 gross wells (including indirect interests in wells in Colombia through
our equity interest in Hupecol Meta). As of December 31, 2023, we had interests in productive wells, categorized by geographic area,
as follows:
Oil Wells Gas Wells
United States
Gross 4 —
Colombia
Gross 4 —
Total
Gross 8 —
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 (excluding our production, prices and costs attributable to wells operated by Hupecol
Meta), for each of the three years ended December 31, 2023, 2022, and 2021:
Year Ended December 31,
Net Production:
Gas (Mcf):
Colombia — — —
Oil (Bbls):
Colombia — — —
Average sales price:
Gas ($ per Mcf)
Colombia — — —
Oil ($ per Bbl)
Colombia — — —
Average production costs ($ per BOE):
Colombia — — —
Natural
Gas and Oil Reserves
Reserve
Estimates
The
following tables sets forth, by country and as of December 31, 2023, 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 below table excludes reserve and other information pertaining
to assets operated by Hupecol Meta.
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 Producing
Colombia(3) — — —
Proved Undeveloped
United States — — —
Colombia(3) — — —
Total Proved Undeveloped Reserves — — —
Proved Developed Proved Undeveloped Total Proved
Due
to the inherent uncertainties and the limited nature of reservoir data, proved reserves are subject to change as additional information
becomes available. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed
by the SEC, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes,
development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these
estimates.
Reserve
Estimation Process, Controls and Technologies
The
reserve estimates, including PV-10 and Standard Measure estimates, set forth above were prepared by Russell K. Hall & Associates,
Inc. for our Permian Basin, Texas reserves.
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 reports are prepared by reserve engineering firms 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. Upon
analysis and evaluation of data provided, the reserve engineering firms issue a preliminary appraisal report of our reserves. The preliminary
appraisal report and changes in our reserves are reviewed by our President and board for reasonableness of the results obtained. Once
any questions have been addressed, the reserve engineering firms issue final appraisal reports, reflecting their conclusions.
Russell
K. Hall & Associates is an independent Midland, Texas based professional engineering firm providing reserve evaluation services to
the oil and gas industry. Their report was prepared under the direction of Russell K. Hall, founder and President of Russell K. Hall
& Associates. Mr. Hall holds a BS in Mechanical Engineering from the University of Oklahoma, is a registered professional engineer
and a member of the Society of Petroleum Engineers, the Society of Independent Professional Earth Scientists and the West Texas Geological
Society. Mr. Hall has more than 30 years of experience in reserve evaluation for the oil and gas industry and the oil and gas finance
industry. Russell K. Hall & Associates, and its employees, have no interest in our company or our properties 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.
Our
reserve engineering firm 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
We
had no proved undeveloped reserves at either December 31, 2022 or December 31, 2023.
Developed
and Undeveloped Acreage
The
following table sets forth the gross and net developed and undeveloped acreage (including both leases and concessions, but excluding
acreage in which we hold a royalty interest but no working interest), categorized by geographical area, which we held as of December
31, 2023:
Developed Undeveloped
Gross Net Gross Net
Developed
acreage is comprised of leased acres that are within an area spaced by or assignable to a productive well and acreage in which we hold
a direct or indirect mineral interest with no potential development related lease expirations. 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.
The
U.S. undeveloped acreage set forth in the table above relate to our Louisiana acreage which is not subject to expiration.
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, 2023, we had no contractual agreements to sell our gas and oil production and all production was sold on spot markets.
Human
Capital
As
of December 31, 2023, we had 2 full-time employees and no part time employees. The employees are not covered by a collective bargaining
agreement, and we do not anticipate that any of our future employees will be covered by such agreements.
Competition
We
encounter intense competition from other oil and gas companies in all areas of our operations, including the acquisition of producing
properties and undeveloped acreage. Our competitors include major integrated oil and gas companies, numerous independent oil and gas
companies and individuals. Many of our competitors are large, well-established companies with substantially larger operating staffs and
greater capital resources and have been engaged in the oil and gas business for a much longer time than our Company. These companies
may be able to pay more for productive oil and gas properties, exploratory prospects and to define, evaluate, bid for and purchase a
greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties
and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate
transactions in this highly competitive environment.
Regulatory
Matters
Regulation
of Oil and Gas Production, Sales and Transportation
The
oil and gas industry is subject to regulation by numerous national, state and local governmental agencies and departments. Compliance
with these regulations is often difficult and costly and noncompliance could result in substantial penalties and risks. Most jurisdictions
in which we operate also have statutes, rules, regulations or guidelines governing the conservation of natural resources, including the
unitization or pooling of oil and gas properties, minimum well spacing, plugging and abandonment of wells and the establishment of maximum
rates of production from oil and gas wells. Some jurisdictions also require the filing of drilling and operating permits, bonds and reports.
The failure to comply with these statutes, rules and regulations could result in the imposition of fines and penalties and the suspension
or cessation of operations in affected areas.
Environmental
Regulation
Various
federal, state and local laws and regulations relating to the protection of the environment, including the discharge of materials into
the environment, may affect our exploration, development and production operations and the costs of those operations. These laws and
regulations, among other things, govern the amounts and types of substances that may be released into the environment, the issuance of
permits to conduct exploration, drilling and production operations, the discharge and disposition of generated waste materials and waste
management, the reclamation and abandonment of wells, sites and facilities, financial assurance and the remediation of contaminated sites.
These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from our operations
and may require the suspension or cessation of operations in affected areas.
The
environmental laws and regulations applicable to our U.S. operations include, among others, the following United States federal laws
and regulations:
● Clean Air Act, and its amendments, which govern air emissions;
● Clean Water Act, which governs discharges into waters of the United States;
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.
Hydraulic
Fracturing Regulation
Hydraulic
fracturing, or “fracking”, is a common practice used to stimulate production of oil and natural gas from tight formations,
including shales. Fracking involves the injection of fluids—usually consisting mostly of water but typically including small amounts
of chemical additives—as well as sand into a well under high pressure in order to create fractures in the rock that allow oil or
gas to flow more freely to the wellbore.
Except
as applies to federal lands, fracking generally is exempt from regulation under many federal environmental rules and is generally regulated
at the state level.
For
example, in Texas, the Texas Railroad Commission administers regulations related to oil and gas operations, including regulations pertaining
to protection of water resources in connection with those operations. The Texas Legislature adopted new legislation requiring oil and
gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas
Railroad Commission has adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission
issues an initial drilling permit after February 1, 2012. This law requires that the well operator disclose the list of chemical ingredients
subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on an internet website
and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used
to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission.
There
is public controversy regarding fracking with regard to the use of fracking fluids, impacts on drinking water supplies, use of water
and the potential for impacts to surface water, groundwater and the environment generally. Lawsuits and enforcement actions have been
initiated across the country implicating hydraulic fracturing practices. If new laws or regulations restricting hydraulic fracturing
are adopted, such laws could make it more difficult or costly to perform fracturing to stimulate production from tight formations as
well as make it easier to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could
adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities
could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased
monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and
potential increases in costs. Such legislative changes could cause operators to incur substantial compliance costs, and compliance or
the consequences of any failure to comply could have a material adverse effect on well operations and economics.
We
do not operate wells but contract well operations to third party operators. Operators of our wells may perform fracking operations, or
contract third parties to perform such operations, on wells in which we participate. Many newer wells would not be economical without
the use of fracking to stimulate production from the well. At this time, it is not possible to estimate the impact on our business of
newly enacted or potential federal or state legislation governing hydraulic fracturing.
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. These effects are widely referred to as “climate change.” Since its
December 2009 endangerment finding regarding the emission of greenhouse gases, the Environmental Protection Agency (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. The EPA’s final greenhouse gas reporting requirements pertain to certain oil and
gas production facilities.
Moreover,
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.
Since
taking office in 2021, the Biden presidential administration has signaled a commitment to cutting greenhouse gases, and an accompanying
commitment to moving the U.S. away from fossil fuels and to so-called green or renewable energy sources. Among the steps taken by the
Biden Administration are rejoining the Paris Agreement on climate change, a stated commitment to cut U.S. greenhouse gas emissions by
2030 to roughly half of 2005 levels, limitations on land available for oil and gas leasing, the United States Methane Emissions Reduction
Action Plan and certain Clean Air Act rules and various executive orders and certain provisions of the 2022 Inflation Reduction Act,
each of which imposes costs, burdens, restrictions or otherwise is designed to discourage the use of oil and gas and, accordingly, is
potentially harmful to the U.S. oil and gas industry.
As
a crude oil and natural gas company, the debate on climate change is relevant to our operations because the regulatory response is designed
to reduce demand for, and use of, our products, oil and gas, in favor of alternative forms of energy. We cannot presently predict the
ultimate impact of existing or future climate change initiatives on our company or our industry although we do anticipate that, at a
minimum, we will incur additional operating and other costs to respond to such initiatives.
Web
Site Access to Reports
Our
Web site address is www.houstonamerican.com. We make available, free of charge on our Web site, our annual report on Form 10-K,
quarterly reports on Form 10-Q and current reports on Form 8-K, and all amendments to these reports as soon as reasonably practicable
after such material is electronically filed with, or furnished to, the United States Securities and Exchange Commission. Information
contained on our website is not incorporated by reference into this report and you should not consider information contained on our website
as part of this report.
Item 1A. Risk Factors
Our
business activities and the value of our securities are subject to significant hazards and risks, including those described below. If
any of such events should occur, our business, financial condition, liquidity and/or results of operations could be materially harmed,
and holders and purchasers of our securities could lose part or all of their investments.
Company
and Organization Risks
We
have experienced recurring operating losses and may not attain profitability; attainment of profitability will require successful drilling
and development operations to support substantial increases in production and revenues.
We
have incurred losses from operations in each year since 2011 and, at December 31, 2023, had an accumulated deficit of $76,998,997. While
we have implemented cost control initiatives that have brought down our overhead in recent years and distributions of our share of profits
from Hupecol Meta have improved overall profitability, our ability to attain profitability is substantially dependent upon increasing
our production, production revenues and allocable profits from Hupecol Meta while continuing to control costs. In order to increase production
and revenues, we will need to successfully drill new wells on our existing, or future acquired, acreage at a pace, and with results,
significantly greater than in recent years. If, for any reason, we are unable to substantially increase our production and revenues and
sustain or grow our profitability from our investment in Hupecol Meta (see, “Our operations in Colombia are controlled by operators
which may carry out transactions affecting our Colombian assets and operations without our consent”, below), while controlling
drilling costs and overhead, we may never attain, or sustain, profitability. Our ability to so increase production and revenues and attain
profitability is subject to all of the other risks of oil and gas operations as well as our ability to fund our share of drilling and
development 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 depend on numerous factors beyond our control. These factors include,
but are not limited to, the following:
● the actions of the Organization of Petroleum Exporting Countries, or OPEC;
● the price and quantity of imports of foreign oil and natural gas;
● the level of global oil and natural gas exploration and production activity;
● the level of global oil and natural gas inventories;
● weather conditions;
● 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, we have experienced periodic declines in demand thought to be associated with slowing economic growth in certain
markets, including the effects of the COVID-19 pandemic, coupled with new oil and gas supplies coming on line and other circumstances
beyond our control that resulted in oil and gas supply exceeding global demand which, in turn, resulted in steep declines in prices of
oil and natural gas.
Past
declines in prices 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.
Supply
chain challenges, such as those arising in the wake of the COVID-19 pandemic, may adversely affect our operations.
Supply
and demand imbalances, such as those arising from the COVID-19 pandemic, have resulted, and may result, in shortages, backlogs and delayed
deliveries of a wide array of products and services, including products and services critical to oil and gas operations. Any future outbreaks
of infectious disease, or other development, may result in supply chain challenges, in which case we may experience unavailability, or
delay in delivery, of products and services that are critical to our well operations. Any such delays may result in deferral or reduction
of revenues and increased costs, any of which could materially adversely affect our profitability.
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