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 UNITED
STATES

 SECURITIES
AND EXCHANGE COMMISSION

 Washington,
D.C. 20549

 FORM

 (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

 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

 (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.)

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

 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)

by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No

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

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

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

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.

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

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).

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

 Item 1.

 Business

 Item 1A.

 Risk Factors

 Item 1B.

 Unresolved Staff Comments

 Item 1C.

 Cybersecurity

 Item 2.

 Properties

 Item 3.

 Legal Proceedings

 Item 4.

 Mine Safety Disclosures

 Item 5.

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

 Item 6.

 Reserved

 Item 7.

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

 Item 7A.

 Quantitative and Qualitative Disclosures About Market Risk

 Item 8.

 Financial Statements and Supplementary Data

 Item 9.

 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 Item 9A.

 Controls and Procedures

 Item 9B.

 Other Information

 Item 9C

 Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

 Item 10.

 Directors, Executive Officers, and Corporate Governance

 Item 11.

 Executive Compensation

 Item 12.

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

 Item 13.

 Certain Relationships and Related Transactions, and Director Independence

 Item 14.

 Principal Accountant Fees and Services

 Item 15.

 Exhibit and Financial Statement Schedules

 Item 16.

 Form 10-K Summary

 SIGNATURES

 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

 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

 Net
 acreage

 working
 interest
 %

 producing
 wells

 reserves
 (boe) (1)

 Oil
 (bbls) (1)

 Natural
 Gas
 (mcf) (1)

 Texas

 17.0
 %

 159,875

 7,971

 Louisiana

 23.4
 %

 —

 —

 —

 —

 Total
 U.S.

 22.1
 %

 159,875

 7,971

 Colombia (2)

 56,647

 8.9
 %

 —

 —

 —

 Total

 57,338

 8.9
 %

 159,875

 7,971

 (1)

 All reserve and production information excludes wells operated by Hupecol Meta in Colombia.

 (2)

 Net
 acreage and average working interest in Colombia are held through our investment in Hupecol Meta, and are subject to pending approvals
 of (i) the proposed relinquishment of a portion of the acreage within the Venus Exploration Area of the CPO-11 block; and (ii) the
 acquisition of the remaining 50% interest in the balance of the CPO-11 block previously farmed out to Parex Resources. See "Colombian
 Properties – CPO-11" below.

 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.

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:

 Property

 Operator

 Ownership
Interest(1)

 Total Gross
Acres

 Total Gross
Acres

 Gross
Wells

 CPO-11 – Venus Exploration Area

 16.0
 %

 69,128

 CPO-11

 8.0
 %

 570,277

 —

 —

 Total

 639,405

 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

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.

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

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,

 2023

 2022

 2021

 Gross

 Net

 Gross

 Net

 Gross

 Net

 Development wells, completed
 as:

 0.32

 —

 —

 —

 —

 Non-productive

 —

 —

 —

 —

 —

 —

 Total
 development wells

 0.32

 —

 —

 —

 —

 Exploratory wells, completed
 as:

 —

 —

 0.16

 —

 —

 Non-productive

 —

 —

 0.16

 —

 —

 Total
 exploratory wells

 —

 —

 0.32

 —

 —

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.

Wells

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

 Gross

 —

 Net

 0.68

 —

 Gross

 —

 Net

 0.64

 —

 Total

 Gross

 —

 Net

 1.22

 —

 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,

 2023

 2022

 2021

 Net Production:

 Gas (Mcf):

 73,635

 60,069

 —

 —

 —

 Total

 73,635

 60,069

 Oil (Bbls):

 7,971

 10,688

 14,367

 —

 —

 —

 Total

 7,971

 10,688

 14,367

 Average sales price:

 Gas ($ per Mcf)

 $
 1.38

 $
 5.13

 $
 4.13

 —

 —

 —

 Total

 $
 1.38

 $
 5.13

 $
 4.13

 Oil ($ per Bbl)

 $
 74.08

 $
 93.10

 $
 63.60

 —

 —

 —

 Total

 $
 74.08

 $
 93.10

 $
 63.60

 Average production costs ($ per BOE):

 $
 27.03

 $
 27.48

 $
 33.67

 —

 —

 —

 Total

 $
 27.03

 $
 27.48

 $
 33.67

 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

 159,873

 Colombia (3)

 —

 —

 —

 Total Proved Developed Producing Reserves

 159,873

 Proved Undeveloped

 —

 —

 —

 Colombia (3)

 —

 —

 —

 Total Proved Undeveloped Reserves

 —

 —

 —

 Total Proved Reserves

 159,873

 Undeveloped

 Total

 PV-10 (1)

 $

 $
 —

 $

 Standardized
 measure (4)

 $

 $
 —

 $

 (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, 2023. 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, 2023.
 The average prices utilized for purposes of estimating our proved reserves were $74.70 per barrel of oil and $1.98 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)

 As an equity investment accounted for at cost, we do not report any reserves attributable to our investment in
 Hupecol Meta.

 (4)

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

 Due
to the inherent uncertainties and the limited nature of reservoir data, proved reserves are subject to change as additional information
becomes available. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed
by the SEC, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes,
development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these
estimates.

 Reserve
Estimation Process, Controls and Technologies

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

Undeveloped Reserves

 We
had no proved undeveloped reserves at either December 31, 2022 or December 31, 2023.

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:

 Undeveloped

 Gross

 Net

 Gross

 Net

 2,485

 Colombia (1)

 69,128

 11,053

 570,277

 45,594

 Total

 69,768

 11,162

 572,762

 46,176

 (1)
 Gross
 and net acreage in Colombia represents acreage held and operated by Hupecol Meta and our
 proportionate interest therein as an owner of Hupecol Meta, and is subject to pending approvals
 of (i) the proposed relinquishment of a portion of the acreage within the Venus Exploration
 Area of the CPO-11 block; and (ii) the acquisition of the remaining 50% interest in the balance
 of the CPO-11 block not currently held by Hupecol Meta. See "Properties – Colombian
 Properties – CPO-11" above. Assuming approval of those proposals, gross and net
 developed acreage in Colombia would decrease to approximately 7,158 and 1,145 acres, respectively,
 and net undeveloped acreage in Colombia would increase to approximately 113,294 acres.

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

 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;

 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.

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:

 changes
 in global supply and demand for oil and natural gas, including changes in demand resulting from general and specific economic conditions
 relating to the business cycle and other factors (e.g., global health pandemics such as COVID-19);

 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, including renewable energy initiatives that result in energy consumption transitioning away
 from fossil fuels; 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, 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
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
ability to acquire additional mineral acreage and to drill and develop our existing acreage as well as other acreage that may be acquired
is subject to availability of financing on satisfactory terms.

 Our
financial resources are limited and may not be adequate to fully drill and develop our acreage or to consummate any meaningful acquisition.
While our available funds as of March 2024 are expected to be adequate to fund our share of well costs on wells expected to be drilled,
as of that date, during 2024, our funds on hand are not expected to be adequate to support a long-term drilling and development plan
with respect to our existing acreage holdings, should such a plan be implemented.

 We
may continue to seek to access the capital markets to support planned drilling operations or acquisitions through sales of equity securities
or may seek debt financing to support such capital requirements. We do not presently have any commitments to provide equity or debt financing
to support any future drilling operations or acquisitions and there can be no assurance that such financing will be available if and
when needed on acceptable terms or at all. If we are unable to fund our share of drilling and completion costs of future wells, we may
experience flat and declining production and revenues and decreased profitability and may be subject to penalties with respect to our
interest in acreage.

 Our
ability to utilize our common stock to finance future capital needs, or for other purposes, is limited by our authorized shares available
for issuance.

 As
of March 2024, we had authority to issue a total of 12 million shares of common stock, of which approximately 10.9 million shares had
been issued and 1 million shares were reserved for issuance pursuant to outstanding stock options and warrants. Absent an increase in
authorized shares of common stock, we only have approximately 200,000 shares of common stock available for issuance to raise capital
or to support additional stock option grants and for other uses.

 We
have historically utilized "at-the-market" sales of our common stock to provide financing to support growth and operations.
With the limited shares of common stock presently available for issuance, our ability to secure additional funding through the sale of
common stock is limited. Absent an increase in the shares of common stock authorized to be issued, we will be limited to other financing
structures in the event additional financing is required. Such alternative structures may be less favorable or unavailable in which case
we may be forced to forego opportunities or required to downsize operations due to lack of funding.

 We
may be unable to make attractive acquisitions and any acquisitions may be subject to substantial risks that could adversely affects our
business.

 Acquisitions
of additional mineral acreage at favorable prices is part of our strategy to increase and diversify our holdings and grow our production
and revenues. We expect to focus our acquisition efforts in the Permian Basin and in Colombia with an emphasis on partnering with proven
operators in the area to acquire positions at favorable prices. Competition for mineral acreage in the Permian Basin is intense. Other
operators, particularly large operators, have historically paid substantially higher prices for Permian Basin acreage than we have paid.
There can be no assurance that we will be able to successfully acquire additional acreage in the Permian Basin, Colombia or elsewhere
at favorable prices or at all. Even if we are successful in acquiring additional acreage on favorable terms, it is possible that such
acreage (i) will be more speculative than higher priced acreage, (ii) may face challenges or limitations in drilling and operations such
as lack of, or limited access to, critical infrastructure, or (iii) may prove uneconomical.

 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.

 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.

 Oil
and Gas Operating Risks

 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.

 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:

 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, including potential declines in production and revenues from properties,
declines in value of properties and lease expirations, among other potential consequences.

 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.

 Our
operations are expected to involve use of horizontal drilling and completion techniques, which involve risks and uncertainties in their
application.

 Our
operations, in most instances, are expected to involve utilizing some of the latest drilling and completion techniques as developed by
our service providers, including horizontal drilling and completion techniques. Risks that we face while drilling horizontal wells include,
but are not limited to, the following:

 landing
 the wellbore in the desired drilling zone;

 staying
 in the desired drilling zone while drilling horizontally through the formation;

 running
 casing the entire length of the wellbore; and

 being
 able to run tools and other equipment consistently through the horizontal wellbore.

 Risks
that we face while completing wells include, but are not limited to, the following:

 the
 ability to fracture stimulate the planned number of stages;

 the
 ability to run tools the entire length of the wellbore during completion operations; and

 The
 ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

 Horizontal
drilling in emerging areas with little or no history of use of such techniques is more uncertain than drilling in areas that are more
developed and have a longer history of established horizontal drilling operations. If our horizontal drilling fails to adequately address
the risks described, we may incur costs overruns, underperformance by wells or non-productive wells.

 The
unavailability or high cost of drilling rigs, equipment, supplies, personnel, water disposal and oil field services could adversely affect
our ability to execute on a timely basis our exploration and development plans within our budget and operate profitably.

 Shortages
or the high cost of drilling rigs, equipment, supplies or personnel, including shortages or unavailability of personnel, supplies and
equipment, 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. In particular, high levels of horizontal drilling and hydraulic fracturing operations in the
Permian Basin have, from time to time, created increased demand, and higher costs, for associated drilling and completion services, water
supply, handling and disposal and access to production handling and transportation infrastructure, each of which have resulted in higher
than anticipated prices with respect to our initial Reeves County wells. 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.

 We
may not be able to obtain access on commercially reasonable terms or otherwise to pipelines and storage facilities, gathering systems
and other transportation, processing, fractionation and refining facilities to market our oil and gas production; we rely on a limited
number of purchasers of our products.

 The
marketing of oil and gas production depends in large part on the availability, proximity and capacity of pipelines and storage facilities,
gathering systems and other transportation, processing, fractionation and refining facilities, as well as the existence of adequate markets.
If there were insufficient capacity available on these systems, if these systems were unavailable to us, or if access to these systems
were to become commercially unreasonable, the price offered for our production could be significantly depressed, or we could be forced
to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons while
we construct our own facility or await the availability of third party facilities. We rely on facilities developed and owned by third
parties in order to store, process, transport, fractionate and sell our oil and gas production. Our plans to develop and sell our oil
and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient
transportation, storage or processing and fractionation facilities to us, especially in areas of planned expansion where such facilities
do not currently exist.

 The
amount of oil and gas that can be produced is subject to limitations in certain circumstances, such as pipeline interruptions due to
scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, transportation, refining or processing facilities,
or lack of capacity on such facilities. Curtailments arising from these and similar circumstances may last from a few days to several
months, resulting in lost or curtailed production and revenues.

 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 Colombian acreage 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.

 To
the extent that we enter into transportation contracts with pipelines that are subject to FERC regulation, we are subject to FERC requirements
related to use of such capacity. Any failure on our part to comply with FERC's regulations and policies or with an interstate pipeline's
tariff could result in the imposition of civil and criminal penalties.

 A
limited number of companies purchase a majority of our production. The loss of a significant purchaser could have a material adverse
effect on our ability to sell production.

 Our
oil and gas holdings and operations are concentrated, and we are dependent upon the results of drilling and production operations on
a small number of prospects and wells. If those properties and wells perform below expectations, we may experience production, revenues
and profitability below expectations.

 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. At December 31, 2023, we owned interests
in 691 net acres and 0.68 net wells in the United States and, through properties owned and/or operated by Hupecol entities, 56,647 net
acres and 0.64 net wells in Colombia. While we continually evaluate potential prospects in operations in diverse regions, our production,
revenues and profitability for the foreseeable future are expected to be highly dependent upon the results of existing and future wells
we may drill in the Permian Basis and the CPO-11 block in Colombia. In order to grow our revenues and improve profitability, we must
continue to drill productive wells. If existing wells, or future wells we may drill, perform below expectations, we may experience flat
or declining production and revenues and may be unable to attain profitability.

 Unless
we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flows and
income.

 Unless
we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved
reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining
production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production,
and, therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves
and economically finding or acquiring additional recoverable reserves. If we are unable to develop, exploit, find or acquire additional
reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing
properties would be incapable of sustaining commercial production.

 A
substantial percentage of our properties are unproven and undeveloped; therefore, the cost of proving and developing our properties and
risk associated with our success is greater than would be the case if the majority of our properties were categorized as proved developed
producing.

 Because
a substantial percentage of our properties are unproven and/or undeveloped, we require significant capital to prove and develop such
properties before they may become productive. 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.

 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.

 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.

 Accounting
rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on
specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development
plans, production data, economics and other factors, we have written down the carrying value of our oil and natural gas properties periodically
and may be required to further write down the carrying value of oil and gas properties in the future. A write-down would constitute a
non-cash charge to earnings. It is likely the cumulative effect of a write-down could also negatively impact the trading price of our
securities.

 Reserve
estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying
assumptions will materially affect the quantities and present value of our reserves.

 The
process of estimating oil and natural gas reserves is complex, requiring interpretations of available technical data and many assumptions,
including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially
affect the estimated quantities and present value of reserves reported.

 In
order to prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available
geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also
requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures,
taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.

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

 The
present value of future net revenues from our proved reserves, as reported from time to time, should not be assumed to be the current
market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we generally base the estimated discounted
future net cash flows from our proved reserves on costs on the date of the estimate and average prices over the preceding twelve months.
Actual future prices and costs may differ materially from those used in the present value estimate. If future prices decline or costs
increase it could negatively impact our ability to finance operations, and individual properties could cease being commercially viable,
affecting our decision to continue operations on producing properties or to attempt to develop properties. All of these factors would
have a negative impact on earnings and net income, and most likely the trading price of our securities.

 Our
operations will be subject to environmental and other government laws, regulations and policies that are costly, could potentially subject
us to substantial liabilities and potentially result in decreased demand for products.

 Crude
oil and natural gas exploration and production operations in the United States and in Colombia are subject to extensive federal, state
and local laws and regulations. Oil and gas companies are subject to laws and regulations addressing, among others, land use and lease
permit restrictions, bonding and other financial assurance related to drilling and production activities, spacing of wells, unitization
and pooling of properties, environmental and safety matters, plugging and abandonment of wells and associated infrastructure after production
has ceased, operational reporting and taxation. Failure to comply with such laws and regulations can subject us to governmental sanctions,
such as fines and penalties, as well as potential liability for personal injuries and property and natural resources damages. We may
be required to make significant expenditures to comply with the requirements of these laws and regulations, and future laws or regulations,
or any adverse change in the interpretation of existing laws and regulations, could increase such compliance costs. Regulatory requirements
and restrictions could also delay or curtail our operations and could have a significant impact on our financial condition or results
of operations.

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

 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"
and have adopted policies to actively promote alternative energy "green energy" sources that are specifically designed to
replace fossil fuels. 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 "green energy" initiatives
could substantially reduce demand for our products in the future.

 Increased
regulation, or limitations on the use, of hydraulic fracturing could increase our cost of operations and reduce profitability.

 Our
existing Permian Basin wells have been hydraulically fractured and future wells that we may drill in the Permian Basin are expected to
be economically viable only if hydraulic fracturing is utilized to increase flows of oil and natural gas, particularly in shale formations.
The use of hydraulic fracturing has been the subject of much scrutiny and debate in recent years with many activists and state and federal
legislators and regulators actively pushing for most stringent regulation of such operations or even the ban of such operations.

 In
the event that state or federal regulation of hydraulic fracturing is increased or hydraulic fracturing is substantially curtailed or
prohibited through law or regulation, our cost of drilling and operating wells may increase substantially. In some cases, increased costs
associated with increased regulation of hydraulic fracturing, or the prohibition of hydraulic fracturing, may result in wells being uneconomical
to drill and operate that would otherwise be economical to drill and operate in the absence of such regulations or prohibitions. Should
wells be determined to be uneconomical as a result of increasing regulation of hydraulic fracturing, we may be required to write-down
or abandon oil and gas properties that are determined to be uneconomical to drill and develop. Additionally, potential litigation arising
from alleged harm resulting from hydraulic fracturing may materially adversely affect our financial results and position regardless of
whether we prevail on the merits of such litigation.

 International
Operations Risks

 Our
operations in Colombia are subject to uncertainty, delays and other risks relating to political and economic instability.

 We
currently have interests in a single oil and gas concession in Colombia and anticipate that operations in Colombia may 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. While each of our
past and current oil and gas concessions in Colombia have been granted by the federal government, we have experienced multiple extended
delays in obtaining necessary permits to commence drilling operations on concessions. The delays in obtaining necessary permits have
been attributed to numerous factors beyond our control but not uncommon in Colombia, including strong local opposition to drilling operations
based on environmental and other concerns. In the face of such opposition, our operator shelved drilling on multiple concessions and
ultimately abandoned those concessions. The abandonment of those concessions was the principal factor in our realizing a loss on disposal of oil and gas properties
of $ 2,343,126 during 2023.

 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 many years with insurgents attacking civilians and violent guerilla activity continues in many
parts of the country. While the parties have expressed a continuing commitment to a peace process, until such process is formalized,
any operations we may conduct in Colombia, and any assets we may hold in Colombia, may continue to be subject to risk associated with
guerilla activity that may disrupt operations and result in losses from operations and of assets. 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 prospect continues to be
characterized by political risks and, in fact, our operator has experienced delays in planned operations on prospects due to such political
risks. On the concessions abandoned by our operator, the operator experienced delays extending multiple years. In the event of 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.

 Inflation
rates in Colombia have consistently exceeded inflation rates in the United States. The situation does not meet the definition of highly
inflationary, but in the event it does meet that definition, we may experience financial loss associated with the related increase in
operating expenses.

 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 indirect interests
in Colombia. We have been an investor in a number of ventures operated by Hupecol, including our current holdings in the CPO-11 block,
which represents all of our current assets in Colombia. In the past, 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. Additionally, Hupecol has, on occasion, temporarily shut-in production from our Colombian properties. Hupecol advised us,
in late 2023, that it intends to evaluate monetization of the CPO-11 block. Our management intends to closely monitor the nature and
progress of Hupecol's efforts to monetize the block 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. Absent new investments in Colombia, if Hupecol ultimately sells the CPO-11 block, we will have no remaining
operations in Colombia.

 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. In 2022, we acquired a portion
of a joint interest partner's interest in Hupecol Meta, which operates the CPO-11 block, when the joint interest partner was unable
to fund its portion of development costs. As a result of such acquisition, while we did increase our ownership interest in the prospect,
we assumed an increased portion of the prospect's development costs. 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.

 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.

 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.

 Stock
Related Risks

 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.

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

 The
sale of a substantial number of shares of our common stock may affect our stock price.

 We
may require additional capital to support our future drilling plans and may issue additional shares of our common stock or equity-related
securities to secure such capital. 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.

 Item 1B.

 Unresolved Staff Comments

 Not
applicable.

 Item
 1C.

 Cybersecurity

 We
do not presently maintain any formal processes for assessing, identifying and managing material risks from cybersecurity threats.

 We
engage a consultant to maintain our website, email, financial record keeping and related internet capabilities, including, as necessary,
addressing any cybersecurity incidents. To date we have not experienced any material cybersecurity incidents. Given the nature of our
operations (single location, minimal customer interface, no gathering of customer digital data, etc.), we do not believe that we are
reasonably likely to face any material cybersecurity risks.

 Our
audit committee is tasked with oversight of risks from cybersecurity threats. Our audit committee interfaces with our consultant periodically
to assess vulnerability to cybersecurity threats and determine actions to be taken in response to such threats. In the event risks are
identified and actions are recommended by our consultant, our audit committee will communicate the same to our chief executive officer
who is charged with interfacing with our consultant in addressing any identified cybersecurity threats. Similarly, if our officers become
aware of material cybersecurity threats, they are charged with communicating the same to our audit committee.

 Item 2.

 Properties

 We
currently lease approximately 3,080 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 October 31, 2025,
is approximately $7,200. 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 April 1, 2024, we were not aware of any current, pending
or threatened litigation or proceedings that could have a material adverse effect on our results of operations, cash flows or financial
condition.

 Item
 4.

 Mine Safety Disclosures

 Not
applicable.

 PART
II

 Item
 5.

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

 Market
Information

 Our
common stock is listed on the NYSE American under the symbol "HUSA."

 Holders

 As
of April 1, 2024, there were approximately 10,906,353 shareholders of record of our common stock.

 Securities
Authorized for Issuance Under Equity Compensation Plans

 The
following table provides information as of December 31, 2023 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)

 1,000,807

 $
 2.46

 121,333

 Equity compensation plans not approved by security holders

 —

 —

 —

 1,000,807

 $
 2.46

 121,333

 (1)

 Consists of shares (a) reserved
 for issuance pursuant to outstanding options granted and (b) shares remaining available for future issuance; under the Houston American
 Energy Corp. 2021 Equity Incentive Plan.

 Item
 6.

 Selected Financial Data

 Not
applicable.

 Item
 7.

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

 We
are an independent energy company focused on the development, exploration, exploitation, acquisition, and production of natural gas and
crude oil properties with principal holdings in the U.S. Permian Basin, the South American country of Colombia and additional holdings
in the U.S. Gulf Coast region.

 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 opportunistic entrance into, existing and emerging resource plays. We do not operate wells
but 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, identifying stranded blocks
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

 Lease
Activity

 Colombia.
In 2023, we released our interest in the last of our legacy non-Hupecol Meta properties in Colombia, formally terminating our interests
in the Picachos and Macaya blocks. We recognized a loss on disposal of oil and gas properties of $ 2,343,126
as a result of this transaction.

 At
December 31, 2023, our sole holdings in Colombia consisted of our interest in Hupecol Meta which holds a working interest in the 639,405
gross acre CPO-11 block in the Llanos Basin in Colombia, comprised of the 69,128 acre Venus Exploration Area and 570,277 acres, which
was 50% farmed out by Hupecol Meta. Through our ownership interest in Hupecol Meta, we hold an approximately 16% interest in the Venus
Exploration Area and an approximately 8% interest in the remainder of the block.

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.

 United
States. During 2023, we experienced lease expirations in Yoakum County, Texas (46 net acres).

 Drilling
Activity and Well Operations

 Colombia. During
2023, Hupecol Meta drilled and completed, and production commenced on, two wells in Colombia, the Venus 1-H horizontal well and the
Venus 2-H ST1 horizontal well. The Saturno 1 ST -1 vertical well, drilled in 2022, was shut-in during the third quarter of
2023 and brought back onto production in late 2023. The legacy well Venus 2A was in production through 2023. At December 31, 2023,
Hupecol Meta had 4 wells on production.

 United
States. During 2023, we drilled no wells on our U.S. properties. At December 31, 2023, we had 4 wells on production in the U.S. Permian
Basin.

Investments

2023, our capital investment expenditures for acreage acquisitions, drilling, completion and related operations, as well as investments
relating to Hupecol Meta, totaled $2,403,219, all of which was attributable to direct investments in Hupecol Meta to fund our share
of drilling and operating costs.

 Distributions
from Equity Investment

2023, we received distributions, totaling $1,220,954, from Hupecol Meta, representing our share of distributable net income and reflected
as "Other Income" on our Statement of Operations.

 Planned
Drilling and Divestiture in Colombia

has 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.

 Financing
Activities

 In
November 2022, we entered into an At-the-Market Sales Agreement (the "Sales Agreement") with Univest Securities, LLC ("Univest")
pursuant to which we could sell (the "2022 ATM Offering"), at our option, up to an aggregate of $3.5 million in shares of
common stock through Univest, as sales agent. Sales of shares under the Sales Agreement (the "2022 ATM Offering") were made,
in accordance with placement notices delivered to Univest, which notices set parameters under which shares could be sold. The 2022 ATM
Offering was made pursuant to a shelf registration statement by methods deemed to be "at the market," as defined in Rule
415 promulgated under the Securities Act of 1933. We pay Univest a commission in cash equal to 3% of the gross proceeds from the sale
of shares in the 2022 ATM Offering. We reimbursed Univest for $25,000 of expenses incurred in connection with the 2022 ATM Offering.

2023, we sold an aggregate of 578,707 shares in connection with the 2022 ATM Offering and received proceeds, net of commissions and expenses,
of $1,652,000.

 Executive
Compensation Changes

2023, our compensation committee approved, and we paid, a cash bonus of $200,000 to our Chief Executive Officer and increased, effective
July 1, 2023, our Chief Executive Officer's annual base salary from $180,000 to $240,000.

 Impairment
Charge

 During 2023, we incurred an impairment charge
of $537,686. The impairment charge was attributable to declines in energy prices and production relating to our Reeves County properties.

 Critical
Accounting Estimates and Policies

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

 Full
Cost Method of Accounting for Oil and Gas Activities. We follow the full cost method of accounting for oil and gas property acquisition,
exploration and development activities. Under this method, all productive and nonproductive costs incurred in connection with the exploration
for and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisition, geological and geophysical
work, delay rentals, costs of drilling, completing and equipping successful and unsuccessful oil and gas wells and related internal costs
that can be directly identified with acquisition, exploration and development activities, but does not include any cost related to production,
general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized
unless significant amounts of oil and gas reserves are involved. No corporate overhead has been capitalized as of December 31, 2023.
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.

 Revenue
recognition. On January 1, 2018, we adopted the new revenue guidance using the modified retrospective method for contracts that were
not complete at December 31, 2017. ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)". Topic 606 requires
an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration
the entity expects to be entitled to in exchange for those goods or services. We adopted Topic 606 on January 1, 2018, using the modified
retrospective method applied to contracts that were not completed as of January 1, 2018. Under the modified retrospective method, prior
period financial positions and results are not adjusted. The cumulative effect adjustment recognized in the opening balances included
no significant changes as a result of this adoption. While our 2018 net earnings were not materially impacted by revenue recognition
timing changes, Topic 606 requires certain changes to the presentation of revenues and related expenses beginning January 1, 2018.

 Our
revenue is comprised principally of revenue from exploration and production activities. Our oil is sold primarily to marketers, gatherers,
and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local
distribution companies, and natural-gas marketers. Natural gas liquids, or NGLs, are sold primarily to direct end-users, refiners, and
marketers. Payment is generally received from the customer in the month following delivery.

 Contracts
with customers have varying terms, including spot sales or month-to-month contracts, contracts with a finite term, and life-of-field
contracts where all production from a well or group of wells is sold to one or more customers. We recognize sales revenues for oil, natural
gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers
at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is
completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market
differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs.

are recognized for the sale of our net share of production volumes.

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.

oil and gas properties not subject to amortization include the following at December 31, 2023 and 2022:

 At
 December
31, 2023

 At
 December
31, 2022

 Acquisition costs

 $
 —

 $
 143,847

 Evaluation costs

 —

 2,199,279

 Total

 $
 —

 $

 The
carrying value of unevaluated oil and gas prospects consisted of $2,343,126 expended for properties in South America at December 31,
2022. Our interest in these properties was relinquished in 2023, resulting in a loss on disposal of oil and gas properties of $ 2,343,126.

 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, 2023 Compared to Year Ended December 31, 2022

 Oil
and Gas Revenues. Total oil and gas revenues decreased 52% to $794,027 in 2023 from $1,638,841 in 2022.

 The
decrease in revenues was attributable to (i) declines in oil production, down 25%, and gas production, down 22% from 2022 levels; and
(ii) declines in average sales price of oil, down 20%, and average sales price of natural gas, down 73% from 2022 levels.

 The
following table sets forth the gross and net producing wells, net oil and gas production volumes and average hydrocarbon sales prices
for 2023 and 2022 (excluding information pertaining to Hupecol Meta):

 2023

 2022

 Gross producing wells

 Net producing wells

 0.68

 0.68

 Net oil production (Bbls)

 7,971

 10,688

 Net gas production (Mcf)

 73,635

 Oil—Average sales price per barrel

 $
 74.08

 $
 93.10

 Gas—Average sales price per mcf

 $
 1.38

 $
 5.13

 The
change in production volumes reflects natural production declines. The change in average oil and natural gas prices realized reflects
movements in global energy prices.

 All
oil and gas sales revenues for 2023 and 2022, by region (excluding information pertaining to Hupecol Meta), were as follows:

 U.S.

 Total

 2023

 Oil sales

 $
 —

 $
 590,486

 $
 590,586

 Gas sales

 $
 —

 $
 79,443

 $
 79,443

 2022

 Oil sales

 $
 —

 $
 995,083

 $
 995,083

 Gas sales

 $
 —

 $
 377,534

 $
 377,534

 Lease
Operating Expenses. Lease operating expenses, excluding expenses attributable to our cost method investment in Colombia, decreased
11% to $473,925 in 2023 from $531,675 in 2022.

 Lease
operating expense, by region, for 2023 and 2022 (excluding information pertaining to Hupecol Meta), were as follows:

 U.S.

 Total

 2023

 $
 —

 $

 $

 2022

 $
 —

 $

 $

 The
change in lease operating expenses was principally attributable to the decrease in production during 2023.

 Depreciation
and Depletion Expense. Depreciation and depletion expense decreased by 18% to $167,527 in 2023 from $205,458 in 2022. The decrease
in depreciation and depletion during 2023 was attributable to the decrease in production during 2023.

 Impairment Expense and Loss
on Disposal of Oil and Gas Properties. During 2023, we realized an impairment expense of $537,686 and a loss on disposal of oil and
gas properties of $2,343,126. The impairment was attributable to declines in energy prices and production relating to our Reeves County
properties. The loss on disposal of oil and gas properties was attributable to the release our interest in certain properties in Colombia.

and Administrative Expenses (Excluding Stock-Based Compensation). General and administrative expense increased by 17% to
$1,614,245 in 2023 from $1,374,060 in 2022. The change in general and administrative expense was primarily attributable to an
increase in the base salary of our CEO from $180,000 to $240,000 annually, effective July 1, 2023 and approximately $200,000
increase in legal and professional services fees.

 Stock-Based
Compensation. Stock-based compensation increased to $238,314 in 2023 from $206,210 in 2022.

 Other
Income. Other income totaled $1,369,519 in 2023 compared to $33,641 in 2022. Other income consisted of (i) equity investment distributions
from Hupecol Metal totaling $1,220,954 during 2023; and (ii) interest earned on cash balances, totaling $148,565 in 2023 and $33,641
in 2022.

 Distributions
from Hupecol Meta reflect, generally, our share of distributable net income of Hupecol Meta. Distributions should not be viewed as a
measure of actual operating results of Hupecol Meta for the period of such distributions or any other periods. Distributions merely reflect
determinations by the managers of Hupecol Meta to make distributions in accordance with contractual rights of the various members of
Hupecol Meta within the discretion of the managers as permitted under the contracts governing Hupecol Meta. We report distributions from
Hupecol Meta as "Other Income" to the extent that the character of the distributions is in the nature of income and not a
return of capital. The distributions received during 2023 are, generally, attributable to operations of Hupecol Meta's initial
wells, the Saturno ST1 vertical well, the Venus 2A vertical well, a legacy well that had been shut-in, the Venus 1-H well, Hupecol Meta's
first horizontal well, which began production in May 2023, and the Venue 2-H ST1 well, which began production in August 2023.

 The
increase in interest income from 2022 to 2023 was attributable to the increase in our cash balances, resulting from sales of common stock
during 2023, and substantial increases in interest rates due to trends in the broad debt market.

 Financial
Condition

 Liquidity
and Capital Resources. At December 31, 2023, we had a cash balance of $4,059,182 and working capital of $3,917,231, compared to a
cash balance of $4,547,210 and working capital of $4,601,168 at December 31, 2022.

 Cash
Flows. Operating activities provided cash of $263,191 during 2023, compared to $228,962 used during 2022. The change in cash
flows from operating activities was attributable to an increase in other income of $1,335,878 (principally distributions from
Hupecol Meta), partially offset by increased general and administrative expenses (up approximately $240,000, excluding non-cash
stock-based compensation) and decreased revenues net of lease operating expense and severance tax (down approximately $687,000).

 Investing
activities used cash of $2,403,219 during 2023, compared to $1,661,405 used during 2022. The increase in cash used in investing activities
is attributable to direct investments in Hupecol Meta to fund our share of costs associated with commencement
of Hupecol Meta's drilling program on the CPO-11 block.

 Financing
activities provided cash of $1,652,000 during 2023, compared to $1,543,000 provided during 2022. Cash provided by financing activities
during both 2023 and 2022 was attributable to funds received from the sale of common stock under our 2022 ATM Offering.

 Long-Term
Liabilities. At December 31, 2023, we had long-term liabilities of $134,167, compared to $219,148 at December 31, 2022. Long-term
liabilities, as of December 31, 2023, consisted of a reserve for plugging costs of $63,084 and a lease liability of $71,083.

and Exploration Expenditures and Commitments. Our principal capital and exploration expenditures relate to ongoing efforts to
acquire, drill and complete prospects. During 2023, capital expenditures relating to Hupecol Meta increased with our investments in
Hupecol Meta to fund our share of costs associated with the initial wells drilled on the CPO-11 block. Based on discussions with
Hupecol Meta, we anticipate that one additional vertical well will be drilled on the CPO-11 block by mid-2024
pending efforts by Hupecol Meta to monetize its interest in the CPO-11 block. Our costs relating to the drilling of such well is estimated at approximately
$500,000. There are no present plans to conduct additional
drilling operations on our U.S. properties. The actual timing and number of well operations undertaken, if any, will be principally
controlled by the operators of our acreage based on a number of factors, including but not limited to availability of financing,
performance of existing wells on the subject acreage, energy prices and industry condition and outlook, costs of drilling and
completion services and equipment and other factors beyond our control or that of our operators.

 In
addition to possible operations on our existing acreage holdings, we continue to evaluate drilling prospects in which we may acquire
an interest and participate.

 As
our allocable share of well costs will vary depending on the timing and number of wells drilled as well as our working interest in each
such well and the level of participation of other interest owners, we have not established a drilling budget but will budget on a well-by-well
basis as our operators propose wells.

 We
believe that we have the ability, through our cash on-hand, to fund operations during 2024 and for the twelve months following the issuance
of these financial statements.

 In
the event that we pursue additional acreage acquisitions or expand our drilling plans, we may be required to secure additional funding
beyond our resources on hand. While we may, among other efforts, seek additional funding from "at-the-market" sales of common
stock, and private sales of equity and debt securities, we presently have, as of December 31, 2023, less than 200,000 authorized shares
of common stock available for issuance to support equity capital raises and we have no commitments to provide additional funding, and
there can be no assurance that we can secure the necessary capital to fund our share of drilling, acquisition or other costs on acceptable
terms or at all. If, for any reason, we are unable to fund our share of drilling and completion costs and fail to satisfy commitments
relative to our interest in our acreage, 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 and we may be required to curtail operations and forego opportunities.

 Item
 7A.

 Quantitative
 and Qualitative Disclosures About Market Risk

 Commodity
Price Risk

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

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

 Item
 8.

 Financial
 Statements and Supplementary Data

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

 Item
 9.

 Changes
 in and Disagreements with Accountants on Accounting and Financial Disclosure

 Not
applicable.

 Item
 9A.

 Controls
 and Procedures

 Disclosure
Controls and Procedures

 Under
the supervision and with the participation of our management, including our principal executive who also serves as our principal financial
officer, we conducted an evaluation as of December 31, 2023 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 concluded that our disclosure controls and procedures were not effective as of December
31, 2023.

 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, we conducted an evaluation of the effectiveness of our internal control over financial reporting
based on the 2013 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, 2023. Such conclusion reflects our chief executive
officer's assumption of duties of the principal financial officer and the resulting lack of an appropriate level of accounting
knowledge and experience commensurate with the financial reporting requirements for a public company, in particulate with respect to
technical accounting knowledge regarding accounting for certain transactions, and a related 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 2023 that has materially affected, or is
reasonably likely to materially affect, our internal control over financial reporting.

 Item
 9B.

 Other
 Information

 Not
applicable

 Item
 9C.

 Disclosure
 Regarding Foreign Jurisdictions that Prevent Inspections

 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, 2023, and their ages and positions as of that date, are as follows:

 Name

 Age

 Position

 John
 Terwilliger

 President
 and Chief Executive Officer

 John
Terwilliger has served as our President and CEO, and as a director, since December 2020. Mr. Terwilliger is the company's founder
and served as its President, Chief Executive Officer and Chairman of the Board from 2001 to 2015 and continued, in a non-executive role,
to provide oil and gas prospect and operations services to the company from 2015 until his appointment as an officer in 2020. Mr. Terwilliger
has more than 40 years' experience in oil and gas management and operations.

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

 Item
 11.

 Executive
 Compensation

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

 Item
 12.

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

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

 Equity
compensation plan information is set forth in Part II, Item 5 of this Form 10-K.

 Item
 13.

 Certain
 Relationships and Related Transactions, and Director Independence

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

 Item
 14.

 Principal
 Accountant Fees and Services

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

 PART
IV

 Item
 15.

 Exhibits
 and Financial Statement Schedules

 1.

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

 2.

 Exhibits

 Exhibit

 Incorporated
 by Reference

 Filed

 Number

 Exhibit
 Description

 Form

 Date

 Number

 Herewith

 1.1

 At-the-Market Issuance Sales Agreement, dated November 18, 2022, by and between Houston American Energy Corp. and Univest Securities, LLC

 11/18/22

 1.1

 3.1

 Certificate of Incorporation of Houston American Energy Corp. filed April 2, 2001

 S-4

 08/03/01

 3.1

 3.2

 Amended and Restated Bylaws of Houston American Energy Corp. adopted June 26, 2023

 06/29/23

 3.1

 3.3

 Certificate of Amendment to the Certificate of Incorporation of Houston American Energy Corp. filed September 25, 2001

 S-4A

 10/01/01

 3.4

 3.4

 Certificate of Amendment to the Certificate of Incorporation of Houston American Energy Corp. filed July 21, 2020

 07/17/20

 3.1

 4.1

 Text of Common Stock Certificate of Houston American Energy Corp.

 S-4

 08/03/01

 4.1

 10.1

 Form of 2019 Warrant

 09/20/19

 10.3

 10.2

 Houston American Energy Corp. 2017 Equity Incentive Plan*

 Sch
 14A

 07/24/17

 Ex
 A

 10.3

 Houston American Energy Corp. 2021 Equity Incentive Plan*

 Sch
 14A

 04/28/21

 Ex
 B

 10.4

 Form of Change in Control Agreement, dated June 11, 2012*

 06/14/12

 10.1

 10.5

 Production Incentive Compensation Plan*

 08/14/13

 10.1

 14.1

 Code of Ethics for CEO and Senior Financial Officers

 10-KSB

 03/26/04

 14.1

 23.1

 Consent of Marcum, LLP

 X

 23.2

 Consent of Russell K. Hall & Associates, Inc.

 X

 31.1

 Section 302 Certification of CEO and CFO

 X

 32.1

 Section 906 Certification of CEO and CFO

 X

 97.1

 Clawback Policy

 X

 99.1

 Code of Business Ethics

 07/07/06

 99.1

 99.2

 Report of Russell K. Hall & Associates, Inc.

 X

 101.INS

 X

 101.SCH

 X

 101.CAL

 X

 101.DEF

 X

 101.LAB

 X

 101.PRE

 X

 Cover

 X

 *

 Compensatory
 plan or arrangement.

 Item
 16.

 Form
 10-K Summary

 Not
applicable

 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.

 Dated:

 By:

 /s/ John Terwilliger

 John
 Terwilliger

 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 Terwilliger

 Chief
 Executive Officer, President and Director

 John
 Terwilliger

 (Principal Executive Officer and Principal Financial Officer)

 /s/
 James Schoonover

 James
 Schoonover

 Director

 /s/ Stephen Hartzell

 Stephen
 Hartzell

 Director

 /s/ Keith Grimes

 Keith
 Grimes

 Director

TO FINANCIAL STATEMENTS

 Report of Independent Registered Public Accounting Firm (PCAOB ID Number 688)

 Consolidated Balance Sheets as of December 31, 2023 and 2022

 Consolidated Statements of Operations for the Years Ended December 31, 2023 and 2022

 Consolidated Statement of Changes in Shareholders' Equity for the Years Ended December 31, 2023 and 2022

 Consolidated Statements of Cash Flows for the Years Ended December 31, 2023 and 2022

 Notes to Consolidated Financial Statements

 F- 1

 REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 To
the Shareholders and Board of Directors of

 Houston
American Energy Corp.

 Opinion
on the Financial Statements

 We
have audited the accompanying consolidated balance sheets of Houston American Energy Corp. (the "Company") as of December
31, 2023 and 2022, the related consolidated statements of operations, shareholders' equity and cash flows for each of the years
ended December 31, 2023 and 2022, and the related notes (collectively referred to as the "financial statements"). In our
opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31,
2023 and 2022, and the results of its operations and its cash flows for each of the years ended December 31, 2023 and 2022, in conformity
with accounting principles generally accepted in the United States of America.

 Basis
for Opinion

 These
financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's
financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board
(United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 We
conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain
reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company
is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits
we are required to obtain an understanding of internal control over financial reporting 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.

 Our
audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error
or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding
the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant
estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits
provide a reasonable basis for our opinion.

 Critical
Audit Matters

 The
critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated
or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial
statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters
does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit
matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

 F- 2

 The Impact of Proved Oil and Gas
Reserves on Oil and Gas Properties

 As
described in Note 3 to the consolidated financial statements, the Company's consolidated oil and gas properties balance was $1.6
million as of December 31, 2023, and depreciation, depletion and amortization expense for the year ended December 31, 2023 was $0.2 million.
The Company utilizes the full cost method of accounting for its oil and gas properties. Under this method, all capitalized costs are
amortized over the estimated lives of the properties using the unit-of-production method based on proved oil and gas reserves. These
capitalized costs are subject to a ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of
the present value of future net revenues attributable to proved oil and gas reserves discounted at 10%. For the year ended December 31,
2023, pre-tax impairment charges of $0.5 million were recognized. As disclosed by management, proved oil and gas reserves are a major
component of the full cost ceiling test. Estimates of reserves require extensive judgments of available reservoir geologic, geophysical
and engineering data as well as certain economic assumptions such as commodity pricing. The estimates of oil and gas reserves have been
developed by a specialist, specifically a reservoir engineer (the "specialist").

 The principal considerations for our determination that performing procedures relating to the impact of proved oil
and gas reserves on oil and gas properties, is a critical audit matter are (i) the significant judgment by management, including the use
of management's specialist, when developing the estimate of proved oil and gas reserves and (ii) a high degree of auditor judgment,
subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by
management and its specialist in developing the estimates of proved oil and gas reserves applied to the full cost ceiling test.

 Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our
overall opinion on the consolidated financial statements. These procedures included testing the depreciation, depletion and amortization
and full cost ceiling test calculations. The work of management's specialist was used in performing the procedures to evaluate the
reasonableness of the estimates of proved oil and gas reserves applied in the full cost ceiling test. As a basis for using this work,
specialist's qualifications were understood and the Company's relationship with the specialist was assessed. These procedures
also included evaluating of the methods and assumptions used by the specialist, testing of the completeness and accuracy of the data related
to commodity pricing and historical production used by the specialist, and evaluating the specialist's findings.

 /s/
Marcum llp

 Marcum
LLP

 We
have served as the Company's auditor since 2010

 Houston, Texas

 April
2, 2024

 F- 3

 CONSOLIDATED
BALANCE SHEETS

 2023

 2022

 December 31,

 2023

 2022

 ASSETS

 CURRENT ASSETS

 Cash

 $
 4,059,182

 $
 4,547,210

 Accounts receivable – oil and gas sales

 71,736

 164,575

 Prepaid expenses and other current assets

 35,244

 84,544

 TOTAL CURRENT ASSETS

 4,166,162

 4,796,329

 PROPERTY AND EQUIPMENT

 Oil and gas properties, full cost method

 Costs subject to amortization

 62,776,561

 62,786,267

 Costs not being amortized

 —

 Office equipment

 90,004

 90,004

 Total

 62,866,565

 65,219,397

 Accumulated depletion, depreciation, amortization, and impairment

 ( 61,307,264
)

 ( 60,602,051
)

 PROPERTY AND EQUIPMENT, NET

 4,617,346

 Equity investment – Hupecol Meta LLC

 4,505,358

 2,102,139

 Right of use asset

 145,021

 212,202

 Other assets

 3,167

 3,167

 TOTAL ASSETS

 $
 10,379,009

 $
 11,731,183

 LIABILITIES AND SHAREHOLDERS' EQUITY

 CURRENT LIABILITIES

 Accounts payable

 $
 156,572

 $
 113,741

 Accrued expenses

 17,083

 16,035

 Short-term lease liability

 75,276

 65,385

 TOTAL CURRENT LIABILITIES

 248,931

 195,161

 LONG-TERM LIABILITIES

 Lease liability, net of current portion

 71,083

 146,359

 Reserve for plugging and abandonment costs

 63,084

 72,789

 TOTAL LONG-TERM LIABILITIES

 134,167

 219,148

 TOTAL LIABILITIES

 383,098

 414,309

 COMMITMENTS AND CONTINGENCIES

 -

 SHAREHOLDERS' EQUITY

 Common stock, par value $ 0.001; 12,000,000 shares authorized 10,906,353 and 10,327,646 shares issued and outstanding

 10,907

 10,328

 Additional paid-in capital

 86,984,001

 85,094,266

 Accumulated deficit

 ( 76,998,997
)

 ( 73,787,720
)

 TOTAL SHAREHOLDERS' EQUITY

 9,995,911

 11,316,874

 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY

 $
 10,379,009

 $
 11,731,183

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

 F- 4

 CONSOLIDATED
STATEMENTS OF OPERATIONS

 FOR
THE YEARS ENDED DECEMBER 31, 2023 AND 2022

 2023

 2022

 REVENUES

 Oil and gas revenue

 $

 $

 Total operating revenue

 EXPENSES OF OPERATIONS

 Lease operating expense and severance tax

 General and administrative expense

 1,852,559

 1,580,270

 Depreciation and depletion

 167,527

 205,458

 Loss on disposal of oil and gas properties – Colombia

 —

 Impairment expense

 537,686

 —

 Total operating expenses

 5,374,823

 2,416,761

 Loss from operations

 ( 4,580,796
)

 ( 777,920
)

 OTHER INCOME

 Interest income

 148,565

 33,641

 Other income

 1,220,954

 —

 Total other income

 1,369,519

 33,641

 Net loss before taxes

)

)

 Income tax expense (benefit)

 —

 —

 Net loss

 $
)

 $
)

 Basic net loss per common share outstanding

 $
 ( 0.30
)

 $
 ( 0.07
)

 Diluted net loss per common share outstanding

 $
 ( 0.30
)

 $
 ( 0.07
)

 Basic weighted average number of common shares outstanding

 10,783,731

 9,961,253

 Diluted weighted average number of common shares outstanding

 10,783,731

 9,961,253

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

 F- 5

 CONSOLIDATED
STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY

 FOR
THE YEARS ENDED DECEMBER 31, 2023 and 2022

 Shares

 Amount

 Deficit

 Total

 Additional

 Common Stock

 Paid-in

 Accumulated

 Shares

 Amount

 Deficit

 Total

 Balance – December 31, 2021

 9,928,338

 $
 9,928

 $
 83,345,456

 $
 ( 73,043,441
)

 $
 10,311,943

 Issuance of common stock for cash, net

 394,678

 1,542,605

 —

 1,543,000

 Issuance of common stock on cashless exercise of option

 4,630

 ( 5
)

 —

 —

 Stock-based compensation

 —

 —

 206,210

 —

 206,210

 Net loss

 —

 —

 —

)

)

 Balance – December 31, 2022

 10,327,646

 10,328

 85,094,266

 ( 73,787,720
)

 11,316,874

 Balance

 10,327,646

 10,328

 85,094,266

 ( 73,787,720
)

 11,316,874

 Issuance of common stock for cash, net

 578,707

 1,651,421

 —

 1,652,000

 Stock-based compensation

 —

 —

 238,314

 —

 238,314

 Net loss

 —

 —

 —

)

)

 Balance – December 31, 2023

 10,906,353

 $
 10,907

 $
 86,984,001

 $
 ( 76,998,997
)

 $
 9,995,911

 Balance

 10,906,353

 $
 10,907

 $
 86,984,001

 $
 ( 76,998,997
)

 $
 9,995,911

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

 F- 6

 CONSOLIDATED
STATEMENTS OF CASH FLOWS

 FOR
THE YEARS ENDED DECEMBER 31, 2023 AND 2022

 2023

 2022

 CASH
 FLOW FROM OPERATING ACTIVITIES

 Net
 loss

 $
)

 $
)

 Adjustments
 to reconcile net loss to net cash used in operations

 Depreciation
 and depletion

 167,527

 205,458

 Impairment
 of oil and gas properties

 537,686

 —

 Loss on disposal of oil and gas properties – Colombia

 —

 Accretion
 of plugging and abandonment costs

 2,707

 4,580

 Stock-based
 compensation

 238,314

 206,210

 Amortization
 of right of use asset

 67,181

 60,305

 Change
 in operating assets and liabilities:

 Decrease/(Increase)
 in accounts receivable

 92,839

 50,087

 Decrease
 in accrued earning distributions from Hupecol Meta, LLC

 17,358

 —

 Decrease/(Increase)
 in prepaid expense and other current assets

 31,942

 Increase/(Decrease)
 in accounts payable and accrued expenses

 41,174

 53,203

 Decrease
 in operating lease liability

 ( 65,385
)

 ( 65,385
)

 Net
 cash provided by (used in) operating activities

 263,191

 ( 228,962
)

 CASH
 FLOW FROM INVESTING ACTIVITIES

 Payments
 for the acquisition and development of oil and gas properties

 —

 ( 15,045
)

 Payments
 for capital contribution for equity investment

 ( 2,403,219
)

 ( 1,646,360
)

 Net
 cash used in investing activities

 ( 2,403,219
)

 ( 1,661,405
)

 CASH
 FLOW FROM FINANCING ACTIVITIES

 Proceeds
 from issuance of common stock for cash, net of offering costs

 1,652,000

 1,543,000

 Net
 cash provided by financing activities

 1,652,000

 1,543,000

 (DECREASE)/INCREASE
 IN CASH

 ( 488,028
)

 ( 347,367
)

 Cash,
 beginning of year

 4,547,210

 4,894,577

 Cash,
 end of year

 $
 4,059,182

 $
 4,547,210

 SUPPLEMENTAL
 CASH FLOW INFORMATION:

 Interest
 paid

 $
 —

 $
 —

 Taxes
 paid

 $
 —

 $
 —

 SUPPLEMENTAL
 NON-CASH INVESTING AND FINANCING ACTIVITIES

 Change
 in asset retirement obligations, net

 $
 9,706

 $
 —

 Cashless
 exercise of stock options

 -

 $
 -
 $5

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

 F- 7

 NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS

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

 Houston
American Energy Corp. (a Delaware Corporation) ("the Company" or "HUSA") was incorporated in 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. The Company's principal properties are in the Texas Permian Basin and international holdings in Colombia, South
America, with additional holdings in Gulf Coast areas of the United States.

 Consolidation

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

 Liquidity
and Capital Requirements

 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 issuance date of these consolidated financial statements. With limited exceptions, the Company has incurred continuing losses since
2011, with an accumulated deficit of $ 77 million as of December 31, 2023.

 The
Company believes that it has the ability to fund, from cash on hand, its operating costs and anticipated drilling operations for at least
the next twelve months following the issuance of these financial statements.

 The
actual timing and number of wells drilled during 2024 and beyond will be principally controlled by the operators of the Company's
acreage, based on a number of factors, including but not limited to availability of financing, performance of existing wells on the subject
acreage, energy prices and industry condition and outlook, costs of drilling and completion services and equipment and other factors
beyond the Company's control or that of its operators.

 In
the event that the Company pursues additional acreage acquisitions or expands its drilling plans, the Company may be required to secure
additional funding beyond our resources on hand. While the Company may, among other efforts, seek additional funding from "at-the-market"
sales of common stock, and private sales of equity and debt securities, it presently has limited shares of common stock authorized for
issuance to support sales of such shares and does not have any commitments to provide additional funding, and there can be no assurance
that the Company can secure the necessary capital to fund its share of drilling, acquisition or other costs on acceptable terms or at
all. If, for any reason, the Company is unable to fund its share of drilling and completion costs, it would forego participation in one
or more of such wells. In such event, the Company may be subject to penalties or to the possible loss of some of its rights and interests
in prospects with respect to which it fails to satisfy funding obligations and it may be required to curtail operations and forego opportunities.

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.

 F- 8

 Cash
and Cash Equivalents

 Cash
and cash equivalents consist of demand deposits and cash investments with initial maturity dates of less than three months when purchased.
As of December 31, 2023 and 2022, the Company had no cash equivalents outstanding.

 Concentration
of Credit Risk

 Financial
instruments that potentially subject the Company to a concentration of credit risk include cash, cash equivalents and marketable securities
(if any). The Company had cash deposits of $ 3.7 million in excess of the FDIC's current insured limit of $ 250,000 at December 31,
2023 for interest bearing accounts. The Company also had cash deposits of $ 1,737 in Colombian banks at December 31, 2023 that are not
insured by the FDIC. The Company has not experienced any losses on its deposits of cash and cash equivalents.

 Revenue
Recognition

 ASU
2014-09, "Revenue from Contracts with Customers (Topic 606)". Topic 606 requires an entity to recognize revenue when
it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to
in exchange for those goods or services. The Company adopted Topic 606 on January 1, 2018, using the modified retrospective method applied
to contracts that were not completed as of January 1, 2018. Under the modified retrospective method, prior period financial positions
and results are not adjusted. The cumulative effect adjustment recognized in the opening balances included no significant changes as
a result of this adoption. While the Company's 2018 net earnings were not materially impacted by revenue recognition timing changes,
Topic 606 requires certain changes to the presentation of revenues and related expenses beginning January 1, 2018. Refer to Note 2 –
Revenue from Contracts with Customers for additional information.

 The
Company's revenue is comprised principally of revenue from exploration and production activities. The Company's oil is sold
primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct
end-users, industrial users, local distribution companies, and natural-gas marketers. Natural gas liquids, or NGLs, are sold primarily
to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery.

 Contracts
with customers have varying terms, including spot sales or month-to-month contracts, contracts with a finite term, and life-of-field
contracts where all production from a well or group of wells is sold to one or more customers. The Company recognizes sales revenues
for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally,
control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a
tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments
for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs.

are recognized for the sale of the Company's net share of production volumes.

 Loss
per Share

 Basic
loss per share is computed by dividing net loss available to common shareholders by the weighted average common shares outstanding for
the period. Diluted earnings per share reflects the potential dilution that could occur if securities or other contracts to issue common
shares were exercised or converted in common shares that then shared in the earnings of the Company. In periods in which the Company
reports a net loss, dilutive securities are excluded from the calculation of diluted net loss per share amounts as the effect would be
anti-dilutive.

 F- 9

 For
the years ended December 31, 2023 and 2022, the following warrants and options to purchase shares of common stock were excluded from
the computation of diluted net loss per share, as the inclusion of such shares would be anti-dilutive:

 SCHEDULE OF COMPUTATION OF DILUTED NET LOSS PER SHARE

 Year Ended December 31,

 2023

 2022

 Stock warrants

 Stock options

 1,000,807

 944,177

 Totals

 1,095,207

 1,038,577

 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's ability to collect outstanding receivables is critical to its operating performance and cashflows. Accounts receivable
are stated at an amount management expects to collect from outstanding balances. The Company extends credit in the normal course of business.
The Company regularly reviews outstanding receivables and when the Company determines that a party may not be able to make required payments,
a charge to bad debt expense in the period of determination is made. Though the Company's bad debts have not historically been
significant, the Company could experience increased bad debt expense should a financial downturn occur.

 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 $ 167,527 and $ 194,392 for the years ended December 31, 2023 and 2022, respectively,
and accumulated amortization, depreciation and impairment was $ 61,217,260 and $ 60,512,047 at December 31, 2023 and 2022, 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 2023 and 2022 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 2023 and 2022, the Company recorded
impairments of oil and gas properties totaling $ 537,686 and $ 0, respectively. The impairment reflects the decline in energy prices and
production during 2023.

 F- 10

 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.

 Office
equipment having an original cost basis of $ 90,004 was fully depreciated as of January 1, 2020. Therefore, accumulated depreciation was
$ 90,004 and $ 90,004 at December 31, 2023 and 2022, respectively.

 Equity
Investment Accounted for at Cost

 Businesses
not accounted for under either the consolidation method or equity method of accounting are accounted for under equity investments accounted for at cost
and are further discussed in Note 4, "Equity Investments Accounted for at Cost." The Company's share of the earnings and/or losses of
equity investments accounted for at cost is not included in the Consolidated Statements of Operations. Income from equity investments accounted for at cost is only realized
if and when distributions are made from the business to its investors. However, impairment charges related to businesses are recognized in the company's Consolidated Statements of Operations. If circumstances suggest that the value of an
equity investment accounted for at cost with respect to which an impairment charge has been made has subsequently recovered, that recovery is not recorded.
The carrying values of the company's equity investments accounted for at cost are reflected in the line item "Equity investment – Hupecol
Meta, LLC" in the Company's Consolidated Balance Sheets.

 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. Asset retirement obligations are classified as Level 3 (unobservable inputs) fair value measurements.

 Joint
Venture Expense

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

 F- 11

 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.

 Uncertain
Tax Positions

 The
Company evaluates uncertain tax positions to recognize a tax benefit from an uncertain tax position only if it is more likely than not
that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. Those
tax positions failing to qualify for initial recognition are recognized in the first interim period in which they meet the more likely
than not standard or are resolved through negotiation or litigation with the taxing authority, or upon expiration of the statute of limitations.
De-recognition of a tax position that was previously recognized occurs when an entity subsequently determines that a tax position no
longer meets the more likely than not threshold of being sustained.

 The
Company is subject to ongoing tax exposures, examinations and assessments in various jurisdictions. Accordingly, the Company may incur
additional tax expense based upon the outcomes of such matters, including any interest or penalties. In addition, when applicable, the
Company will adjust tax expense to reflect the Company's ongoing assessments of such matters, which require judgment and can materially
increase or decrease its effective rate as well as impact operating results. There were no liabilities recorded for uncertain tax positions
at December 31, 2023 and 2022.

 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 stock-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.

 Concentration
of Risk

 As
a non-operator oil and gas exploration and production company, and through its interest in a limited liability company ("Hupecol
Meta") and concessions operated by Hupecol Meta in the South American country of Colombia, the Company is dependent on the personnel,
management and resources of the operators of its various properties 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's Permian Basin, Texas properties accounted for all of the Company's oil and gas operations and substantially all
of its oil and gas investments reflected in its consolidated financial statements in 2023 and 2022. In the event of a significant negative
change in operations or operating outlook pertaining to the Company's Permian Basin properties, the Company may be forced to abandon
or suspend such operations, which abandonment or suspension could be materially harmful to the Company.

 Additionally,
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.

 F- 12

 For
2023, the Company's oil production from the its 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, 2023 and 2022, respectively.

 Recently
Adopted Accounting Pronouncements

 In
June 2016, the Financial Accounting Standards Board ("FASB") issued ASU No. 2016-13, Financial Instruments – Credit
Losses (Topic 326): Measurement of Credit Losses of Financial Instruments, which was codified in Accounting Standards Codification ("ASC")
326, Financial Instruments — Credit Losses ("ASC 326"). The standard changes the methodology for measuring credit losses
on financial instruments and the timing of when such losses are recorded. Because the Company is a smaller reporting company based on
the most recent determination as of November 15, 2019, ASC 326 became effective for the Company for fiscal years beginning after December
15, 2022. As such, the Company adopted ASC 326 effective January 1, 2023, utilizing the modified retrospective transition method. Upon
adoption, the Company updated its impairment model to utilize a forward-looking current expected credit losses ("CECL") model
in place of the incurred loss methodology for financial instruments measured at amortized cost, primarily including its accounts receivable
and contract asset. In relation to available-for-sale ("AFS") debt securities, the guidance eliminates the concept of "other-than-temporary"
impairment, and instead focuses on determining whether any impairment is a result of a credit loss or other factors. The adoption of
ASC 326 did not have a material impact on our unaudited condensed consolidated financial statements as of the adoption date.

 Recently
Issued Accounting Pronouncements

 In
December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires disaggregated
information about a reporting entity's effective tax rate reconciliation, as well as information related to income taxes paid to
enhance the transparency and decision usefulness of income tax disclosures. This ASU will be effective for the annual period ending December
31, 2025. The Company is currently evaluating the timing and impacts of adoption of this ASU.

 Subsequent
Events

 The
Company evaluated subsequent events for disclosure from December 31, 2023 through the date the consolidated financial statements were
issued.

 NOTE
2— REVENUE FROM CONTRACTS WITH CUSTOMERS

 Disaggregation
of Revenue from Contracts with Customers

 The
following table disaggregates revenue by significant product type for the years ended December 31, 2023 and 2022:

 SCHEDULE OF DISAGGREGATES REVENUE BY SIGNIFICANT PRODUCT

 2023

 2022

 Year Ended December 31,

 2023

 2022

 Oil sales

 $
 590,486

 $
 995,083

 Natural gas sales

 79,443

 377,534

 Natural gas liquids sales

 124,098

 266,224

 Total revenue from customers

 $

 $

 There
were no significant contract liabilities or transaction price allocations to any remaining performance obligations as of December 31,
2023 or 2022.

 NOTE
3— OIL AND GAS PROPERTIES

 Evaluated
Oil and Gas Properties

 Evaluated
oil and gas properties subject to amortization at December 31, 2023 included the following:

 SCHEDULE OF EVALUATED OIL AND GAS PROPERTIES SUBJECT TO AMORTIZATION

 Total

 Evaluated properties being amortized

 $
 13,321,589

 $
 49,444,654

 $
 62,766,243

 Accumulated depreciation, depletion, amortization and impairment

 ( 11,762,288
)

 ( 49,444,654
)

 ( 61,206,942
)

 Net capitalized costs

 $

 $
 —

 $

 Evaluated
oil and gas properties subject to amortization at December 31, 2022 included the following:

 Total

 Evaluated properties being amortized

 $
 13,331,565

 $
 49,444,654

 $
 62,776,219

 Accumulated depreciation, depletion, amortization and impairment

 ( 11,057,345
)

 ( 49,444,654
)

 ( 60,501,999
)

 Net capitalized costs

 $
 2,274,220

 $
 —

 $
 2,274,220

 F- 13

Oil and Gas Properties

oil and gas properties not subject to amortization at December 31, 2023 included the following:

 SCHEDULE OF UNEVALUATED OIL AND GAS
PROPERTIES NOT SUBJECT TO AMORTIZATION

 Total

 Leasehold acquisition costs

 $
 —

 $
 —

 $
 —

 Geological, geophysical, screening and evaluation costs

 —

 —

 —

 Total

 $
 —

 $
 —

 $
 —

oil and gas properties not subject to amortization at December 31, 2022 included the following:

 Total

 Leasehold acquisition costs

 $
 —

 $
 143,847

 $
 143,847

 Geological, geophysical, screening and evaluation costs

 —

 2,199,279

 2,199,279

 Total

 $
 —

 $

 $

2023, the Company invested $ 2,403,219, consisting of additional investments in Hupecol Meta, reflected in the cost method investment
on the Company's balance sheet. During 2022, the Company invested $ 1,661,405 for the acquisition and development of oil and gas
properties, consisting of (1) drilling and development operations in the U.S. Permian Basin ($ 15,045) which have been classified as oil
and gas properties subject to amortization, and (2) acquisition of additional interest in Hupecol Meta ($ 657,638) and direct investments
in Hupecol Meta relating to drilling operations in Colombia ($ 988,722). Of the amount invested, the Company capitalized $ 15,045 to oil
and gas properties subject to amortization and capitalized $ 1,646,360 as additional investment in Hupecol Meta, reflected in the cost
method investment on the Company's balance sheet. See Note 4 — Cost Method Investment for additional information on
the Company's investment in Hupecol Meta.

 Impairments and Loss on Disposal of Unevaluated Oil and Gas Properties

2023, the Company realized a full cost ceiling test impairment of $ 537,686 and a loss on disposal of oil and gas properties of $ 2,343,126.
The impairment was attributable to declines in energy prices and production relating to the Company's Reeves County properties.
The loss on disposal of oil and gas properties was attributable to the release the Company's interest in certain properties in
Colombia.

 NOTE
4— Equity Investment Accounted for at Cost

the year ended December 31, 2023, the Company received distributions, totaling $1,220,954, from Hupecol Meta representing the Company's
share of distributable net profits. During 2023, the Company invested $2,403,219 for required capital contributions related to drilling
operations in Colombia to Hupecol Meta.

 The
Company's carrying value of its holdings in Hupecol Meta, was $ 4.5 million and $ 2.1 million as of December 31, 2023 and
2022, respectively, as reflected in the line item "Equity investment – Hupecol Meta" in the Company's consolidated
balance sheets.

 Impairments

 The
Company performs annual business reviews of its equity investments accounted for at cost to determine whether the carrying value in
that investment is impaired. The Company determined its carrying value in its cost method business was not impaired during the years
ended December 31, 2023 and 2022.

 F- 14

 NOTE
5— ASSET RETIREMENT OBLIGATIONS

 The
following table describes changes in our asset retirement liability ("ARO") during each of the years ended December 31, 2023
and 2022.

 SCHEDULE OF CHANGES IN OUR ASSET RETIREMENT LIABILITY

 2023

 2022

 ARO liability at January 1

 $
 72,789

 $
 68,209

 Additions from new drilling

 —

 —

 Liabilities settled

 ( 2,706
)

 —

 Changes in estimates

 ( 9,706
)

 —

 Accretion expense

 2,707

 4,580

 ARO liability at December 31

 $
 63,084

 $
 72,789

 NOTE
6— STOCK-BASED COMPENSATION

 In
2008, the Company adopted the Houston American Energy Corp. 2008 Equity Incentive Plan (the "2008 Plan"). The terms of the
2008 Plan, as amended in 2012 and 2013, allow for the issuance of up to 480,000 shares of the Company's common stock pursuant to
the grant of stock options and restricted stock.

 In
2017, the Company adopted the Houston American Energy Corp. 2017 Equity Incentive Plan (the "2017 Plan"). The terms of the
2017 Plan allow for the issuance of up to 400,000 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.

 In
2021, the Company adopted the Houston American Energy 2021 Equity Incentive Plan (the "2021 Plan" and, together with the
2008 Plan and the 2017 Plan, the "Plans"). The terms of the 2021 Plan allow for the issuance of up to 500,000 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.

 Stock
Option Activity

 In
September 2022, options to purchase an aggregate of 60,000 shares of common stock were granted to the Company's directors. The
options have a ten -year life and are exercisable at $ 3.91 per share. The options vest 20% on the date of grant and 80% nine months from
the date of grant. The grant date fair value of these stock options was $ 216,326 based on the Black-Scholes Option Pricing model with
the following parameters: (1) risk-free interest rate of 0 % based on the applicable US Treasury bill rate; (2) expected life in years
of 10; (3) expected stock volatility of 121 % based on the trading history of the Company; and (4) expected dividend yield of 0 %. The
Company determined the options qualified as 'plain vanilla' under the provisions of SAB 107 and the simplified method was
used to estimate the expected option life.

 In
June 2023, options to purchase an aggregate of 60,000 shares of the Company's common stock were granted to the Company's
directors. The options have a ten -year life and are exercisable at $ 2.09 per share, vest 20% on the date of grant and 80% ten months
from the date of grant. The grant date fair value of these stock options was $ 119,252 based on the Black-Scholes Option Pricing model
based on the following assumptions: market value of common stock on grant date – $ 2.09; risk free interest rate based on the applicable
US Treasury bill rate – 0 %; dividend yield – 0 %; volatility factor based on the trading history of the Company – 116 %;
weighted average expected life in years – 10; and expected forfeiture rate – 0 %.

 F- 15

 Option
activity during 2023 and 2022 was as follows:

 SUMMARY OF STOCK OPTION ACTIVITY

 Options

 Weighted Average

 Exercise Price

 Weighted

 Average
 Remaining

 Contractual

 Term (in Years)

 Aggregate

Intrinsic Value

 Outstanding at December 31, 2021

 990,177

 $
 3.38

 Granted

 60,000

 $
 3.91

 Exercised

 ( 48,000
)

 $
 3.84

 Forfeited

 ( 58,000
)

 $
 20.43

 Outstanding at December 31, 2022

 944,177

 2.08

 Granted

 60,000

 2.09

 Exercised

 —

 Expired

 ( 3,370
)

 3.85

 Outstanding at December 31, 2023

 1,000,807

 $
 2.46

 5.33

 $
 107,640

 Exercisable at December 31, 2023

 955,481

 $
 2.44

 5.58

 $
 107,640

 As
of December 31, 2023, non-vested options totaled 48,000 and total unrecognized stock-based compensation expense related to non-vested
stock options was $ 50,670. The related unrecognized expense is expected to be recognized over a weighted average period of 0.24 years.
The weighted average remaining contractual term of the outstanding options and exercisable options at December 31, 2023 is 5.33 years
and 5.58 years, respectively.

 As
of December 31, 2023, there were 121,333 shares of common stock available for issuance pursuant to future stock or option grants under
the Plans.

 Stock-Based
Compensation Expense

 The
following table reflects stock-based compensation recorded by the Company for 2023 and 2022:

 SCHEDULE OF STOCK-BASED COMPENSATION

 2023

 2022

 Stock-based compensation expense from stock options and common stock included in general and administrative expense

 $
 238,314

 $
 206,210

 Earnings per share effect of stock-based compensation expense

 $
 ( 0.02
)

 $
 ( 0.02
)

 NOTE
7— CAPITAL STOCK

 Common
Stock - At-the-Market Offerings

 In
November 2022, the Company entered into an At-the-Market Sales Agreement (the "Sales Agreement") with Univest Securities,
LLC) ("Univest") pursuant to which the Company could sell (the "2022 ATM Offering"), at its option, up to an
aggregate of $ 3.5 million in shares of its common stock through Univest, as sales agent. Sales of shares under the Sales Agreement (the
"2022 ATM Offering") were made, in accordance with placement notices delivered to Univest, which notices set parameters under
which shares could be sold. The 2022 ATM Offering was made pursuant to a shelf registration statement by methods deemed to be "at
the market," as defined in Rule 415 promulgated under the Securities Act of 1933. The Company paid Univest a commission in cash
equal to 3 % of the gross proceeds from the sale of shares in the 2022 ATM Offering. The Company reimbursed Univest for $ 25,000 of expenses
incurred in connection with the 2022 ATM Offering.

 In
2022, the Company sold an aggregate of 394,678 shares in connection with the 2022 ATM Offering and received proceeds, net of commissions
and expenses, of $ 1.5 million. In 2023, the Company sold an aggregate of 578,707 shares in connection with the 2022 ATM Offering and
received proceeds, net of commissions and expenses, of $ 1.7 million.

 F- 16

 Warrants

 Bridge
Loan Warrants. In September 2019, the Company issued the warrants in conjunction with a bridge loan. The Bridge Loan Warrants
are exercisable, for a period of ten years, expiring September 18, 2029, to purchase an aggregate of 94,400 shares of common stock of
the Company at $ 2.50 per share. The relative fair value of the warrants was determined on the date of grant at $ 144,948 using the Black
Scholes option-pricing model with the following parameters: (1) risk free interest rate of 1.80 % based on the applicable US Treasury
bill rate; (2) expected life in years of 10.0; (3) expected stock volatility of 82.9 % based on the trading history of the Company; and
(4) expected dividend yield of 0 %. The relative fair value of the warrants was recorded as debt discount on the Bridge Loan Notes and
was amortized as additional interest expense over the term of the notes.

 A
summary of warrant activity and related information for 2023 and 2022 is presented below:

 SUMMARY OF WARRANT ACTIVITY

 Warrants

 Weighted-Average
 Exercise Price

 Aggregate
 Intrinsic Value

 Outstanding at December 31, 2021

 $
 2.50

 Issued

 —

 —

 Exercised

 —

 —

 Expired

 —

 $
 —

 Outstanding at December 31, 2022

 $
 2.50

 Issued

 —

 —

 Exercised

 —

 —

 Expired

 —

 —

 Outstanding at December 31, 2023

 $
 2.50

 $
 —

 Exercisable at December 31, 2023

 $
 2.50

 $
 —

 NOTE
8— TAXES

 The
following table sets forth a reconciliation of the statutory federal income tax for the years ended December 31, 2023 and 2022.

 SCHEDULE
OF RECONCILIATION OF STATUTORY FEDERAL INCOME TAX

 2023

 2022

 Income (loss) before income taxes

 $
)

 $
)

 Income tax expense (benefit) computed at statutory rates

 $
 ( 674,368
)

 $
 ( 156,299
)

 Permanent differences, nondeductible expenses

 10,439

 Increase (decrease) in valuation allowance

 710,366

 ( 189,914
)

 State and Local Taxes

 —

 3,003

 Other adjustment

 ( 10,919
)

 369,680

 Deferred True-Up

 ( 25,088
)

 ( 33,082
)

 Tax provision

 $
 —

 $
 3,827

 Total provision

 Foreign

 $
 —

 $
 —

 Total provision (benefit)

 $
 —

 $
 3,827

 At
December 31, 2023 the Company has a federal tax loss carry forward of $ 12,365,160 and a foreign tax credit carry forward of $ 18,865,
both of which have been fully reserved.

 F- 17

 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, 2023 and 2022 are set out below.

 SIGNIFICANT
COMPONENTS OF DEFERRED TAX ASSET AND LIABILITY

 2023

 2022

 Non-Current Deferred tax assets:

 Net operating loss carry forward

 $
 12,365,160

 $
 12,912,710

 Foreign tax credit carry forward

 18,865

 27,745

 Deferred state tax

 —

 —

 Stock compensation

 470,816

 425,860

 Book in excess of tax depreciation, depletion and capitalization methods on oil and gas properties

 ( 438,337
)

 ( 3,458
)

 Other

 —

 ( 174,401
)

 ASC 842 lease standard – building lease

 ( 4
)

 Pass-through investment

 —

 —

 Total Non-Current Deferred tax assets

 12,416,785

 12,188,460

 Valuation Allowance

 ( 12,416,785
)

 ( 12,188,460
)

 Net deferred tax asset

 $
 —

 $
 —

 Schedule
of Net Operating Loss Carryforwards

 The
Company is currently subject to a three-year statute of limitation for federal tax purposes and, in general, three to four-year statute
of limitation for state tax purposes. State NOL expiration will occur beginning in 2033 and Federal NOL expiration will begin in 2032.

 Under
the Tax Cuts and Jobs Act of 2017, net operating losses incurred for tax years beginning after December 31, 2017 will have no expiration
date but utilization will be limited to 80% of taxable income. For losses generated prior to January 1, 2018, there will be no limitation
on the utilization, but there is an expiration on the carryforward of 20 years for federal tax purposes.

 The
provisions were subsequently amended further under the Coronavirus Aid, Relief, and Economic Security Act ("CARES Act") on
March 27, 2020. The CARES Act amended the net operating loss provisions in the 2017 Tax Cuts and Jobs Act ("TCJA") and allows
for the carryback of NOL's arising in the taxable years ending December 31, 2017 and before January 1, 2021, to each of the five
taxable years preceding the taxable year of the loss. Additionally, the 80 % limitation related to application of NOL's towards
current federal taxable income has been removed for taxable years prior to January 1, 2021; thereby allowing 100 % of the NOL to be applied
to federal taxable income.

 To
the best of the Company's knowledge, Hupecol Meta has made all requisite filings relative to its operations, including those in
Colombia, and that there are no know or expected tax issues, payments due, or judgments related to Hupecol Meta that would adversely
impact the Company's cost method investment therein.

 NOTE
9— COMMITMENTS AND CONTINGENCIES

 Lease
Commitment

 The
Company leases office facilities under an operating lease agreement that expires October 31, 2025. During the year ended December 31,
2023, the operating cash outflows related to operating lease liabilities were $ 87,288 and the expense for the amortization of the right
of use asset for operating leases was $ 66,741. As of December 31, 2023, the Company's operating lease had a weighted-average remaining
term of 1.83 years and a weighted average discount rate of 12 %. Below is a summary of the Company's right of use assets and liabilities
as of December 31, 2023:

 Right of use asset

 SCHEDULE OF FUTURE PAYMENTS UNDER LEASE AGREEMENT

 Year

 Amount

 2024

 $
 88,801

 2025

 75,051

 Thereafter

 —

 Total future lease payments

 163,852

 Less: imputed interest

 17,493

 Present value of future operating lease payments

 146,359

 Less: current portion of operating lease liabilities

 75,276

 Long-term operating lease liability

 $
 71,083

 F- 18

the years ended December 31, 2023 and 2022, the Company recognized operating lease expense of $ 88,644 and $ 86,644, respectively, which
is included in general and administrative expenses in the Company's consolidated statements of operations. 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.

 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

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.

Incentive Arrangements and ORRIs

 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 have adopted a Production Incentive Compensation Plan under which grant
interests in pools, which may take the form of ORRIs, to provide additional incentive identify and secure attractive oil and gas properties.

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.

 F- 19

 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.

2023, no pools were established 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.

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

 Payments
made by the Company under the Plan and ORRI's totaled $ 47,724 and $ 17,725 in 2023 and 2022, respectively. As of December 31, 2023
and 2022, the Company had accrued $ 0 and $ 0, respectively, under the Plan as accounts payable.

 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,
2023 and 2022 and long-lived assets as of December 31, 2023 and 2022 attributable to each geographical area are presented below:

 SCHEDULE
OF REVENUES AND LONG LIVED ASSETS ATTRIBUTABLE TO GEOGRAPHICAL AREA

 2023

 2022

 Long Lived

 Assets, Net

 Long Lived

 Assets, Net

 North America

 $

 $

 $

 $
 2,274,220

 —

 —

 —

 Total

 $

 $

 $

 $
 4,617,346

 F- 20

 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:

 SCHEDULE
OF OIL AND GAS REVENUES AND LEASE OPERATING EXPENSES

 2023

 2022

 North America

 $

 $

 —

 —

 $

 $

 Production Cost

 North America

 $

 $

 —

 —

 $

 $

Costs

 Capitalized
costs and accumulated depletion relating to the Company's oil and gas producing activities as of December 31, 2023, all of which
are onshore properties located in the United States and Colombia, South America are summarized below:

 CAPITALIZED
COSTS AND ACCUMULATED DEPLETION RELATING TO OIL AND GAS PRODUCTION ACTIVITIES

 South
 America

 Total

 Unproved properties not being amortized

 $
 —

 $
 —

 $
 —

 Proved properties being amortized

 13,321,589

 49,444,654

 62,766,243

 Accumulated depreciation, depletion, amortization and impairment

 ( 11,762,288
)

 ( 49,444,654
)

 ( 61,206,942
)

 Net capitalized costs

 $

 $
 —

 $

 Amortization
Rate

 The
amortization rate per unit based on barrel of oil equivalents was $ 9.56 for the United States for the year ended December 31, 2023.

 Acquisition,
Exploration and Development Costs Incurred

 Costs
incurred in oil and gas property acquisition, exploration and development activities as of December 31, 2023 and 2022 are summarized
below:

 COSTS
INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES

 2023

 Property acquisition costs:

 $
 —

 $
 —

 Unproved

 Exploration costs

 —

 —

 Development costs

 —

 —

 Total costs incurred

 $
 —

 $
 —

 2022

 Property acquisition costs:

 $
 —

 $
 —

 Unproved

 —

 —

 Exploration costs

 —

 —

 Development costs

 15,045

 —

 Total costs incurred

 $
 15,045

 $
 —

 F- 21

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

 The
unaudited supplemental information on oil and gas exploration and production activities has been presented in accordance with reserve
estimation and disclosures rules issued by the SEC in 2008. Under those rules, average first-day-of-the-month price during the 12-month
period before the end of the year are 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. 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.

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 Russell K. Hall and Associates, Inc. ("R.K. Hall"), utilizing reserve
definitions and pricing requirements prescribed by the SEC. R.K. Hall is an independent professional engineering firm specializing in
the technical and financial evaluation of oil and gas assets. R.K. Hall's report was conducted under the direction of Russell K.
Hall, founder and President of R.K. Hall. Mr. Hall holds a BS in Mechanical Engineering from the University of Oklahoma and is a registered
professional engineer with more than 30 years of experience in reserve evaluation services. R.K. Hall and their respective employees
have no interest in the Company and were objective in determining the results of the Company's reserves.

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

 SCHEDULE OF PROVED DEVELOPED AND
UNDEVELOPED RESERVES BY PRODUCT TYPE

 Total

 Gas (mcf)

 Oil (bbls)

 Gas (mcf)

 Oil (bbls)

 Gas (mcf)

 Oil (bbls)

 Total proved reserves

 Balance December 31, 2021

 906,918

 94,551

 —

 —

 906,918

 94,551

 Revisions of prior estimates

 197,137

 ( 346
)

 —

 —

 197,137

 ( 346
)

 ( 73,635
)

 ( 10,688
)

 —

 —

 ( 73,635
)

 ( 10,688
)

 Balance December 31, 2022

 1,030,420

 83,517

 —

 —

 1,030,420

 83,517

 Revisions to prior estimates

 ( 365,414
)

 ( 16,947
)

 —

 —

 ( 365,414
)

 ( 16,947
)

 ( 57,360
)

 ( 7,971
)

 —

 —

 ( 57,360
)

 ( 7,971
)

 Balance December 31, 2023

 —

 —

 Proved developed reserves

 at December 31, 2022

 1,030,420

 83,517

 —

 —

 1,030,420

 83,517

 at December 31, 2023

 —

 —

 Proved undeveloped reserves

 at December 31, 2022

 —

 —

 —

 —

 —

 —

 at December 31, 2023

 —

 —

 —

 —

 —

 —

 F- 22

 As
of December 31, 2023 and 2022, the Company had no proved undeveloped ("PUD") reserves.

 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, 2023:

 STANDARDIZED
MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

 Total

 Future cash flows from sales of oil and gas

 $
 6,509,498

 $
 —

 $
 6,509,498

 Future production cost

 ( 3,804,439
)

 —

 ( 3,804,439
)

 Future development cost

 —

 —

 —

 Future net cash flows

 2,705,059

 —

 2,705,059

 10% annual discount for timing of cash flow

 ( 1,140,335
)

 —

 ( 1,140,335
)

 Standardized measure of discounted future net cash flow relating to proved oil and gas reserves

 $

 $
 —

 $

 Changes in standardized measure:

 Change due to current year operations

 Sales, net of production costs

 $
 ( 196,003
)

 $
 —

 $
 ( 196,003
)

 Change due to revisions in standardized variables:

 Accretion of discount

 516,316

 —

 516,316

 Net change in sales and transfer price, net of production costs

 ( 3,117,105

)

 —

 ( 3,117,105
)

 Net change in future development cost

 —

 —

 —

 Discoveries

 —

 —

 —

 Revision and others

 ( 645,668

)

 —

 ( 645,668
)

 Changes in production rates and other

 ( 155,975

)

 —

 ( 155,975

)

 Net

)

 —

)

 Beginning of year

 —

 End of year

 $

 $
 —

 $

 F- 23

 Standardized
measure of discounted future net cash flows at December 31, 2022:

 United
 States

 South
 America

 Total

 Future cash flows from sales of oil and gas

 $
 16,451,375

 $
 —

 $
 16,451,375

 Future production cost

 ( 5,918,092
)

 —

 ( 5,918,092
)

 Future development cost

 —

 —

 —

 Future net cash flows

 10,533,283

 —

 10,533,283

 10% annual discount for timing of cash flow

 ( 5,370,124
)

 —

 ( 5,370,124
)

 Standardized measure of discounted future net cash flow relating to proved oil and gas reserves

 $

 $
 —

 $

 Changes in standardized measure:

 Change due to current year operations

 Sales, net of production costs

 $
 ( 1,007,808
)

 $
 —

 $
 ( 1,007,808
)

 Change due to revisions in standardized variables:

 Accretion of discount

 338,098

 —

 338,098

 Net change in sales and transfer price, net of production costs

 1,876,949

 —

 1,876,949

 Net change in future development cost

 —

 —

 —

 Discoveries

 —

 —

 —

 Revision and others

 691,609

 —

 691,609

 Changes in production rates and other

 ( 116,667
)

 —

 ( 116,667
)

 Net

 1,782,181

 —

 1,782,181

 Beginning of year

 3,380,978

 —

 3,380,978

 End of year

 $

 $
 —

 $

 F- 24