Houston American Energy (HUSA) 10-K 2024 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the Fiscal Year Ended December 31, 2024

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

For the transition period from                            to

Commission File No. 1-32955

HOUSTON AMERICAN ENERGY CORP.

(Exact name of registrant specified in its charter)

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

801 Travis Street, Suite 1425, Houston, Texas 77002

(Address of principal executive offices)(Zip code)

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

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

Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock, $0.001 par value	HUSA	NYSE American

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

None

(Title of Class)

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes ☐ No ☒

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definition of “accelerated filer,” “large accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐	Accelerated filer	☐	Non-accelerated filer	☒
Smaller reporting company	☒	Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to o § 240.10D-1(b). ☐

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant on December 31, 2024, based on the closing sales price of the registrant’s common stock on that date, was $17,666,820. 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 February 21, 2025 was 15,686,533.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company’s Proxy Statement for its 2025 Annual Meeting are incorporated by reference into Part III of this Report.

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	3
Item 1A.	Risk Factors	13
Item 1B.	Unresolved Staff Comments	23
Item 1C.	Cybersecurity	23
Item 2.	Properties	23
Item 3.	Legal Proceedings	23
Item 4.	Mine Safety Disclosures	23
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	24
Item 6.	Reserved	24
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	30
Item 8.	Financial Statements and Supplementary Data	30
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	30
Item 9A.	Controls and Procedures	30
Item 9B.	Other Information	31
Item 9C	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	31
PART III
Item 10.	Directors, Executive Officers, and Corporate Governance	31
Item 11.	Executive Compensation	32
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	32
Item 13.	Certain Relationships and Related Transactions, and Director Independence	32
Item 14.	Principal Accountant Fees and Services	32
PART IV
Item 15.	Exhibit and Financial Statement Schedules	33
Item 16.	Form 10-K Summary	34
SIGNATURES		35

2

FORWARD-LOOKING STATEMENTS

This annual report on Form 10-K contains forward-looking statements within the meaning of the federal securities laws. These forwarding-looking statements include without limitation statements regarding our expectations and beliefs about the market and industry, our goals, plans, and expectations regarding our properties and drilling activities and results, our intentions and strategies regarding future acquisitions and sales of properties, our intentions and strategies regarding the formation of strategic relationships, our beliefs regarding the future success of our properties, our expectations and beliefs regarding competition, competitors, the basis of competition and our ability to compete, our beliefs and expectations regarding our ability to hire and retain personnel, our beliefs regarding period to period results of operations, our expectations regarding revenues, our expectations regarding future growth and financial performance, our beliefs and expectations regarding the adequacy of our facilities, and our beliefs and expectations regarding our financial position, ability to finance operations and growth and the amount of financing necessary to support operations. These statements are subject to risks and uncertainties that could cause actual results and events to differ materially. See “Item 1A. Risk Factors” for a discussion of certain risk factors. We undertake no obligation to update forward-looking statements to reflect events or circumstances occurring after the date of this annual report on Form 10-K.

As used in this annual report on Form 10-K, unless the context otherwise requires, the terms “we,” “us,” “the Company,” and “Houston American” refer to Houston American Energy Corp., a Delaware corporation.

PART I

Item 1. Business

General

Houston American Energy Corp is an independent oil and gas company focused on the development, exploration, exploitation, acquisition, and production of natural gas and crude oil properties. Our principal properties, and operations, are in the U.S. Permian Basin and the South American country of Colombia. Additionally, we have properties in the Louisiana U.S. Gulf Coast region.

We focus on early identification of, and opportunistic entrance into, existing and emerging resource plays. We do not operate properties but typically seek to partner with, or invest along-side, larger operators in the development of resources or retain interests, with or without contribution on our part, in prospects identified, packaged and promoted to larger operators. By entering these plays earlier, identifying stranded blocks and partnering with, investing along-side or promoting to, larger operators, we believe we can capture larger resource potential at lower cost and minimize our exposure to drilling risks and costs and ongoing operating costs.

We, along with our partners, actively manage our resources through opportunistic acquisitions and divestitures where reserves can be identified, developed, monetized and financial resources redeployed with the objective of growing reserves, production and shareholder value.

Properties

Our exploration and development projects are focused on existing property interests 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.

3

The following table sets forth information relating to our principal properties as of December 31, 2024:

										2024 Net Production
	Net acreage		Average working interest %			Gross producing wells		Net proved reserves (boe)(1)		Oil (bbls)(1)		Natural Gas (mcf)(1)		Natural Gas Liquids (gallons)
Texas		98		6.8	%		4		159,875		5,992		53,476		159,680
Louisiana		582		23.4	%		—		—		—		—		—
Total U.S.		680		15.1	%		4		159,875		5,992		53,476		159,680
Colombia(2)		572		16	%		4		—		—		—		—
Total		1,252		16	%		8		159,875		5,992		53,476		159,680

(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.

- 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, 2024. For the year ended December 31, 2024, our production in Reeves County totaled 3,468 barrels of oil and 53,476 mcf of natural gas.

In June 2024, we participated in the drilling of six wells in the State Finkle Unit on the O’Brien Lease. All six wells are expected to commence production in March, 2025

As of December 31, 2024, no additional development or drilling operations are planned with respect to our Reeves County acreage.

Yoakum County. We hold a 15.9% average working interest, subject to a proportionate 10% back-in after payout, in an approximately 360 gross acre block in Yoakum County, Texas. Our Yoakum County acreage lies within the Midland sub-basin of the Permian Basin.

During 2019, we drilled the Frost #1H well, the first well on our Yoakum County acreage. The well was horizontally drilled, hydraulically fractured in the San Andres Formation and completed and commenced production in mid-2019. A second well on our Yoakum County acreage, the Frost #2H well, was horizontally drilled, hydraulically fractured in the San Andres Formation and completed and commenced production during the third quarter of 2020. For the year ended December 31, 2024, our production in Yoakum County totaled 2,524 barrels of oil.

As of December 31, 2024, no additional development or drilling operations are planned with respect to our Yoakum County acreage.

4

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, 2024, 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, 2024:

Property	Operator	Ownership Interest			Total Gross Acres		Total Gross Developed Acres		Gross Productive Wells
CPO-11 – Venus Exploration Area	Hupecol		16.0	%		3,573		1,332		4
Total						3,573		1,332		4

The CPO-11 concession, including the Venus Exploration Area, is located in the Llanos Basin and is owned and operated by Hupecol Meta.

CPO-11

During 2019, we acquired a two percent ownership interest in Hupecol Meta, LLC (“Hupecol Meta”). Hupecol Meta owns the 639,405 gross acre CPO-11 block in the Llanos Basin in Colombia. The CPO-11 block is comprised of the 69,128 acre Venus Exploration area and 570,277 acres which was 50% farmed out by Hupecol to Parex Resources. In 2021, Hupecol Meta increased its ownership interest in the CPO-11 block and we agreed to contribute $99,716. In 2022, we acquired additional interests in Hupecol Meta for an aggregate of $657,638. As a result of our acquisition of additional interests in 2021 and 2022, our ownership interest in Hupecol Meta was approximately 18% at December 31, 2024. Through our ownership interest in Hupecol Meta, at December 31, 2024, 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. 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, 2024, the Saturno ST1 and Venus 2A wells, both vertical wells, and the Venus 1-H and Venus 2-H ST1 wells, both horizontal wells, were on production in the Venus Exploration Area of the CPO-11 block.

Hupecol Meta has (i) proposed to relinquish approximately 62,139 gross acres within the Venus Exploration Area, decreasing its holding within that area to approximately 7,157 gross, and 1,145 net, acres; and (ii) agreed to acquire the 50% interest in the CPO-11 block farmed out to Parex Resources, which would increase Hupecol Meta’s net acreage position in the block to 91,244 acres. The relinquishment of such acreage and acquisition of the Parex interest are both subject to approval of the Colombian hydrocarbons agency, or ANH.

Our equity investment in Hupecol Meta is accounted for at cost and, accordingly, this report does not include any reserves, production and operating results of Hupecol Meta.

In late 2023, Hupecol advised that it intends to evaluate potential monetization of its assets in Colombia, including the interest in the CPO-11 block held by Hupecol Meta. Pending the outcome of Hupecol’s evaluation of, and potential efforts regarding, monetization of the CPO-11 block, we have no planned drilling operations, or other planned operations, in Colombia. There is no assurance as to the timing or outcome of Hupecol’s potential monetization of assets.

As of December 31, 2024, the Company determined it was necessary to take an impairment charge for our investment in Hupecol Meta due to indications that its earnings performance has deteriorated, and the investment is no longer viewed as viable. We determined that we are unlikely to receive any substantial amount of proceeds upon the sale of Hupecol Meta, rendering the value of the investment fully impaired.

5

Drilling Activity

The following table summarizes the number of wells drilled through Hupecol Meta, during 2024, 2023 and 2022, 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,
	2024				2023				2022
	Gross		Net		Gross		Net		Gross		Net
Development wells, completed as:
Productive		—		—		2		0.32		—		—
Non-productive		—		—		—		—		—		—
Total development wells		—		—		2		0.32		—		—
Exploratory wells, completed as:
Productive		—		—		—		—		1		0.16
Non-productive		1		0.16		—		—		1		0.16
Total exploratory wells		—		—						2		0.32

Productive wells are wells that are found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes. During 2024, the operator of the O’Brien Lease, EOG, decided to drill six new wells on the Finkle State Unit. We decided to participate in the drilling of those wells. We anticipate production from those wells to begin in March, 2025. .

Hupecol Meta drilled a well in 2024 which turned out to be non-productive. Through our investment in Hupecol Meta, we own approximately 16% of the block on which the well was drilled.

Productive Wells

Productive wells consist of producing wells and wells capable of production, including shut-in wells. A well bore with multiple completions is counted as only one well. As of December 31, 2024, we owned interests in 14 gross wells (including indirect interests in wells in Colombia through our equity interest in Hupecol Meta). As of December 31, 2024, we had interests in productive wells, categorized by geographic area, as follows:

	Oil Wells		Gas Wells
United States
Gross		10		—
Net		0.7022		—
Colombia
Gross		4		—
Net		0.64		—
Total
Gross		14		—
Net		1.3422		—

6

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, 2024, 2023, and 2022:

	Year Ended December 31,
	2024		2023		2022
Net Production:
Gas (Mcf):
United States		53,476		57,360		73,635
Colombia		—		—		—
Total		53,476		57,360		73,635
Natural Gas Liquids (Gallons)
United States		159,680		179,506		248,506
Colombia		—		—		—
Total		159,680		179,506		248,506
Oil (Bbls):
United States		5,992		7,971		10,688
Colombia		—		—		—
Total		5,992		7,971		10,688
Average sales price:
Gas ($ per Mcf)
United States	$	0.17	$	1.38	$	5.13
Colombia		—		—		—
Total	$	0.17	$	1.38	$	5.13
Natural Gas Liquids ($ per Gallon)
United States	$	0.71	$	0.69	$	1.07
Colombia		—		—		—
Total	$	0.71	$	0.69	$	1.07
Oil ($ per Bbl)
United States		73.08	$	74.08	$	93.10
Colombia		—		—		—
Total		73.08	$	74.08	$	93.10
Average production costs ($ per BOE):
United States		42.85	$	27.03	$	27.48
Colombia		—		—		—
Total		42.85	$	27.03	$	27.48

Average production costs per BOE in 2024 increased to $42.85 per BOE from $27.03 in 2023 due to inflation-related increases in expenses and workover costs incurred in early 2024 related to two of our US wells.

Natural Gas and Oil Reserves

Reserve Estimates

The following tables set forth, by country and as of December 31, 2024, 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.

7

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		Natural Gas Liquids		Total (2)
	(bbls)		(mcf)		(gal)		(boe)
Reserve category
Proved Developed Producing
United States		29,380		339,210		959,650		108,764
Colombia(3)		—		—		—		—
Total Proved Developed Producing Reserves		29,380		339,210		959,650		108,764
Proved Non-Producing
United States		17,010		78,980		502,600		42,140
Colombia(3)		—		—		—		—
Total Proved Non-Producing Reserves		17,010		78,980		502,600		42,140
Total Proved Reserves		46,390		418,190		1,462,250		150,904

	Proved Developed		Proved Non-Producing		Total Proved
PV-10 (1)	$	537,870	$	585,400	$	1,123,270
Standardized measure (4)	$	537,870	$	585,400	$	1,123,270

(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, 2024. 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, 2024. The average prices utilized for purposes of estimating our proved reserves were $71.96 per barrel of oil, $0.52 per MMBTu of natural gas, and $0.71 per gallon of natural gas liquids 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.

8

The reserves as of December 31, 2024 were determined in accordance with standard industry practices and SEC regulations by the licensed independent petroleum engineering firm. The calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry.

Our year-end reserve reports are prepared by reserve engineering firms based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geosciences and engineering data, and other information provided to them by our management team. Upon analysis and evaluation of data provided, the reserve engineering firms issue a preliminary appraisal report of our reserves. The preliminary appraisal report and changes in our reserves are reviewed by our President and board for reasonableness of the results obtained. Once any questions have been addressed, the reserve engineering firms issue final appraisal reports, reflecting their conclusions.

Russell K. Hall & Associates is an independent Midland, Texas based professional engineering firm providing reserve evaluation services to the oil and gas industry. Their report was prepared under the direction of Russell K. Hall, founder and President of Russell K. Hall & Associates. Mr. Hall holds a BS in Mechanical Engineering from the University of Oklahoma, is a registered professional engineer and a member of the Society of Petroleum Engineers, the Society of Independent Professional Earth Scientists and the West Texas Geological Society. Mr. Hall has more than 30 years of experience in reserve evaluation for the oil and gas industry and the oil and gas finance industry. Russell K. Hall & Associates, and its employees, have no interest in our company or our properties and were objective in determining our reserves.

The SEC’s rules with respect to technologies that a company can use to establish reserves allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Our reserve engineering firm used a combination of production and pressure performance, simulation studies, offset analogies, seismic data and interpretation, geophysical logs and core data to calculate our reserves estimates.

Proved Undeveloped Reserves

We had no proved undeveloped reserves at either December 31, 2023 or December 31, 2024.

Developed and Non-Producing Acreage

The following table sets forth the gross and net developed and non-producing 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, 2024:

	Developed				Non-Producing
	Gross		Net		Gross		Net
United States		3,040		98		2,485		582
Colombia		1,332		213		2,241		359
Total		4,372		311		4,726		941

Developed acreage is comprised of leased acres that are within an area spaced by or assignable to a productive well and acreage in which we hold a direct or indirect mineral interest with no potential development related lease expirations. Non-producing acreage is comprised of leased acres that are within an areas assigned to a well which is not yet producing, in which we hold a direct or indirect mineral interest.

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.

9

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, 2024, we had no contractual agreements to sell our gas and oil production and all production was sold on spot markets.

Human Capital

As of December 31, 2024, 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.

10

The environmental laws and regulations applicable to our U.S. operations include, among others, the following United States federal laws and regulations:

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

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

● Comprehensive Environmental Response, Compensation and Liability Act, which imposes liability where hazardous releases have occurred or are threatened to occur (commonly known as “Superfund”);

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

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

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

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

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

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

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

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

Although we do not operate the properties in which we hold interests, noncompliance with applicable environmental laws and regulations by the operators of our oil and gas properties could expose us, and our properties, to potential costs and liabilities associated with such environmental laws. While we exercise no oversight with respect to any of our operators, we believe that each of our operators is committed to environmental protection and compliance. However, since environmental costs and liabilities are inherent in our operations and in the operations of companies engaged in similar businesses and since regulatory requirements frequently change and may become more stringent, there can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production.

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.

11

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.

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.

12

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, 2024, had an accumulated deficit of $85,215,109. 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 our other oil and gas assets. In order to increase production and revenues, we will need to successfully drill new wells on our existing 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, 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.

13

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. Our available funds as of February 2025 are expected to be adequate to fund our share of current existing well expenses. However, 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.

14

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 February 2025, we had authority to issue a total of 20 million shares of common stock, of which approximately 16 million shares had been issued and 1 million shares were reserved for issuance pursuant to outstanding stock options and warrants.

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 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, 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 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.

15

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.

16

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.

17

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, 2024, we owned interests in 3,040 net acres and 98 net wells in the United States and, through properties owned and/or operated by Hupecol entities, 572 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 Basin. 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.

18

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.

19

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.

20

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 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.

As of December 31, 2024, the Company determined it was necessary to take an impairment charge for our investment in Hupecol Meta due to indications that its earnings performance has deteriorated, and the investment is no longer viewed as viable. We determined that we are unlikely to receive any substantial amount of proceeds upon the sale of Hupecol Meta, rendering the value of the investment fully impaired.

21

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;

22

● 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 February 20, 2025, 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.

23

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 February 21, 2025, there were approximately 873 shareholders of record of our common stock.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 2024 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)		916,987	$	2.09		87,680
Equity compensation plans not approved by security holders		—		—		—
		916,987	$	2.09		87,680

(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.

24

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

General

We are an independent energy company focused on the development, exploration, exploitation, acquisition, and production of natural gas and crude oil properties 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, 2024, 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.

Hupecol Meta has (i) proposed to relinquish approximately 62,139 gross acres within the Venus Exploration Area, decreasing its holding within that area to approximately 7,157 gross, and 1,145 net, acres; and (ii) agreed to acquire the 50% interest in the CPO-11 block farmed out to Parex Resources, which would increase Hupecol Meta’s net acreage position in the block to 91,244 acres. The relinquishment of such acreage and acquisition of the Parex interest are both subject to approval of the Colombian hydrocarbons agency, or ANH.

As of December 31, 2024, the company determined it was necessary to take an impairment charge for our investment in Hupecol Meta due to indications that its earnings performance has deteriorated, and the investment is no longer viewed as viable. We determined that we are unlikely to receive any substantial amount of proceeds upon the sale of Hupecol Meta, rendering the value of the investment fully impaired.

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

25

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, 2024, Hupecol Meta had 4 wells on production.

United States. During 2023, we drilled no wells on our U.S. properties. During 2024, the operator of the O’Brien Lease, EOG, decided to drill six new wells on the Finkle State Unit. We decided to participate in the drilling of those wells. We anticipate production from those wells to begin in the second quarter of 2025.

At December 31, 2024, we had 4 wells on production in the U.S. Permian Basin.

Capital Investments

During 2024, our capital investment expenditures for acreage acquisitions, drilling, completion and related operations, as well as investments relating to Hupecol Meta, totaled $1,887,516, all of which was attributable to direct investments in Hupecol Meta to fund our share of drilling and operating costs.

Distributions from Equity Investment

During 2024, we received distributions, totaling $922,719, from Hupecol Meta, representing our share of distributable net income and reflected as “Other Income” on our Statement of Operations.

Impairment of Hupecol Meta Investment

Hupecol 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 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.

As of December 31, 2024, the Company determined it was necessary to take an impairment charge for our investment in Hupecol Meta due to indications that its earnings performance has deteriorated, and the investment is no longer viewed as viable. We determined that we are unlikely to receive any substantial amount of proceeds upon the sale of Hupecol Meta, rendering the value of the investment fully impaired.

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.

During 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.

In 2024, we sold 2,180,180 shares of our common stock in a private placement for net proceeds of $2,325,000.

In January 2025, we sold 2,600,000 shares of our common stock in a registered direct offering for net proceeds of $3,897,000.

26

Executive Compensation Changes

In November 2024, we entered into an agreement with John Terwilliger, our then Chief Executive Officer, to pay Mr. Terwilliger $800,000 in exchange for terminating his change of control agreement with the Company. Mr. Terwilliger retired as a director on December 31, 2025 and remains an advisor to the Company for $2,500 per month.

Impairment Charge

During 2024, we incurred an impairment charge of $6,668,634. The impairment charge was attributable to the conclusion to write down our investment in Hupecol Meta ($6,392,874) and impairment of our US assets ($275,760) attributable to declines in energy prices and production relating to our Reeves County properties, partially offset by our proved non-producing properties.

Planned Acquisitions

On December 12, 2024, the Company entered into two non-binding letters of intent relating to the acquisition of Abundia Global Impact Group, LLC (“AGIG”) and RPD Technologies, LLC (“RPD”).

On February 20, 2025, the Company entered into a Share Exchange Agreement with the members of Abundia Global Impact Group, LLC (“AGIG”). In the Share Exchange Agreement, the Company has agreed to issue to the members of AGIG a number of shares of our common stock equal to 94% of the Company’s issued and outstanding shares (after taking into account such issuance). As a result of entering into the Share Exchange Agreement, we will acquire all of the issued and outstanding units of AGIG, and AGIG will become a wholly-owned subsidiary of the Company. Under the Share Exchange Agreement, the Company is obligated to obtain shareholder approval for the amendment of our Certificate of Incorporation to increase the number of authorized shares of common stock to 300,000,000 shares and for the issuance of approximately 246,000,000 shares to the members of AGIG. The Company expects the AGIG acquisition to close early in the second quarter. The acquisition is subject to shareholder approval and standard closing conditions.

On February 7, 2025, the Company amended the non-binding letter of intent for the acquisition of RPD. Under the amended letter of intent, the Company will acquire all of the assets of RPD. Upon entering into this letter of intent, the Company paid RPD a refundable deposit of $160,000, which will be applied toward the purchase price. The Company expects the RPD acquisition to close in the second quarter.

As a result of the AGIG and RPD transactions, the Company will focus on developing a production plant for plastics and petrochemicals in the Houston area. The acquisition supports a strategy that will diversify the Company’s portfolio into the energy transition sector.

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, 2024. 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.

27

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.

The Company estimated the December 2024 revenue and related drilling expenses for two US wells. Using actual oil production results for the month, the Company used historical lease operating expenses and average price per BBL from prior months to calculate these estimates. No gas or NGL related revenue or expenses are included in the estimate.

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

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, 2024 Compared to Year Ended December 31, 2023

Oil and Gas Revenues. Total oil and gas revenues decreased 30% to $560,180 to in 2024 from $794,027 in 2023.

The decrease in revenues was attributable to (i) declines in oil production, down 18%, and gas production, down 11% from 2023 levels; and (ii) declines in average sales price of natural gas, down 99% from 2023 levels.

The following table sets forth the gross and net producing wells, net oil, natural gas liquids, and gas production volumes and average hydrocarbon sales prices for 2024 and 2023 (excluding information pertaining to Hupecol Meta):

	2024		2023
Gross producing wells		4		4
Net producing wells		0.68		0.68
Net oil production (Bbls)		5,992		7,971
Net gas production (Mcf)		53,476		57,360
Net natural gas liquids production (Gallons)		159,680		179,506
Oil—Average sales price per barrel	$	73.08	$	74.08
Gas—Average sales price per mcf	$	0.17	$	1.38
Natural gas liquids—Average sales price per gallon	$	0.71	$	0.69

28

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 2024 and 2023, by region (excluding information pertaining to Hupecol Meta), were as follows:

	Colombia		U.S.		Total
2024
Oil sales	$	—	$	473,900	$	473,900
Gas sales	$	—	$	8,869	$	8,869
Gas Liquids sales	$	—	$	113,411	$	113,411
2023
Oil sales	$	—	$	590,486	$	590,586
Gas sales	$	—	$	79,443	$	79,443
Gas Liquids sales	$	—	$	124,098	$	124,098

Lease Operating Expenses. Lease operating expenses, excluding expenses attributable to our cost method investment in Colombia, increased 24% to $747,559 in 2024 from $473,925 in 2023.

Lease operating expense, by region, for 2024 and 2023 (excluding information pertaining to Hupecol Meta), were as follows:

	Colombia		U.S.		Total
2024	$	—	$	747,559	$	747,559
2023	$	—	$	473,925	$	473,925

The change in lease operating expenses was principally attributable to the increased expenses in production during 2024 and approximately $125,000 related to the six new wells in development.

Depreciation and Depletion Expense. Depreciation and depletion expense decreased by 5% to $160,001 in 2024 from $167,527 in 2023. The decrease in depreciation and depletion during 2024 was attributable to the increase in the depletion rate during 2024 due to the naturally occurring reduction in reserves which is used in the calculation. .

Impairment Expense and Loss on Disposal of Oil and Gas Properties. During 2024, we realized an impairment expense of $6,392,874 on our investment in Hupecol Meta attributable to indications that its earnings performance has deteriorated, and the investment is no longer viewed as viable. An additional $275,760 impairment on the US properties was realized in 2024, attributable to declines in energy prices and production relating to our Reeves County properties, partially offset by the addition of our proved non-producing properties . The loss on disposal of oil and gas properties in 2023 for 2,343,126 was attributable to the release of our interest in properties in Colombia.

General and Administrative Expenses (Excluding Stock-Based Compensation). General and administrative expense increased by 32% to $2,123,051 in 2024 from $1,614,245 in 2023. The change in general and administrative expense was primarily attributable to the payment to our former CEO to terminate his change of control agreement with the Company.

Stock-Based Compensation. Stock-based compensation decreased to $101,508 in 2024 from $238,314 in 2023. The decrease was attributable to a lower fair value of newly issued options compared to the prior period.

Other Income. Other income totaled $ 1,024,461 in 2024 compared to $1,369,518 in 2023. Other income consisted of (i) equity investment distributions from Hupecol Metal totaling $922,719 during 2024 compared to $1,220,954; and (ii) interest earned on cash balances, totaling $101,742 in 2024 and $148,565 in 2023.

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 2024 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.

29

The decrease in interest income from 2023 to 2024 was attributable to the decrease in our cash balances during 2024.

Financial Condition

Liquidity and Capital Resources. At December 31, 2024, we had a cash balance of $2,960,151 and working capital of $3,072,783, compared to a cash balance of $4,059,182 and working capital of $3,917,231 at December 31, 2023.

Cash Flows. Operating activities used cash of $1,536,515 during 2024, compared to $263,191 used during 2023. The change in cash flows from operating activities was attributable to the $800,000 payment to our former CEO.

Investing activities used cash of $1,887,516 during 2024, compared to $2,403,219 used during 2023. The decrease in cash used in investing activities is attributable to the reduced activities 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 $2,325,000 during 2024, compared to $1,652,000 provided during 2023. Cash provided by financing activities in 2024 was due to our private placement, in which we received aggregate net proceeds of $2,325,000. Cash provided by financing activities in 2023 was attributable to funds received from the sale of common stock under our 2022 ATM Offering.

Long-Term Liabilities. At December 31, 2024, we had long-term liabilities of $57,180, compared to $134,167 at December 31, 2023. Long-term liabilities, as of December 31, 2024, consisted of a reserve for plugging costs of $57,180.

Capital 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. 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.

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, 2024 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, 2024.

30

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, 2024. 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 particular with respect to technical accounting knowledge regarding accounting for certain transactions, including reserve inputs, asset retirement obligations, calculation of depreciation, depletion, and amortization, and the full cost ceiling test, 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.

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 2024 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, 2024, and their ages and positions as of that date, are as follows:

Name	Age	Position
Peter Longo	65	President, Chief Executive Officer, and CFO

Peter Longo has served as our President and CEO, and as a director, since November 2024, and principal financial officer since February 2025. Mr. Longo retired from United Technologies Corporation (UTC) in 1988 and has since been serving as the Chairman of Cyient, Inc. the U.S. subsidiary of Cyient, Ltd., a leading management services provider in engineering, manufacturing, geospatial, network, and operations management services to multi-national companies. Mr. Longo was employed at UTC since 1988. From 2016 to 2018, Mr. Longo served as SVP of Operations for UTC from prior to its merger with Raytheon Corporation (RTX). During his 30 years with UTC, Mr. Longo served as CFO and CIO at several of UTC’s business units. Neither Cyient nor RTX is affiliated with the Company. Mr. Longo has a bachelor in accountancy degree from Bentley University and is a Certified Public Accountant (CPA) since 1981.

31

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

Item 11. Executive Compensation

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

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

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

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

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

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

Item 14. Principal Accountant Fees and Services

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

32

PART IV

Item 15. Exhibits and Financial Statement Schedules

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

2. Exhibits

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Date	Number	Filed Herewith
1.1	At-the-Market Issuance Sales Agreement, dated November 18, 2022, by and between Houston American Energy Corp. and Univest Securities, LLC	8-K	11/18/22	1.1
1.2	Engagement Letter, dated October 26, 2024, by and between Houston American Energy Corp. and Univest Securities LLC	8-K	11/12/24	10.1
1.3	Subscription Agreement, dated November 8, 2024, by and between Houston American Energy Corp. and the purchaser designated on the signature page thereto	8-K	11/12/24	10.2
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	8-K	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	8-K	07/17/20	3.1
3.5	Certificate of Amendment to the Certificate of Incorporation of Houston American Energy Corp. filed October 17, 2024				X
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	8-K	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

33

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Date	Number	Filed Herewith
10.4	Form of Change in Control Agreement, dated June 11, 2012*	8-K	06/14/12	10.1
10.5	Production Incentive Compensation Plan*	10-Q	08/14/13	10.1
10.6	Agreement, dated November 11, 2024, between Houston American Energy Corp. and John Terwilliger*	8-K	11/12/24	10.3
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	8-K	07/07/06	99.1
99.2	Report of Russell K. Hall & Associates, Inc.				X
101.INS	Inline XBRL Instance Document				X
101.SCH	Inline XBRL Taxonomy Extension Schema Document				X
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document				X
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document				X
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document				X
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document				X
104	Cover Page Interactive Data File (embedded within the Inline XBRL document)				X

* Compensatory plan or arrangement.

Item 16. Form 10-K Summary

Not applicable

34

SIGNATURES

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

	HOUSTON AMERICAN ENERGY CORP.
Dated: February 21, 2025
	By:	/s/ Peter Longo
		Peter Longo
		Chief Executive Officer

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/ Peter Longo	Chief Executive Officer, President and Director	February 21, 2025
Peter Longo	(Principal Executive Officer and Principal Financial Officer)
/s/ Robert J. Bailey	Director	February 21, 2025
Robert J. Bailey
/s/ Stephen Hartzell	Director	February 21, 2025
Stephen Hartzell
/s/ Keith Grimes	Director	February 21, 2025
Keith Grimes

35

HOUSTON AMERICAN ENERGY CORP.

INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm (PCAOB ID Number 688)	F-2
Consolidated Balance Sheets as of December 31, 2024 and 2023	F-3
Consolidated Statements of Operations for the Years Ended December 31, 2024 and 2023	F-4
Consolidated Statement of Changes in Shareholders’ Equity for the Years Ended December 31, 2024 and 2023	F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2024 and 2023	F-6
Notes to Consolidated Financial Statements	F-7

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, 2024 and 2023, the related consolidated statements of operations, stockholders’ equity and cash flows for each of the years in the period ended December 31, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the years in the period ended December 31, 2024, 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.

The Impact of Proved Oil and Natural Gas Liquids 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 $1.1 million as of December 31, 2024, and depreciation, depletion and amortization expense for the year ended December 31, 2024 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, gas, and natural gas liquids (“NGL”) 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, gas, and NGL reserves discounted at 10%. For the year ended December 31, 2024, pre-tax impairment charges of $0.3 million were recognized. As disclosed by management, proved oil, gas, and NGL 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 and the costs that will be incurred in developing and producing reserves. The estimates of oil, gas, and NGL 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 NGL 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 NGL 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 NGL 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 NGL 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

February 21, 2025

F-2

HOUSTON AMERICAN ENERGY CORP.

CONSOLIDATED BALANCE SHEETS

	December 31,
	2024			2023
ASSETS
CURRENT ASSETS
Cash		2,960,151		$	4,059,182
Accounts receivable – oil and gas sales		75,074			71,736
Prepaid expenses and other current assets		175,866			35,244
TOTAL CURRENT ASSETS		3,211,091			4,166,162
PROPERTY AND EQUIPMENT
Oil and gas properties, full cost method
Costs subject to amortization		62,770,657			62,776,561
Costs not being amortized		—			—
Office equipment		90,004			90,004
Total		62,860,661			62,866,565
Accumulated depletion, depreciation, amortization, and impairment		(61,743,025	)		(61,307,264	)
PROPERTY AND EQUIPMENT, NET		1,117,636			1,559,301
Equity investment – Hupecol Meta LLC		—			4,505,358
Right of use asset		69,901			145,021
Other assets		3,167			3,167
TOTAL ASSETS		4,401,795		$	10,379,009
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable		49,542		$	156,572
Accrued expenses		17,684			17,083
Short-term lease liability		71,082			75,276
TOTAL CURRENT LIABILITIES		138,308			248,931
LONG-TERM LIABILITIES
Lease liability, net of current portion		—			71,083
Reserve for plugging and abandonment costs		57,180			63,084
TOTAL LONG-TERM LIABILITIES		57,180			134,167
TOTAL LIABILITIES		195,488			383,098
COMMITMENTS AND CONTINGENCIES		-
SHAREHOLDERS’ EQUITY
Common stock, par value $0.001; 20,000,000 shares authorized 13,086,533 and 10,906,353 shares issued and outstanding		13,087			10,907
Additional paid-in capital		89,408,329			86,984,001
Accumulated deficit		(85,215,109	)		(76,998,997	)
TOTAL SHAREHOLDERS’ EQUITY		4,206,307			9,995,911
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		4,401,795		$	10,379,009

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

F-3

HOUSTON AMERICAN ENERGY CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

FOR THE YEARS ENDED DECEMBER 31, 2024 AND 2023

	2024			2023
REVENUES
Oil and gas revenue		560,180		$	794,027
Total operating revenue		560,180			794,027
EXPENSES OF OPERATIONS
Lease operating expense and severance tax		747,559			473,925
General and administrative expense		2,224,559			1,852,559
Depreciation and depletion		160,001			167,527
Loss on disposal of oil and gas properties – Colombia		—			2,343,126
Impairment expense – oil and gas properties		275,760			537,686
Impairment expense – equity investment in Hupecol Meta LLC		6,392,874			—
Total operating expenses		9,800,753			5,374,823
Loss from operations		(9,240,573	)		(4,580,796	)
OTHER INCOME
Interest income		101,742			148,565
Other income		922,719			1,220,954
Total other income		1,024,461			1,369,519
Net loss before taxes		(8,216,112	)		(3,211,277	)
Income tax expense (benefit)		—			—
Net loss		(8,216,112	)	$	(3,211,277	)
Basic net loss per common share outstanding	$	(0.73	)	$	(0.30	)
Diluted net loss per common share outstanding	$	(0.73	)	$	(0.30	)
Basic weighted average number of common shares outstanding		11,288,019			10,783,731
Diluted weighted average number of common shares outstanding		11,288,019			10,783,731

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

F-4

HOUSTON AMERICAN ENERGY CORP.

CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2024 and 2023

	Shares		Amount		Capital		Deficit			Total
	Common Stock				Additional		Accumulated
	Shares		Amount		Paid-in Capital		Deficit			Total
Balance – December 31, 2022		10,327,646	$	10,328	$	85,094,266	$	(73,787,720	)	$	11,316,874
Issuance of common stock for cash, net		578,707		579		1,651,421		—			1,652,000
Stock-based compensation		—		—		238,314		—			238,314
Net loss		—		—		—		(3,211,277	)		(3,211,277	)
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
Issuance of common stock for cash, net		2,180,180		2,180		2,322,820		—			2,325,000
Stock-based compensation		—		—		101,508		—			101,508
Net loss		—		—		—		(8,216,112	)		(8,216,112	)
Balance – December 31, 2024		13,086,533	$	13,087	$	89,408,329	$	(85,215,109	)	$	4,206,307
Balance		13,086,533	$	13,087	$	89,408,329	$	(85,215,109	)	$	4,206,307

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

F-5

HOUSTON AMERICAN ENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2024 AND 2023

	2024			2023
CASH FLOW FROM OPERATING ACTIVITIES
Net loss	$	(8,216,112	)	$	(3,211,277	)
Adjustments to reconcile net loss to net cash used in operations
Depreciation and depletion		160,001			167,527
Impairment of oil and gas properties		275,760			537,686
Impairment of equity investment – Hupecol Meta LLC		6,392,874			—
Loss on disposal of oil and gas properties – Colombia		—			2,343,126
Accretion of plugging and abandonment costs		—			2,707
Stock-based compensation		101,508			238,314
Amortization of right of use asset		75,120			67,181
Change in operating assets and liabilities:
(Increase)/Decrease in accounts receivable		(3,338	)		92,839
Decrease in accrued earning distributions from Hupecol Meta, LLC		—			17,358
(Increase)/Decrease in prepaid expense and other current assets		(140,622	)		31,942
(Decrease)/Increase in accounts payable and accrued expenses		(106,429	)		41,174
Decrease in operating lease liability		(75,277	)		(65,385	)
Net cash (used in) provided by operating activities		(1,536,515	)		263,191
CASH FLOW FROM INVESTING ACTIVITIES
Payments for capital contribution for equity investment		(1,887,516	)		(2,403,219	)
Net cash used in investing activities		(1,887,516	)		(2,403,219	)
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from issuance of common stock for cash, net of offering costs		2,325,000			1,652,000
Net cash provided by financing activities		2,325,000			1,652,000
(DECREASE)/INCREASE IN CASH		(1,099,031	)		(488,028	)
Cash, beginning of year		4,059,182			4,547,210
Cash, end of year	$	2,960,151		$	4,059,182
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid	$	—		$	—
Taxes paid	$	—		$	—
SUPPLEMENTAL NON-CASH INVESTING AND FINANCING ACTIVITIES
Change in estimate of asset retirement obligations, net	$	5,904		$	9,706

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

F-6

HOUSTON AMERICAN ENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

General

Houston American Energy Corp. (a Delaware corporation) (“the Company” or “HUSA”) was incorporated 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 subsidiary (HAEC Louisiana 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 $85.2 million as of December 31, 2024.

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 2025 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.

General Principles and Use of Estimates

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

F-7

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, 2024 and 2023, 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 $2.5 million in excess of the FDIC’s current insured limit of $250,000 at December 31, 2024 for interest bearing accounts. The Company has not experienced any losses on its deposits of cash and cash equivalents.

Revenue Recognition

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.

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

The Company estimated the December 2024 revenue and related drilling expenses for two US wells. Using actual oil production results for the month, the Company used historical lease operating expenses and average price per BBL from prior months to calculate these estimates. No gas or NGL related revenue or expenses are included in the estimate.

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.

For the years ended December 31, 2024 and 2023, 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,
	2024		2023
Stock warrants		94,400		94,400
Stock options		916,987		1,000,807
Totals		1,011,387		1,095,207

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. 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.

F-8

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 $160,001 and $167,526 for the years ended December 31, 2024 and 2023, respectively, and accumulated amortization, depreciation and impairment was $61,743,025 and $61,217,260 at December 31, 2024 and 2023, 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 2024 and 2023 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 2024 and 2023, the Company recorded impairments of oil and gas properties totaling $275,760 and $537,686, respectively. The impairment reflects the decline in energy prices and production during 2024.

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, 2024 and 2023, 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. As of December 31, 2024, the Company determined it was necessary to take an impairment charge of $6,392,874 for its investment in Hupecol Meta due to indications that its earnings performance has deteriorated, and the investment is no longer viewed as viable. The Company determined that it is unlikely to receive any substantial amount of proceeds upon the sale of Hupecol Meta, rendering the value of the investment fully impaired.

F-9

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.

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, 2024 and 2023.

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.

F-10

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 2024. 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.

For 2024, the Company’s oil production from 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, 2024 and 2023, 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.

In accordance with Accounting Standards Updates ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), the Company applies historic loss factors to its receivable portfolio segments that were not expected to be further impacted by current economic developments, and additional economic conditions factor to portfolio segments anticipated to experience greater losses in the current economic environment. Additionally, the Company continuously evaluates customers based on risk characteristics, such as historical losses and current economic conditions. Due to the cyclical nature of the oil and gas industry, the Company often evaluates its customers’ estimated losses on a case-by-case basis. The Company did not record a provision for credit losses during the year ended December 31, 2024 or 2023. The adoption of ASC 326 did not have a material impact on our unaudited condensed consolidated financial statements as of the adoption date.

In November 2023, the FASB issued Accounting Standards Update (“ASU”) 2023-07 “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures”. The amendments in this ASU are intended to improve reportable segment disclosure requirements primarily through enhanced disclosures about significant segment expenses. The Company adopted the update for year-end 2024, but did not identify a material effect on its consolidated financial statements.

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.

F-11

Subsequent Events

The Company evaluated subsequent events for disclosure from December 31, 2024 through the date the consolidated financial statements were issued. See Note 12.

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, 2024 and 2023:

SCHEDULE OF DISAGGREGATES REVENUE BY SIGNIFICANT PRODUCT 

	2024		2023
	Year Ended December 31,
	2024		2023
Oil sales	$	437,900	$	590,486
Natural gas sales		8,869		79,443
Natural gas liquids sales		113,411		124,098
Total revenue from customers	$	560,180	$	794,027

There were no significant contract liabilities or transaction price allocations to any remaining performance obligations as of December 31, 2024 or 2023.

NOTE 3—OIL AND GAS PROPERTIES

Evaluated Oil and Gas Properties

Evaluated oil and gas properties subject to amortization at December 31, 2024 included the following:

SCHEDULE OF EVALUATED OIL AND GAS PROPERTIES SUBJECT TO AMORTIZATION  

	United States			South America			Total
Evaluated properties being amortized	$	13,326,003		$	49,444,654		$	62,770,657
Accumulated depreciation, depletion, amortization and impairment		(12,208,367	)		(49,444,654	)		(61,653,021	)
Net capitalized costs	$	1,117,636		$	—		$	1,117,636

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

	United States			South America			Total
Evaluated properties being amortized	$	13,321,907		$	49,444,654		$	62,766,561
Accumulated depreciation, depletion, amortization and impairment		(11,762,288	)		(49,444,654	)		(61,206,942	)
Net capitalized costs	$	1,559,619		$	—		$	1,559,619

Impairments

During 2024, the Company realized a full cost ceiling test impairment of $275,760. The impairment of the US assets was attributable to declines in energy prices and production relating to the Company’s Reeves County properties, partially offset by the addition of the Company’s proved non-producing properties.

NOTE 4—Equity Investment Accounted for at Cost

During the year ended December 31, 2024, the Company received distributions, totaling $922,719, from Hupecol Meta representing the Company’s share of distributable net profits. During 2024, the Company invested $1.9 million 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 as of December 31, 2023, as reflected in the line item “Equity investment – Hupecol Meta” in the Company’s consolidated balance sheets.

F-12

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. As of December 31, 2024, the Company determined it was necessary to take an impairment charge of $6,392,874 for its investment in Hupecol Meta due to indications that its earnings performance has deteriorated, and the investment is no longer viewed as viable. The Company determined that it is unlikely to receive any substantial amount of proceeds upon the sale of Hupecol Meta, rendering the value of the investment fully impaired.

NOTE 5—ASSET RETIREMENT OBLIGATIONS

The following table presents changes in our asset retirement liability (“ARO”) during each of the years ended December 31, 2024 and 2023.

SCHEDULE OF CHANGES IN OUR ASSET RETIREMENT LIABILITY  

	2024			2023
ARO liability at January 1	$	63,084		$	72,789
Additions from new drilling		—			—
Liabilities settled		—			(2,706	)
Changes in estimates		(5,904	)		(9,706	)
Accretion expense		—			2,707
ARO liability at December 31	$	57,180		$	63,084

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 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%.

In June 2024, 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 $1.21 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 $63,730 based on the Black-Scholes Option Pricing model based on the following assumptions: market value of common stock on grant date – $1.21; 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 – 97.8%; weighted average expected life in years – 10; and expected forfeiture rate – 0%.

F-13

In November 2024, the Company agreed to issue to its CEO a number of options equal to $15,000 divided by the closing price of our stock on the 15^th day of each month. The strike price of each option is equal to the grant price. The options have a ten-year life and are exercisable at $0.76 per share for the November 2024 issuances and $0.73 per share for the December 2024 issuances, 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 $14,657 in November 2024, and $13,225 in December 2024, based on the Black-Scholes Option Pricing model based on the following assumptions: market value of common stock on grant dates – $1.43 and $1.36, respectively; 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 – 92%; weighted average expected life in years – 10; and expected forfeiture rate – 0%.

Option activity during 2024 and 2023 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, 2022		944,177		$	2.08
Granted		60,000		$	2.09
Exercised		—		$	3.84
Forfeited		(3,370	)	$	20.43
Outstanding at December 31, 2023		1,000,807			2.46
Granted		82,320			1.08
Exercised		—
Expired		(166,140	)		3.87
Outstanding at December 31, 2024		916,987		$	2.06		6.10	$	16,956
Exercisable at December 31, 2024		851,131		$	2.13		5.86	$	16,956

As of December 31, 2024, non-vested options granted totaled 65,856 and total unrecognized stock-based compensation expense related to non-vested stock options was $40,790. 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, 2024 is 6.10 years and 5.86 years, respectively.

As of December 31, 2024, there were 87,680 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 2024 and 2023:

SCHEDULE OF STOCK-BASED COMPENSATION  

	2024			2023
Stock-based compensation expense from stock options and common stock included in general and administrative expense	$	101,508		$	238,314
Earnings per share effect of stock-based compensation expense	$	(0.01	)	$	(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.

During 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 $1.7 million.

In 2024, we sold 2,180,180 shares of our common stock in a private placement for net proceeds of $2.3 million.

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.

F-14

A summary of warrant activity and related information for 2024 and 2023 is presented below:

SUMMARY OF WARRANT ACTIVITY  

	Warrants		Weighted-Average Exercise Price		Aggregate Intrinsic Value
Outstanding at December 31, 2022		94,400	$	2.50
Issued		—		—
Exercised		—		—
Expired		—	$	—
Outstanding at December 31, 2023		94,400	$	2.50
Issued		—		—
Exercised		—		—
Expired		—		—
Outstanding at December 31, 2024		94,400	$	2.50	$	—
Exercisable at December 31, 2024		94,400	$	2.50	$	—

NOTE 8—TAXES

The following table sets forth a reconciliation of the statutory federal income tax for the years ended December 31, 2024 and 2023.

 SCHEDULE OF RECONCILIATION OF STATUTORY FEDERAL INCOME TAX 

	2024			2023
Income (loss) before income taxes	$	(8,216,112	)	$	(3,211,277	)
Income tax expense (benefit) computed at statutory rates	$	(1,725,727	)	$	(674,368	)
Permanent differences, nondeductible expenses		28			9
Increase (decrease) in valuation allowance		1,807,535			710,336	)
Expiration of options		32,060			—
RTA True-Ups		(227,729	)		(10,919	)
Deferred True-Up		113,833			(25,088	)
Tax provision	$	—		$	—
Total provision
Foreign	$	—		$	—
Total provision (benefit)	$	—		$	—

At December 31, 2024 the Company has a federal tax loss carry forward of $12,741,145 and a foreign tax credit carry forward of $18,865, both of which have been fully reserved. The foreign tax credit will expire in 2025.

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, 2024 and 2023 are set out below.

 SIGNIFICANT COMPONENTS OF DEFERRED TAX ASSET AND LIABILITY 

	2024			2023
Non-Current Deferred tax assets:
Net operating loss carry forward		12,729,620		$	12,355,137
Foreign tax credit carry forward		18,865			18,865
Deferred state tax		—			—
Stock compensation		460,368			470,816
Book in excess of tax depreciation, depletion and capitalization methods on oil and gas properties		1,497,253			53,720
Other		—			—
ASC 842 lease standard – building lease		248			281
Pass-through investment		—			—
Total Non-Current Deferred tax assets		14,706,354			12,898,819
Valuation Allowance		(14,706,354	)		(12,898,819	)
Net deferred tax asset		—		$	—

F-15

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. The Company files income tax returns in the U.S. federal jurisdiction, and Texas and Oklahoma state jurisdictions. 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. The federal tax years open to examination are tax years 2021, 2022, and 2023. The state tax years open to examination are tax years 2020, 2021, 2022, and 2023.

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, 2024, 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, 2024, the Company’s operating lease had a weighted-average remaining term of 0.83 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, 2024:

Right of use asset

SCHEDULE OF FUTURE PAYMENTS UNDER LEASE AGREEMENT 

Year	Amount
2025		75,051
Thereafter		—
Total future lease payments		75,051
Less: imputed interest		(3,969	)
Present value of future operating lease payments		71,082
Less: current portion of operating lease liabilities		71,082
Long-term operating lease liability	$	—

During the years ended December 31, 2024 and 2023, the Company recognized operating lease expense of $88,644 and $88,644, 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.

F-16

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

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

Production Incentive 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.

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

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

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

F-17

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

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

During 2024, 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 former Chairman and Chief Executive Officer and a former director.

Payments made by the Company under the Plan and ORRI’s totaled $42,450 and $47,724 in 2024 and 2023, respectively. As of December 31, 2024 and 2023, 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, 2024 and 2023 and long-lived assets as of December 31, 2024 and 2023 attributable to each geographical area are presented below:

 SCHEDULE OF REVENUES AND LONG LIVED ASSETS ATTRIBUTABLE TO GEOGRAPHICAL AREA 

	2024				2023
	Revenues		Long Lived Assets, Net		Revenues		Long Lived Assets, Net
North America	$	560,180	$	1,117,636	$	794,027	$	1,559,301
South America		—		—		—		—
Total	$	560,180	$	1,117,636	$	794,027	$	1,559,301

NOTE 11 — SEGMENT INFORMATION

The Company’s chief operating decision maker (“CODM”), the Chief Executive Officer, manages the Company’s business activities as a single operating and reportable segment at the consolidated level. Accordingly, our CODM uses net income to measure profit or loss, allocate resources, and assess performance. Further, the CODM is regularly provided with and utilizes consolidated functional expenses, as presented in the accompanying consolidated statements of operations, and total assets at the consolidated level, as included in the consolidated balance sheets herein, to manage the Company’s operations.

NOTE 12—SUBSEQUENT EVENTS

On February 20, 2025, the Company entered into a Share Exchange Agreement with the members of Abundia Global Impact Group, LLC (“AGIG”). In the Share Exchange Agreement, the Company has agreed to issue to the members of AGIG a number of shares of our common stock equal to 94% of the Company’s issued and outstanding shares (after taking into account such issuance). As a result of entering into the Share Exchange Agreement, we will acquire all of the issued and outstanding units of AGIG, and AGIG will become a wholly-owned subsidiary of the Company. Under the Share Exchange Agreement, the Company is obligated to obtain shareholder approval for the amendment of our Certificate of Incorporation to increase the number of authorized shares of common stock to 300,000,000 and for the issuance of approximately 246,000,000 shares to the members of AGIG. The acquisition is subject to shareholder approval and standard closing conditions.

In January 2025, the Company sold 2,600,000 shares of its common stock in a registered direct offering for net proceeds of $3,897,000.

In January 2025, the Company issued 24,202 options to its CEO and 24,202 options to a board member as compensation. In February 2025, the Company issued 10,638 options to its CEO as compensation.

NOTE 13—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 

	2024		2023
Revenues
North America	$	560,180	$	794,027
South America		—		—
	$	560,180	$	794,027
Production Cost
North America	$	747,559	$	473,925
South America		—		—
	$	747,559	$	473,925

F-18

Capital Costs

Capitalized costs and accumulated depletion relating to the Company’s oil and gas producing activities as of December 31, 2024, 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  

	United States			South America			Total
Unproved properties not being amortized	$	—		$	—		$	—
Proved properties being amortized		13,326,003			49,444,654			62,770,657
Accumulated depreciation, depletion, amortization and impairment		(12,208,367	)		(49,444,654	)		(61,653,021	)
Net capitalized costs	$	1,117,636		$	—		$	1,117,636

Amortization Rate

The amortization rate per unit based on barrel of oil equivalents was $10.75 for the United States for the year ended December 31, 2024.

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.

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

The reserve estimates set forth below were prepared by 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.

F-19

Total estimated proved developed, proved non-producing, 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  

	United States
	Gas (mcf)			Oil (bbls)			Natural Gas Liquids (gallons)
Total proved reserves
Balance December 31, 2022		1,030,420			83,517			—
Revisions of prior estimates		(365,414	)		(16,947	)		—
Production		(57,360	)		(7,719	)		—
Balance December 31, 2023		607,646			58,599			—
Extensions and discoveries		78,980			17,000			502,614
Revisions to prior estimates		(214,960	)		(23,217	)		1,119,316
Production		(53,476	)		(5,992	)		(159,680	)
Balance December 31, 2024		418,190			46,390			1,462,250
Proved developed reserves
at December 31, 2023		607,646			58,599			1,621,930
at December 31, 2024		418,190			46,390			1,462,250
Proved undeveloped reserves
at December 31, 2023		—			—			—
at December 31, 2024		—			—			—

As of December 31, 2024 and 2023, the Company had no proved undeveloped (“PUD”) reserves and no reserves outside of the United States.

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.

F-20

Standardized measure of discounted future net cash flows at December 31, 2024:

 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS 

	United States			South America		Total
Future cash flows from sales of oil and gas	$	4,427,982			—		4,427,982
Future production cost		(2,400,990	)		—		(2,400,990	)
Future development cost		(155,628	)		—		155,628
Future net cash flows		1,871,364			—		1,871,364
10% annual discount for timing of cash flow		(748,094	)		—		(748,094	)
Standardized measure of discounted future net cash flow relating to proved oil and gas reserves	$	1,123,270			—		1,123,270
Changes in standardized measure:
Change due to current year operations Sales, net of production costs	$	39,359	)		—		39,359
Sales, net of production costs	$	39,359	)		—		39,359	)
Change due to revisions in standardized variables:		—					—
Accretion of discount		156,472			—		156,472
Net change in sales and transfer price, net of production costs		(1,433,013	)		—		(1,433,013	)
Net change in future development cost		—			—		—
Discoveries		585,420			—		585,420
Revision and others		(33,056	)		—		(33,056	)
Changes in production rates and other		243,364			—		243,364
Net		(441,454	)		—		(441,454	)
Beginning of year		1,564,724			—		1,564,724
End of year	$	1,123,270			—		1,123,270

Standardized measure of discounted future net cash flows at December 31, 2023:

	United States			South America		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	$	1,564,724		$	—	$	1,564,724
Changes in standardized measure:
Change due to current year operations Sales, net of production costs	$	(196,003	)	$	—	$	(196,003	)
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		(3,598,435	)		—		(3,598,435
Beginning of year		5,163,159			—		5,163,159
End of year	$	1,564,724		$	—	$	1,564,724

F-21