Abundia Global Impact Group, Inc.: Form 10-K/A for the period ended Dec 31, 2024

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.

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

(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.

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:

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.

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).

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:

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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:

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.

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.

(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.

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 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.

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.

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.

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 (http://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.

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.

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.

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.

Oil and Gas Operating Risks

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

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

• delays imposed by or resulting from compliance with regulatory requirements;
• pressure or irregularities in geological formations;
• shortages of or delays in obtaining equipment and qualified personnel;
• equipment failures or accidents;
• adverse weather conditions;
• reductions in oil and natural gas prices;
• title problems; and
• limitations in the market for oil and natural gas.

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

We are dependent upon third party operators of our oil and gas properties.

Under the terms of the operating agreements related to our oil and gas properties, third parties act as the operator of each of our oil and gas wells and control the drilling and operating activities to be conducted on our properties. Therefore, we have limited control over certain decisions related to activities on our properties, which could affect our results of operations. Decisions over which we have limited control include:

• the timing and amount of capital expenditures;
• the timing of initiating the drilling and recompleting of wells;
• the extent of operating costs; and
• the level of ongoing production.

Decisions made by our operators may be different than those we would make reflecting priorities different than our priorities and may materially adversely affect our operating results and financial position, including potential declines in production and revenues from properties, declines in value of properties and lease expirations, among other potential consequences.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

Our prospects are properties on which we have identified what we believe, based on available seismic and geological information, to be indications of oil or natural gas potential. Our prospects are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require substantial seismic data processing and interpretation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

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

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

• landing the wellbore in the desired drilling zone;
• staying in the desired drilling zone while drilling horizontally through the formation;
• running casing the entire length of the wellbore; and
• being able to run tools and other equipment consistently through the horizontal wellbore.

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

• the ability to fracture stimulate the planned number of stages;
• the ability to run tools the entire length of the wellbore during completion operations; and
• The ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

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

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

Shortages or the high cost of drilling rigs, equipment, supplies or personnel, including shortages or unavailability of personnel, supplies and equipment, could delay or adversely affect our development and exploration operations. If the price of oil and natural gas increases, the demand for production equipment and personnel will likely also increase, potentially resulting, at least in the near-term, in shortages of equipment and personnel. In addition, larger producers may be more likely to secure access to such equipment by virtue of offering drilling companies more lucrative terms. In particular, high levels of horizontal drilling and hydraulic fracturing operations in the Permian Basin have, from time to time, created increased demand, and higher costs, for associated drilling and completion services, water supply, handling and disposal and access to production handling and transportation infrastructure, each of which have resulted in higher than anticipated prices with respect to our initial Reeves County wells. If we are unable to acquire access to such resources, or can obtain access only at higher prices, not only would this potentially delay our ability to convert our reserves into cash flow but could also significantly increase the cost of producing those reserves, thereby negatively impacting anticipated net income.

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

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

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

We may operate in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. This may be particularly true with respect to our Colombian acreage where infrastructure is limited or, in some cases, non-existent. Such restrictions on our ability to sell our oil or natural gas could have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.

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

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

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

We have historically been focused on development of a small number of geographically concentrated prospects. Accordingly, we lack diversification with respect to the nature and geographic location of our holdings. As a result, we are exposed to higher dependence on individual resource plays and may experience substantial losses should a single individual prospect prove unsuccessful. At December 31, 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.

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

Because a substantial percentage of our properties are unproven and/or undeveloped, we require significant capital to prove and develop such properties before they may become productive. Because of the inherent uncertainties associated with drilling for oil and gas, some of these properties may never be successfully drilled and developed to the extent that they result in positive cash flow. Even if we are successful in our drilling and development efforts, it could take several years for a significant portion of our unproven properties to be converted to positive cash flow.

We may incur substantial uninsured losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

• environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;
• abnormally pressured formations;
• mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
• fires and explosions;
• personal injuries and death; and
• natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to our company. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of a significant accident or other event that is not fully covered by insurance could have a material adverse effect on our business, results of operations or financial condition.

If oil and natural gas prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.

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

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

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

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

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

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

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

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

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

• require the acquisition of a permit before drilling commences;
• restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;
• limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
• impose substantial liabilities for pollution resulting from operations.

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

• the imposition of administrative, civil and/or criminal penalties;
• incurring investigatory or remedial obligations; and
• the imposition of injunctive relief.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Although we intend to be in compliance in all material respects with all applicable environmental laws and regulations, we cannot assure you that we will be able to comply with existing or new regulations. In addition, the risk of accidental spills, leakages or other circumstances could expose us to extensive liability.

We are unable to predict the effect of additional environmental laws and regulations that may be adopted in the future, including whether any such laws or regulations would materially adversely increase our cost of doing business or affect operations in any area.

Under certain environmental laws that impose strict, joint and several liability, we may be required to remediate our contaminated properties regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were or were not in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations. Moreover, new or modified environmental, health or safety laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. Therefore, the costs to comply with environmental, health or safety laws or regulations or the liabilities incurred in connection with them could significantly and adversely affect our business, financial condition or results of operations.

In addition, many countries as well as several states and regions of the U.S. have agreed to regulate emissions of “greenhouse gases” and have adopted policies to actively promote alternative energy “green energy” sources that are specifically designed to replace fossil fuels. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning of natural gas and oil, are greenhouse gases. Regulation of greenhouse gases could adversely impact some of our operations and “green energy” initiatives could substantially reduce demand for our products in the future.

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

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

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

International Operations Risks

Our operations in Colombia are 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.

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;

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• 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.

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.

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.”

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.

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).

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 1ST-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.

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.

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):

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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:

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:

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.

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.

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.

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.

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.