Houston American Energy (HUSA) 10-K 21 Feb 25 2024 FY Annual report Financial data

Cover

Cover - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2024	Feb. 21, 2025
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Annual Report	true
Document Transition Report	false
Document Period End Date	Dec. 31, 2024
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2024
Current Fiscal Year End Date	--12-31
Entity File Number	1-32955
Entity Registrant Name	HOUSTON AMERICAN ENERGY CORP.
Entity Central Index Key	0001156041
Entity Tax Identification Number	76-0675953
Entity Incorporation, State or Country Code	DE
Entity Address, Address Line One	801 Travis Street
Entity Address, Address Line Two	Suite 1425
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	(713)
Local Phone Number	222-6966
Title of 12(b) Security	Common Stock, $0.001 par value
Trading Symbol	HUSA
Security Exchange Name	NYSEAMER
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float	$ 17,666,820
Entity Common Stock, Shares Outstanding		15,686,533
Documents Incorporated by Reference [Text Block]	Portions of the Company’s Proxy Statement for its 2025 Annual Meeting are incorporated by reference into Part III of this Report.
ICFR Auditor Attestation Flag	false
Document Financial Statement Error Correction [Flag]	false
Entity Listing, Par Value Per Share	$ 0.001
Auditor Firm ID	688
Auditor Name	Marcum LLP
Auditor Location	Houston, Texas

Consolidated Balance Sheets

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

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2024	Dec. 31, 2023
Statement of Financial Position [Abstract]
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	20,000,000	20,000,000
Common stock, shares issued	13,086,533	10,906,353
Common stock, shares outstanding	13,086,533	10,906,353

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
REVENUES
Oil and gas revenue	$ 560,180	$ 794,027
Total operating revenue	560,180	794,027
EXPENSES OF OPERATIONS
Lease operating expense and severance tax	747,559	473,925
General and administrative expense	2,224,559	1,852,559
Depreciation and depletion	160,001	167,527
Loss on disposal of oil and gas properties – Colombia		2,343,126
Impairment expense – oil and gas properties	275,760	537,686
Impairment expense – equity investment in Hupecol Meta LLC	6,392,874
Total operating expenses	9,800,753	5,374,823
Loss from operations	(9,240,573)	(4,580,796)
OTHER INCOME
Interest income	101,742	148,565
Other income	922,719	1,220,954
Total other income	1,024,461	1,369,519
Net loss before taxes	(8,216,112)	(3,211,277)
Income tax expense (benefit)
Net loss	$ (8,216,112)	$ (3,211,277)
Basic net loss per common share outstanding	$ (0.73)	$ (0.30)
Diluted net loss per common share outstanding	$ (0.73)	$ (0.30)
Basic weighted average number of common shares outstanding	11,288,019	10,783,731
Diluted weighted average number of common shares outstanding	11,288,019	10,783,731

Consolidated Statement of Chang

Consolidated Statement of Changes in Shareholders' Equity - USD ($)	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Total
Balance at Dec. 31, 2022	$ 10,328	$ 85,094,266	$ (73,787,720)	$ 11,316,874
Balance, shares at Dec. 31, 2022	10,327,646
Issuance of common stock for cash, net	$ 579	1,651,421		1,652,000
Issuance of common stock for cash, net, shares	578,707
Stock-based compensation		238,314		238,314
Net loss			(3,211,277)	(3,211,277)
Balance at Dec. 31, 2023	$ 10,907	86,984,001	(76,998,997)	9,995,911
Balance, shares at Dec. 31, 2023	10,906,353
Issuance of common stock for cash, net	$ 2,180	2,322,820		$ 2,325,000
Issuance of common stock for cash, net, shares	2,180,180			87,680
Stock-based compensation		101,508		$ 101,508
Net loss			(8,216,112)	(8,216,112)
Balance at Dec. 31, 2024	$ 13,087	$ 89,408,329	$ (85,215,109)	$ 4,206,307
Balance, shares at Dec. 31, 2024	13,086,533

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
CASH FLOW FROM OPERATING ACTIVITIES
Net loss	$ (8,216,112)	$ (3,211,277)
Adjustments to reconcile net loss to net cash used in operations
Depreciation and depletion	160,001	167,527
Impairment of oil and gas properties	275,760	537,686
Impairment of equity investment – Hupecol Meta LLC	6,392,874
Loss on disposal of oil and gas properties – Colombia		2,343,126
Accretion of plugging and abandonment costs		2,707
Stock-based compensation	101,508	238,314
Amortization of right of use asset	75,120	67,181
Change in operating assets and liabilities:
(Increase)/Decrease in accounts receivable	(3,338)	92,839
Decrease in accrued earning distributions from Hupecol Meta, LLC		17,358
(Increase)/Decrease in prepaid expense and other current assets	(140,622)	31,942
(Decrease)/Increase in accounts payable and accrued expenses	(106,429)	41,174
Decrease in operating lease liability	(75,277)	(65,385)
Net cash (used in) provided by operating activities	(1,536,515)	263,191
CASH FLOW FROM INVESTING ACTIVITIES
Payments for capital contribution for equity investment	(1,887,516)	(2,403,219)
Net cash used in investing activities	(1,887,516)	(2,403,219)
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from issuance of common stock for cash, net of offering costs	2,325,000	1,652,000
Net cash provided by financing activities	2,325,000	1,652,000
(DECREASE)/INCREASE IN CASH	(1,099,031)	(488,028)
Cash, beginning of year	4,059,182	4,547,210
Cash, end of year	2,960,151	4,059,182
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid
Taxes paid
SUPPLEMENTAL NON-CASH INVESTING AND FINANCING ACTIVITIES
Change in estimate of asset retirement obligations, net	$ 5,904	$ 9,706

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Pay vs Performance Disclosure [Table]
Net Income (Loss)	$ (8,216,112)	$ (3,211,277)

Insider Trading Arrangements

Insider Trading Arrangements	12 Months Ended
	Dec. 31, 2024
Insider Trading Arrangements [Line Items]
No Insider Trading Flag	true

Cybersecurity Risk Management a

Cybersecurity Risk Management and Strategy Disclosure	12 Months Ended
	Dec. 31, 2024
Cybersecurity Risk Management, Strategy, and Governance [Abstract]
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]	We do not 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
Cybersecurity Risk Management Processes Integrated [Flag]	false
Cybersecurity Risk Management Processes Integrated [Text Block]	We do not
Cybersecurity Risk Management Third Party Engaged [Flag]	true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]	false
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Text Block]	we do not
Cybersecurity Risk Board of Directors Oversight [Text Block]	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.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]	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.
Cybersecurity Risk Management Positions or Committees Responsible [Flag]	true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	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.
Cybersecurity Risk Board of Directors Oversight [Text Block]	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.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]	Similarly, if our officers become aware of material cybersecurity threats, they are charged with communicating the same to our audit committee.

NATURE OF COMPANY AND SUMMARY O

NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	NOTE 1— NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General Houston American Energy Corp. (a Delaware corporation) (“the Company” or “HUSA”) was incorporated in 2001. The Company is engaged, as a non-operating joint owner, in the exploration, development, and production of natural gas, crude oil, and condensate from properties. The Company’s principal properties are in the Texas Permian Basin and international holdings in Colombia, South America, with additional holdings in Gulf Coast areas of the United States. Consolidation The accompanying consolidated financial statements include all accounts of HUSA and its subsidiary (HAEC Louisiana E&P, Inc.). All significant inter-company balances and transactions have been eliminated in consolidation. Liquidity and Capital Requirements The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the issuance date of these consolidated financial statements. With limited exceptions, the Company has incurred continuing losses since 2011, with an accumulated deficit of $ 85.2 The Company believes that it has the ability to fund, from cash on hand, its operating costs and anticipated drilling operations for at least the next twelve months following the issuance of these financial statements. The actual timing and number of wells drilled during 2025 and beyond will be principally controlled by the operators of the Company’s acreage, based on a number of factors, including but not limited to availability of financing, performance of existing wells on the subject acreage, energy prices and industry condition and outlook, costs of drilling and completion services and equipment and other factors beyond the Company’s control or that of its operators. In the event that the Company pursues additional acreage acquisitions or expands its drilling plans, the Company may be required to secure additional funding beyond our resources on hand. While the Company may, among other efforts, seek additional funding from “at-the-market” sales of common stock, and private sales of equity and debt securities, it presently has limited shares of common stock authorized for issuance to support sales of such shares and does not have any commitments to provide additional funding, and there can be no assurance that the Company can secure the necessary capital to fund its share of drilling, acquisition or other costs on acceptable terms or at all. If, for any reason, the Company is unable to fund its share of drilling and completion costs, it would forego participation in one or more of such wells. In such event, the Company may be subject to penalties or to the possible loss of some of its rights and interests in prospects with respect to which it fails to satisfy funding obligations and it may be required to curtail operations and forego opportunities. General Principles and Use of Estimates The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America. In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to such potential matters as litigation, environmental liabilities, income taxes, and determination of proved reserves of oil and gas and asset retirement obligations. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates. Cash and Cash Equivalents Cash and cash equivalents consist of demand deposits and cash investments with initial maturity dates of less than three months when purchased. As of December 31, 2024 and 2023, the Company had no Concentration of Credit Risk Financial instruments that potentially subject the Company to a concentration of credit risk include cash, cash equivalents and marketable securities (if any). The Company had cash deposits of $ 2.5 250,000 Revenue Recognition The Company’s revenue is comprised principally of revenue from exploration and production activities. The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. Natural gas liquids, or NGLs, are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery. Contracts with customers have varying terms, including spot sales or month-to-month contracts, contracts with a finite term, and life-of-field contracts where all production from a well or group of wells is sold to one or more customers. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs. Revenues are recognized for the sale of the Company’s net share of production volumes. The Company estimated the December 2024 revenue and related drilling expenses for two US wells. Using actual oil production results for the month, the Company used historical lease operating expenses and average price per BBL from prior months to calculate these estimates. No gas or NGL related revenue or expenses are included in the estimate. Loss per Share Basic loss per share is computed by dividing net loss available to common shareholders by the weighted average common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted in common shares that then shared in the earnings of the Company. In periods in which the Company reports a net loss, dilutive securities are excluded from the calculation of diluted net loss per share amounts as the effect would be anti-dilutive. For the years ended December 31, 2024 and 2023, the following warrants and options to purchase shares of common stock were excluded from the computation of diluted net loss per share, as the inclusion of such shares would be anti-dilutive: SCHEDULE OF COMPUTATION OF DILUTED NET LOSS PER SHARE Year Ended December 31, 2024 2023 Stock warrants 94,400 94,400 Stock options 916,987 1,000,807 Totals 1,011,387 1,095,207 Accounts Receivable Accounts receivable – other and escrow receivables have been evaluated for collectability and are recorded at their net realizable values. Allowance for Accounts Receivable The Company’s ability to collect outstanding receivables is critical to its operating performance and cashflows. Accounts receivable are stated at an amount management expects to collect from outstanding balances. The Company extends credit in the normal course of business. The Company regularly reviews outstanding receivables and when the Company determines that a party may not be able to make required payments, a charge to bad debt expense in the period of determination is made. Though the Company’s bad debts have not historically been significant, the Company could experience increased bad debt expense should a financial downturn occur. The Company updated its impairment model to utilize a forward-looking current expected credit losses (“CECL”) model in place of the incurred loss methodology for financial instruments measured at amortized cost, primarily including its accounts receivable and contract asset. In relation to available-for-sale (“AFS”) debt securities, the guidance eliminates the concept of “other-than-temporary” impairment, and instead focuses on determining whether any impairment is a result of a credit loss or other factors. The adoption of ASC 326 did not have a material impact on our unaudited condensed consolidated financial statements as of the adoption date. Oil and Gas Properties The Company uses the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs for unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. Capitalized costs include lease acquisition, geological and geophysical work, delay rentals, costs of drilling, completing and equipping the wells and any internal costs that are directly related to acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Proceeds from the sale or other disposition of oil and gas properties are generally treated as a reduction in the capitalized costs of oil and gas properties, unless the impact of such a reduction would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. The Company categorizes its full cost pools as costs subject to amortization and costs not being amortized. The sum of net capitalized costs subject to amortization, including estimated future development and abandonment costs, are amortized using the unit-of-production method. Depletion and amortization for oil and gas properties was $ 160,001 167,526 61,743,025 61,217,260 Costs Excluded Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent costs of investments in unproved properties. The Company excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the costs subject to amortization. Ceiling Test Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X. The ceiling test determines a limit, on a country-by-country basis, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment (“DD&A”) 275,760 537,686 Furniture and Equipment Office equipment is stated at original cost and is depreciated on the straight-line basis over the useful life of the assets, which ranges from three to five years. Office equipment having an original cost basis of $ 90,004 90,004 90,004 Equity Investment Accounted for at Cost Businesses not accounted for under either the consolidation method or equity method of accounting are accounted for under equity investments accounted for at cost and are further discussed in Note 4, “Equity Investments Accounted for at Cost.” The Company’s share of the earnings and/or losses of equity investments accounted for at cost is not included in the Consolidated Statements of Operations. Income from equity investments accounted for at cost is only realized if and when distributions are made from the business to its investors. However, impairment charges related to businesses are recognized in the company’s Consolidated Statements of Operations. If circumstances suggest that the value of an equity investment accounted for at cost with respect to which an impairment charge has been made has subsequently recovered, that recovery is not recorded. The carrying values of the company’s equity investments accounted for at cost are reflected in the line item “Equity investment – Hupecol Meta, LLC” in the Company’s Consolidated Balance Sheets. As of December 31, 2024, the Company determined it was necessary to take an impairment charge of $ 6,392,874 Asset Retirement Obligations For the Company, asset retirement obligations (“ARO”) represent the systematic, monthly accretion and depreciation of future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, an adjustment is made to the full cost pool, with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. Although the Company’s domestic policy with respect to ARO is to assign depleted wells to a salvager for the assumption of abandonment obligations before the wells have reached their economic limits, the Company has estimated its future ARO obligation with respect to its domestic operations. The ARO assets, which are carried on the balance sheet as part of the full cost pool, have been included in our amortization base for the purposes of calculating depreciation, depletion and amortization expense. For the purposes of calculating the ceiling test, the future cash outflows associated with settling the ARO liability have been included in the computation of the discounted present value of estimated future net revenues. Asset retirement obligations are classified as Level 3 (unobservable inputs) fair value measurements. Income Taxes Deferred income taxes are provided on a liability method whereby deferred tax assets and liabilities are established for the difference between the financial reporting and income tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. Uncertain Tax Positions The Company evaluates uncertain tax positions to recognize a tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. Those tax positions failing to qualify for initial recognition are recognized in the first interim period in which they meet the more likely than not standard or are resolved through negotiation or litigation with the taxing authority, or upon expiration of the statute of limitations. De-recognition of a tax position that was previously recognized occurs when an entity subsequently determines that a tax position no longer meets the more likely than not threshold of being sustained. The Company is subject to ongoing tax exposures, examinations and assessments in various jurisdictions. Accordingly, the Company may incur additional tax expense based upon the outcomes of such matters, including any interest or penalties. In addition, when applicable, the Company will adjust tax expense to reflect the Company’s ongoing assessments of such matters, which require judgment and can materially increase or decrease its effective rate as well as impact operating results. There were no liabilities recorded for uncertain tax positions at December 31, 2024 and 2023. Stock-Based Compensation The Company measures the cost of employee services received in exchange for stock and stock options based on the grant date fair value of the awards. The Company determines the fair value of stock option grants using the Black-Scholes option pricing model. The Company determines the fair value of shares of non-vested stock based on the last quoted price of our stock on the date of the share grant. The fair value determined represents the cost for the award and is recognized over the vesting period during which an employee is required to provide service in exchange for the award. As stock-based compensation expense is recognized based on awards ultimately expected to vest, the Company reduces the expense for estimated forfeitures based on historical forfeiture rates. Previously recognized compensation costs may be adjusted to reflect the actual forfeiture rate for the entire award at the end of the vesting period. Excess tax benefits, if any, are recognized as an addition to paid-in capital. Concentration of Risk As a non-operator oil and gas exploration and production company, and through its interest in a limited liability company (“Hupecol Meta”) and concessions operated by Hupecol Meta in the South American country of Colombia, the Company is dependent on the personnel, management and resources of the operators of its various properties to operate efficiently and effectively. As a non-operating joint interest owner, the Company has a right of investment refusal on specific projects and the right to examine and contest its division of costs and revenues determined by the operator. The Company’s Permian Basin, Texas properties accounted for all of the Company’s oil and gas operations and substantially all of its oil and gas investments reflected in its consolidated financial statements in 2024. In the event of a significant negative change in operations or operating outlook pertaining to the Company’s Permian Basin properties, the Company may be forced to abandon or suspend such operations, which abandonment or suspension could be materially harmful to the Company. For 2024, the Company’s oil production from its mineral interests was sold to U.S. oil marketing companies based on the highest bid. The gas production is sold to U.S. natural gas marketing companies based on the highest bid. No purchaser accounted for more than 10 The Company reviews accounts receivable balances when circumstances indicate a balance may not be collectible. Based upon the Company’s review, no allowance for uncollectible accounts was deemed necessary at December 31, 2024 and 2023, respectively. Recently Adopted Accounting Pronouncements In June 2016, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses of Financial Instruments, which was codified in Accounting Standards Codification (“ASC”) 326, Financial Instruments — Credit Losses (“ASC 326”). The standard changes the methodology for measuring credit losses on financial instruments and the timing of when such losses are recorded. Because the Company is a smaller reporting company based on the most recent determination as of November 15, 2019, ASC 326 became effective for the Company for fiscal years beginning after December 15, 2022. As such, the Company adopted ASC 326 effective January 1, 2023, utilizing the modified retrospective transition method. Upon adoption, the Company updated its impairment model to utilize a forward-looking current expected credit losses (“CECL”) model in place of the incurred loss methodology for financial instruments measured at amortized cost, primarily including its accounts receivable and contract asset. In relation to available-for-sale (“AFS”) debt securities, the guidance eliminates the concept of “other-than-temporary” impairment, and instead focuses on determining whether any impairment is a result of a credit loss or other factors. In accordance with Accounting Standards Updates ASU 2016-13, Financial Instruments-Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments In November 2023, the FASB issued Accounting Standards Update (“ASU”) 2023-07 “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures”. Recently Issued Accounting Pronouncements In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires disaggregated information about a reporting entity’s effective tax rate reconciliation, as well as information related to income taxes paid to enhance the transparency and decision usefulness of income tax disclosures. This ASU will be effective for the annual period ending December 31, 2025. The Company is currently evaluating the timing and impacts of adoption of this ASU. Subsequent Events The Company evaluated subsequent events for disclosure from December 31, 2024 through the date the consolidated financial statements were issued. See Note 12.

REVENUE FROM CONTRACTS WITH CUS

REVENUE FROM CONTRACTS WITH CUSTOMERS	12 Months Ended
	Dec. 31, 2024
Revenue from Contract with Customer [Abstract]
REVENUE FROM CONTRACTS WITH CUSTOMERS	NOTE 2— REVENUE FROM CONTRACTS WITH CUSTOMERS Disaggregation of Revenue from Contracts with Customers The following table disaggregates revenue by significant product type for the years ended December 31, 2024 and 2023: SCHEDULE OF DISAGGREGATES REVENUE BY SIGNIFICANT PRODUCT 2024 2023 Year Ended December 31, 2024 2023 Oil sales $ 437,900 $ 590,486 Natural gas sales 8,869 79,443 Natural gas liquids sales 113,411 124,098 Total revenue from customers $ 560,180 $ 794,027 There were no

OIL AND GAS PROPERTIES

OIL AND GAS PROPERTIES	12 Months Ended
	Dec. 31, 2024
Extractive Industries [Abstract]
OIL AND GAS PROPERTIES	NOTE 3— OIL AND GAS PROPERTIES Evaluated Oil and Gas Properties Evaluated oil and gas properties subject to amortization at December 31, 2024 included the following: SCHEDULE OF EVALUATED OIL AND GAS PROPERTIES SUBJECT TO AMORTIZATION United States South America Total Evaluated properties being amortized $ 13,326,003 $ 49,444,654 $ 62,770,657 Accumulated depreciation, depletion, amortization and impairment (12,208,367 ) (49,444,654 ) (61,653,021 ) Net capitalized costs $ 1,117,636 $ — $ 1,117,636 Evaluated oil and gas properties subject to amortization at December 31, 2023 included the following: United States South America Total Evaluated properties being amortized $ 13,321,907 $ 49,444,654 $ 62,766,561 Accumulated depreciation, depletion, amortization and impairment (11,762,288 ) (49,444,654 ) (61,206,942 ) Net capitalized costs $ 1,559,619 $ — $ 1,559,619 Impairments During 2024, the Company realized a full cost ceiling test impairment of $ 275,760 . The impairment of the US assets was attributable to declines in energy prices and production relating to the Company’s Reeves County properties, partially offset by the addition of the Company’s proved non-producing properties

Equity Investment Accounted for

Equity Investment Accounted for at Cost	12 Months Ended
	Dec. 31, 2024
Equity Investment Accounted For At Cost
Equity Investment Accounted for at Cost	NOTE 4— Equity Investment Accounted for at Cost During the year ended December 31, 2024, the Company received distributions, totaling $ 922,719 1.9 The Company’s carrying value of its holdings in Hupecol Meta, was $ 4.5 Impairments The Company performs annual business reviews of its equity investments accounted for at cost to determine whether the carrying value in that investment is impaired. As of December 31, 2024, the Company determined it was necessary to take an impairment charge of $ 6,392,874

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2024
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	NOTE 5— ASSET RETIREMENT OBLIGATIONS The following table presents changes in our asset retirement liability (“ARO”) during each of the years ended December 31, 2024 and 2023. SCHEDULE OF CHANGES IN OUR ASSET RETIREMENT LIABILITY 2024 2023 ARO liability at January 1 $ 63,084 $ 72,789 Additions from new drilling — — Liabilities settled — (2,706 ) Changes in estimates (5,904 ) (9,706 ) Accretion expense — 2,707 ARO liability at December 31 $ 57,180 $ 63,084

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2024
Share-Based Payment Arrangement [Abstract]
STOCK-BASED COMPENSATION	NOTE 6— STOCK-BASED COMPENSATION In 2008, the Company adopted the Houston American Energy Corp. 2008 Equity Incentive Plan (the “2008 Plan”). The terms of the 2008 Plan, as amended in 2012 and 2013, allow for the issuance of up to 480,000 In 2017, the Company adopted the Houston American Energy Corp. 2017 Equity Incentive Plan (the “2017 Plan”). The terms of the 2017 Plan allow for the issuance of up to 400,000 In 2021, the Company adopted the Houston American Energy 2021 Equity Incentive Plan (the “2021 Plan” and, together with the 2008 Plan and the 2017 Plan, the “Plans”). The terms of the 2021 Plan allow for the issuance of up to 500,000 Stock Option Activity In June 2023, options to purchase an aggregate of 60,000 ten 2.09 vest 20% on the date of grant and 80% ten months from the date of grant. 119,252 2.09 0 0 116 10 0 In June 2024, options to purchase an aggregate of 60,000 ten 1.21 vest 20% on the date of grant and 80% ten months from the date of grant. 63,730 1.21 0 0 97.8 10 0 In November 2024, the Company agreed to issue to its CEO a number of options equal to $ 15,000 th ten-year 0.76 0.73 vest 20% on the date of grant and 80% ten months from the date of grant. 14,657 13,225 1.43 1.36 0 0 92 10 0 Option activity during 2024 and 2023 was as follows: SUMMARY OF STOCK OPTION ACTIVITY Options Weighted Average Exercise Price Weighted Average Remaining Contractual Term (in Years) Aggregate Intrinsic Value Outstanding at December 31, 2022 944,177 $ 2.08 Granted 60,000 $ 2.09 Exercised — $ 3.84 Forfeited (3,370 ) $ 20.43 Outstanding at December 31, 2023 1,000,807 2.46 Granted 82,320 1.08 Exercised — Expired (166,140 ) 3.87 Outstanding at December 31, 2024 916,987 $ 2.06 6.10 $ 16,956 Exercisable at December 31, 2024 851,131 $ 2.13 5.86 $ 16,956 As of December 31, 2024, non-vested options granted totaled 65,856 40,790 0.24 6.10 5.86 As of December 31, 2024, there were 87,680 Stock-Based Compensation Expense The following table reflects stock-based compensation recorded by the Company for 2024 and 2023: SCHEDULE OF STOCK-BASED COMPENSATION 2024 2023 Stock-based compensation expense from stock options and common stock included in general and administrative expense $ 101,508 $ 238,314 Earnings per share effect of stock-based compensation expense $ (0.01 ) $ (0.02 )

CAPITAL STOCK

CAPITAL STOCK	12 Months Ended
	Dec. 31, 2024
Equity [Abstract]
CAPITAL STOCK	NOTE 7— CAPITAL STOCK Common Stock - At-the-Market Offerings In November 2022, the Company entered into an At-the-Market Sales Agreement (the “Sales Agreement”) with Univest Securities, LLC) (“Univest”) pursuant to which the Company could sell (the “2022 ATM Offering”), at its option, up to an aggregate of $ 3.5 During 2023, we sold an aggregate of 578,707 1.7 In 2024, we sold 2,180,180 2.3 Warrants Bridge Loan Warrants ten years September 18, 2029 94,400 2.50 144,948 1.80 10.0 82.9 0 A summary of warrant activity and related information for 2024 and 2023 is presented below: SUMMARY OF WARRANT ACTIVITY Warrants Weighted-Average Aggregate Outstanding at December 31, 2022 94,400 $ 2.50 Issued — — Exercised — — Expired — $ — Outstanding at December 31, 2023 94,400 $ 2.50 Issued — — Exercised — — Expired — — Outstanding at December 31, 2024 94,400 $ 2.50 $ — Exercisable at December 31, 2024 94,400 $ 2.50 $ —

TAXES

TAXES	12 Months Ended
	Dec. 31, 2024
Income Tax Disclosure [Abstract]
TAXES	NOTE 8— TAXES The following table sets forth a reconciliation of the statutory federal income tax for the years ended December 31, 2024 and 2023. SCHEDULE OF RECONCILIATION OF STATUTORY FEDERAL INCOME TAX 2024 2023 Income (loss) before income taxes $ (8,216,112 ) $ (3,211,277 ) Income tax expense (benefit) computed at statutory rates $ (1,725,727 ) $ (674,368 ) Permanent differences, nondeductible expenses 28 9 Increase (decrease) in valuation allowance 1,807,535 710,336 ) Expiration of options 32,060 — RTA True-Ups (227,729 ) (10,919 ) Deferred True-Up 113,833 (25,088 ) Tax provision $ — $ — Total provision Foreign $ — $ — Total provision (benefit) $ — $ — At December 31, 2024 the Company has a federal tax loss carry forward of $ 12,741,145 18,865 The tax effects of the temporary differences between financial statement income and taxable income are recognized as a deferred tax asset and liabilities. Significant components of the deferred tax asset and liability as of December 31, 2024 and 2023 are set out below. SIGNIFICANT COMPONENTS OF DEFERRED TAX ASSET AND LIABILITY 2024 2023 Non-Current Deferred tax assets: Net operating loss carry forward 12,729,620 $ 12,355,137 Foreign tax credit carry forward 18,865 18,865 Deferred state tax — — Stock compensation 460,368 470,816 Book in excess of tax depreciation, depletion and capitalization methods on oil and gas properties 1,497,253 53,720 Other — — ASC 842 lease standard – building lease 248 281 Pass-through investment — — Total Non-Current Deferred tax assets 14,706,354 12,898,819 Valuation Allowance (14,706,354 ) (12,898,819 ) Net deferred tax asset — $ — Schedule of Net Operating Loss Carryforwards The Company is currently subject to a three-year statute of limitation for federal tax purposes and, in general, three to four-year statute of limitation for state tax purposes. State NOL expiration will occur beginning in 2033 and Federal NOL expiration will begin in 2032. The Company files income tax returns in the U.S. federal jurisdiction, and Texas and Oklahoma state jurisdictions. The Company is currently subject to a three-year statute of limitation for federal tax purposes and, in general, three to four year statute of limitation for state tax purposes. The federal tax years open to examination are tax years 2021, 2022, and 2023. The state tax years open to examination are tax years 2020, 2021, 2022, and 2023. Under the Tax Cuts and Jobs Act of 2017, net operating losses incurred for tax years beginning after December 31, 2017 will have no expiration date but utilization will be limited to 80% of taxable income. For losses generated prior to January 1, 2018, there will be no limitation on the utilization, but there is an expiration on the carryforward of 20 years for federal tax purposes. The provisions were subsequently amended further under the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) on March 27, 2020. The CARES Act amended the net operating loss provisions in the 2017 Tax Cuts and Jobs Act (“TCJA”) and allows for the carryback of NOL’s arising in the taxable years ending December 31, 2017 and before January 1, 2021, to each of the five taxable years preceding the taxable year of the loss. Additionally, the 80 100 To the best of the Company’s knowledge, Hupecol Meta has made all requisite filings relative to its operations, including those in Colombia, and that there are no know or expected tax issues, payments due, or judgments related to Hupecol Meta that would adversely impact the Company’s cost method investment therein.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	NOTE 9— COMMITMENTS AND CONTINGENCIES Lease Commitment The Company leases office facilities under an operating lease agreement that expires October 31, 2025 87,288 66,741 0.83 12 Right of use asset SCHEDULE OF FUTURE PAYMENTS UNDER LEASE AGREEMENT Year Amount 2025 75,051 Thereafter — Total future lease payments 75,051 Less: imputed interest (3,969 ) Present value of future operating lease payments 71,082 Less: current portion of operating lease liabilities 71,082 Long-term operating lease liability $ — During the years ended December 31, 2024 and 2023, the Company recognized operating lease expense of $ 88,644 88,644 Legal Contingencies The Company is subject to legal proceedings, claims and liabilities that arise in the ordinary course of its business. The Company accrues for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as further information develops or circumstances change. Environmental Contingencies The Company’s oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, incurrence of investigatory or remedial obligations or the imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require the Company to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on its results of operations, competitive position or financial condition as well as the industry in general. Under these environmental laws and regulations, the Company could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether the Company was responsible for the release or if its operations were standard in the industry at the time they were performed. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks. Development Commitments During the ordinary course of oil and gas prospect development, the Company commits to a proportionate share for the cost of acquiring mineral interests, drilling exploratory or development wells and acquiring seismic and geological information. Production Incentive Arrangements and ORRIs In conjunction with our efforts to secure oil and gas prospects, financing and services, we have, from time to time, granted overriding royalty interests (“ORRI”) in various properties and have adopted a Production Incentive Compensation Plan under which grant interests in pools, which may take the form of ORRIs, to provide additional incentive identify and secure attractive oil and gas properties. Production Incentive Compensation Plan. Under that Plan, the committee may establish one or more Pools and designate employees and consultants to participate in those Pools and designate prospects and wells, and a defined percentage of the Company’s revenues from those wells, to fund those Pools. Only prospects acquired on or after establishment of the Plan, and excluding all prospects in Colombia, may be designated to fund a Pool. The maximum percentage of the Company’s share of revenues from a well that may be designated to fund a Pool is 2 73 71 Designated participants in a Pool will be assigned a specific percentage out of the Company’s revenues assigned to the Pool and will be paid that percentage of such revenues from all wells designated to such Pool and spud during that participant’s employment or services with the Company. In no event may the percentage assigned to the Company’s chief executive officer relative to any well within a Pool exceed one-half of the applicable Pool Cap for that well. Payouts of revenues funded into Pools shall be made to participants not later than 60 days following year end, subject to the committee’s right to make partial interim payouts. Participants will continue to receive their percentage share of revenues from wells included in a Pool and spud during the term of their employment or service so long as revenues continue to be derived by the Company from those wells even after termination of employment or services of the Participant; provided, however, that a participant’s interest in all Pools shall terminate on the date of termination of employment or services where such termination is for cause. In the event of certain changes in control of the Company, the acquirer or survivor of such transaction must assume all obligations under the Plan; provided, however, that in lieu of such assumption obligation, the committee may, at its sole discretion, assign overriding royalty interests in wells to substantially mirror the rights of participants under the Plan. Similarly, the committee may, at any time, assign overriding royalty interests in wells in settlement of obligations under the Plan. The Plan is administered by the Company’s compensation committee which shall consult with the Company’s chief executive officer relative to Pool participants, prospects, wells and interests assign although the committee will have final and absolute authority to make all such determinations. During 2024, no pools were established under the Plan. The Company records amounts payable under the plan as a reduction to revenue as revenues are recognized from prospects included in pools covered by the plan based on the participants’ interest in such prospect revenues and records the same as accounts payable until such time as such amounts are paid out. ORRI Grants 1.5 Payments made by the Company under the Plan and ORRI’s totaled $ 42,450 47,724 0 0

GEOGRAPHICAL INFORMATION

GEOGRAPHICAL INFORMATION	12 Months Ended
	Dec. 31, 2024
Geographical Information
GEOGRAPHICAL INFORMATION	NOTE 10— GEOGRAPHICAL INFORMATION The Company currently has operations in two geographical areas, the United States and Colombia. Revenues for the years ended December 31, 2024 and 2023 and long-lived assets as of December 31, 2024 and 2023 attributable to each geographical area are presented below: SCHEDULE OF REVENUES AND LONG LIVED ASSETS ATTRIBUTABLE TO GEOGRAPHICAL AREA 2024 2023 Revenues Long Lived Assets, Net Revenues Long Lived Assets, Net North America $ 560,180 $ 1,117,636 $ 794,027 $ 1,559,301 South America — — — — Total $ 560,180 $ 1,117,636 $ 794,027 $ 1,559,301

SEGMENT INFORMATION

SEGMENT INFORMATION	12 Months Ended
	Dec. 31, 2024
Segment Reporting [Abstract]
SEGMENT INFORMATION	NOTE 11 — SEGMENT INFORMATION The Company’s chief operating decision maker (“CODM”), the Chief Executive Officer, manages the Company’s business activities as a single operating and reportable segment at the consolidated level. Accordingly, our CODM uses net income to measure profit or loss, allocate resources, and assess performance. Further, the CODM is regularly provided with and utilizes consolidated functional expenses, as presented in the accompanying consolidated statements of operations, and total assets at the consolidated level, as included in the consolidated balance sheets herein, to manage the Company’s operations.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2024
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	NOTE 12— SUBSEQUENT EVENTS On February 20, 2025, the Company entered into a Share Exchange Agreement with the members of Abundia Global Impact Group, LLC (“AGIG”). In the Share Exchange Agreement, the Company has agreed to issue to the members of AGIG a number of shares of our common stock equal to 94% of the Company’s issued and outstanding shares (after taking into account such issuance). As a result of entering into the Share Exchange Agreement, we will acquire all of the issued and outstanding units of AGIG, and AGIG will become a wholly-owned subsidiary of the Company. Under the Share Exchange Agreement, the Company is obligated to obtain shareholder approval for the amendment of our Certificate of Incorporation to increase the number of authorized shares of common stock to 300,000,000 246,000,000 In January 2025, the Company sold 2,600,000 3,897,000 In January 2025, the Company issued 24,202 24,202 10,638

SUPPLEMENTAL INFORMATION ON OIL

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)	12 Months Ended
	Dec. 31, 2024
Extractive Industries [Abstract]
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)	NOTE 13— SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) This footnote provides unaudited information required by FASB ASC Topic 932, Extractive Activities—Oil and Gas Geographical Data The following table shows the Company’s oil and gas revenues and lease operating expenses, which excludes the joint venture expenses incurred in South America, by geographic area: SCHEDULE OF OIL AND GAS REVENUES AND LEASE OPERATING EXPENSES 2024 2023 Revenues North America $ 560,180 $ 794,027 South America — — $ 560,180 $ 794,027 Production Cost North America $ 747,559 $ 473,925 South America — — $ 747,559 $ 473,925 Capital Costs Capitalized costs and accumulated depletion relating to the Company’s oil and gas producing activities as of December 31, 2024, all of which are onshore properties located in the United States and Colombia, South America are summarized below: CAPITALIZED COSTS AND ACCUMULATED DEPLETION RELATING TO OIL AND GAS PRODUCTION ACTIVITIES United States South America Total Unproved properties not being amortized $ — $ — $ — Proved properties being amortized 13,326,003 49,444,654 62,770,657 Accumulated depreciation, depletion, amortization and impairment (12,208,367 ) (49,444,654 ) (61,653,021 ) Net capitalized costs $ 1,117,636 $ — $ 1,117,636 Amortization Rate The amortization rate per unit based on barrel of oil equivalents was $ 10.75 Reserve Information and Related Standardized Measure of Discounted Future Net Cash Flows The unaudited supplemental information on oil and gas exploration and production activities has been presented in accordance with reserve estimation and disclosures rules issued by the SEC in 2008. Under those rules, average first-day-of-the-month price during the 12-month period before the end of the year are used when estimating whether reserve quantities are economical to produce. This same 12 Proved reserves are those estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment, and operating methods. The reserve estimates set forth below were prepared by Russell K. Hall and Associates, Inc. (“R.K. Hall”), utilizing reserve definitions and pricing requirements prescribed by the SEC. R.K. Hall is an independent professional engineering firm specializing in the technical and financial evaluation of oil and gas assets. R.K. Hall’s report was conducted under the direction of Russell K. Hall, founder and President of R.K. Hall. Mr. Hall holds a BS in Mechanical Engineering from the University of Oklahoma and is a registered professional engineer with more than 30 Total estimated proved developed, proved non-producing, and undeveloped reserves by product type and the changes therein are set forth below for the years indicated. SCHEDULE OF PROVED DEVELOPED AND UNDEVELOPED RESERVES BY PRODUCT TYPE United States Gas (mcf) Oil (bbls) Natural Gas Liquids (gallons) Total proved reserves Balance December 31, 2022 1,030,420 83,517 — Revisions of prior estimates (365,414 ) (16,947 ) — Production (57,360 ) (7,719 ) — Balance December 31, 2023 607,646 58,599 — Extensions and discoveries 78,980 17,000 502,614 Revisions to prior estimates (214,960 ) (23,217 ) 1,119,316 Production (53,476 ) (5,992 ) (159,680 ) Balance December 31, 2024 418,190 46,390 1,462,250 Proved developed reserves at December 31, 2023 607,646 58,599 1,621,930 at December 31, 2024 418,190 46,390 1,462,250 Proved undeveloped reserves at December 31, 2023 — — — at December 31, 2024 — — — As of December 31, 2024 and 2023, the Company had no proved undeveloped (“PUD”) reserves and no reserves outside of the United States. The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is computed using average first-day-of the-month prices for oil and gas during the preceding 12-month period (with consideration of price changes only to the extent provided by contractual arrangements), applied to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated related future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated), and assuming continuation of existing economic conditions. Future income tax expenses give effect to permanent differences and tax credits but do not reflect the impact of continuing operations including property acquisitions and exploration. The estimated future cash flows are then discounted using a rate of ten percent a year to reflect the estimated timing of the future cash flows. Standardized measure of discounted future net cash flows at December 31, 2024: STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS United States South America Total Future cash flows from sales of oil and gas $ 4,427,982 — 4,427,982 Future production cost (2,400,990 ) — (2,400,990 ) Future development cost (155,628 ) — 155,628 Future net cash flows 1,871,364 — 1,871,364 10% annual discount for timing of cash flow (748,094 ) — (748,094 ) Standardized measure of discounted future net cash flow relating to proved oil and gas reserves $ 1,123,270 — 1,123,270 Changes in standardized measure: Change due to current year operations Sales, net of production costs $ 39,359 ) — 39,359 Sales, net of production costs $ 39,359 ) — 39,359 ) Change due to revisions in standardized variables: — — Accretion of discount 156,472 — 156,472 Net change in sales and transfer price, net of production costs (1,433,013 ) — (1,433,013 ) Net change in future development cost — — — Discoveries 585,420 — 585,420 Revision and others (33,056 ) — (33,056 ) Changes in production rates and other 243,364 — 243,364 Net (441,454 ) — (441,454 ) Beginning of year 1,564,724 — 1,564,724 End of year $ 1,123,270 — 1,123,270 Standardized measure of discounted future net cash flows at December 31, 2023: United States South America Total Future cash flows from sales of oil and gas $ 6,509,498 $ — $ 6,509,498 Future production cost (3,804,439 ) — (3,804,439 ) Future development cost — — — Future net cash flows 2,705,059 — 2,705,059 10% annual discount for timing of cash flow (1,140,335 ) — (1,140,335 ) Standardized measure of discounted future net cash flow relating to proved oil and gas reserves $ 1,564,724 $ — $ 1,564,724 Changes in standardized measure: Change due to current year operations Sales, net of production costs $ (196,003 ) $ — $ (196,003 ) Sales, net of production costs $ (196,003 ) $ — $ (196,003 ) Change due to revisions in standardized variables: Accretion of discount 516,316 — 516,316 Net change in sales and transfer price, net of production costs (3,117,105 ) — (3,117,105 Net change in future development cost — — — Discoveries — — — Revision and others (645,668 ) — (645,668 Changes in production rates and other (155,975 ) — (155,975 ) Net (3,598,435 ) — (3,598,435 Beginning of year 5,163,159 — 5,163,159 End of year $ 1,564,724 $ — $ 1,564,724

NATURE OF COMPANY AND SUMMARY_2

NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General	General Houston American Energy Corp. (a Delaware corporation) (“the Company” or “HUSA”) was incorporated in 2001. The Company is engaged, as a non-operating joint owner, in the exploration, development, and production of natural gas, crude oil, and condensate from properties. The Company’s principal properties are in the Texas Permian Basin and international holdings in Colombia, South America, with additional holdings in Gulf Coast areas of the United States.
Consolidation	Consolidation The accompanying consolidated financial statements include all accounts of HUSA and its subsidiary (HAEC Louisiana E&P, Inc.). All significant inter-company balances and transactions have been eliminated in consolidation.
Liquidity and Capital Requirements	Liquidity and Capital Requirements The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the issuance date of these consolidated financial statements. With limited exceptions, the Company has incurred continuing losses since 2011, with an accumulated deficit of $ 85.2 The Company believes that it has the ability to fund, from cash on hand, its operating costs and anticipated drilling operations for at least the next twelve months following the issuance of these financial statements. The actual timing and number of wells drilled during 2025 and beyond will be principally controlled by the operators of the Company’s acreage, based on a number of factors, including but not limited to availability of financing, performance of existing wells on the subject acreage, energy prices and industry condition and outlook, costs of drilling and completion services and equipment and other factors beyond the Company’s control or that of its operators. In the event that the Company pursues additional acreage acquisitions or expands its drilling plans, the Company may be required to secure additional funding beyond our resources on hand. While the Company may, among other efforts, seek additional funding from “at-the-market” sales of common stock, and private sales of equity and debt securities, it presently has limited shares of common stock authorized for issuance to support sales of such shares and does not have any commitments to provide additional funding, and there can be no assurance that the Company can secure the necessary capital to fund its share of drilling, acquisition or other costs on acceptable terms or at all. If, for any reason, the Company is unable to fund its share of drilling and completion costs, it would forego participation in one or more of such wells. In such event, the Company may be subject to penalties or to the possible loss of some of its rights and interests in prospects with respect to which it fails to satisfy funding obligations and it may be required to curtail operations and forego opportunities.
General Principles and Use of Estimates	General Principles and Use of Estimates The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America. In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to such potential matters as litigation, environmental liabilities, income taxes, and determination of proved reserves of oil and gas and asset retirement obligations. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents consist of demand deposits and cash investments with initial maturity dates of less than three months when purchased. As of December 31, 2024 and 2023, the Company had no
Concentration of Credit Risk	Concentration of Credit Risk Financial instruments that potentially subject the Company to a concentration of credit risk include cash, cash equivalents and marketable securities (if any). The Company had cash deposits of $ 2.5 250,000
Revenue Recognition	Revenue Recognition The Company’s revenue is comprised principally of revenue from exploration and production activities. The Company’s oil is sold primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct end-users, industrial users, local distribution companies, and natural-gas marketers. Natural gas liquids, or NGLs, are sold primarily to direct end-users, refiners, and marketers. Payment is generally received from the customer in the month following delivery. Contracts with customers have varying terms, including spot sales or month-to-month contracts, contracts with a finite term, and life-of-field contracts where all production from a well or group of wells is sold to one or more customers. The Company recognizes sales revenues for oil, natural gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs. Revenues are recognized for the sale of the Company’s net share of production volumes. The Company estimated the December 2024 revenue and related drilling expenses for two US wells. Using actual oil production results for the month, the Company used historical lease operating expenses and average price per BBL from prior months to calculate these estimates. No gas or NGL related revenue or expenses are included in the estimate.
Loss per Share	Loss per Share Basic loss per share is computed by dividing net loss available to common shareholders by the weighted average common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted in common shares that then shared in the earnings of the Company. In periods in which the Company reports a net loss, dilutive securities are excluded from the calculation of diluted net loss per share amounts as the effect would be anti-dilutive. For the years ended December 31, 2024 and 2023, the following warrants and options to purchase shares of common stock were excluded from the computation of diluted net loss per share, as the inclusion of such shares would be anti-dilutive: SCHEDULE OF COMPUTATION OF DILUTED NET LOSS PER SHARE Year Ended December 31, 2024 2023 Stock warrants 94,400 94,400 Stock options 916,987 1,000,807 Totals 1,011,387 1,095,207
Accounts Receivable	Accounts Receivable Accounts receivable – other and escrow receivables have been evaluated for collectability and are recorded at their net realizable values.
Allowance for Accounts Receivable	Allowance for Accounts Receivable The Company’s ability to collect outstanding receivables is critical to its operating performance and cashflows. Accounts receivable are stated at an amount management expects to collect from outstanding balances. The Company extends credit in the normal course of business. The Company regularly reviews outstanding receivables and when the Company determines that a party may not be able to make required payments, a charge to bad debt expense in the period of determination is made. Though the Company’s bad debts have not historically been significant, the Company could experience increased bad debt expense should a financial downturn occur. The Company updated its impairment model to utilize a forward-looking current expected credit losses (“CECL”) model in place of the incurred loss methodology for financial instruments measured at amortized cost, primarily including its accounts receivable and contract asset. In relation to available-for-sale (“AFS”) debt securities, the guidance eliminates the concept of “other-than-temporary” impairment, and instead focuses on determining whether any impairment is a result of a credit loss or other factors. The adoption of ASC 326 did not have a material impact on our unaudited condensed consolidated financial statements as of the adoption date.
Oil and Gas Properties	Oil and Gas Properties The Company uses the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs for unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. Capitalized costs include lease acquisition, geological and geophysical work, delay rentals, costs of drilling, completing and equipping the wells and any internal costs that are directly related to acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Proceeds from the sale or other disposition of oil and gas properties are generally treated as a reduction in the capitalized costs of oil and gas properties, unless the impact of such a reduction would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. The Company categorizes its full cost pools as costs subject to amortization and costs not being amortized. The sum of net capitalized costs subject to amortization, including estimated future development and abandonment costs, are amortized using the unit-of-production method. Depletion and amortization for oil and gas properties was $ 160,001 167,526 61,743,025 61,217,260
Costs Excluded	Costs Excluded Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent costs of investments in unproved properties. The Company excludes these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the costs subject to amortization.
Ceiling Test	Ceiling Test Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X. The ceiling test determines a limit, on a country-by-country basis, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment (“DD&A”) 275,760 537,686
Furniture and Equipment	Furniture and Equipment Office equipment is stated at original cost and is depreciated on the straight-line basis over the useful life of the assets, which ranges from three to five years. Office equipment having an original cost basis of $ 90,004 90,004 90,004
Equity Investment Accounted for at Cost	Equity Investment Accounted for at Cost Businesses not accounted for under either the consolidation method or equity method of accounting are accounted for under equity investments accounted for at cost and are further discussed in Note 4, “Equity Investments Accounted for at Cost.” The Company’s share of the earnings and/or losses of equity investments accounted for at cost is not included in the Consolidated Statements of Operations. Income from equity investments accounted for at cost is only realized if and when distributions are made from the business to its investors. However, impairment charges related to businesses are recognized in the company’s Consolidated Statements of Operations. If circumstances suggest that the value of an equity investment accounted for at cost with respect to which an impairment charge has been made has subsequently recovered, that recovery is not recorded. The carrying values of the company’s equity investments accounted for at cost are reflected in the line item “Equity investment – Hupecol Meta, LLC” in the Company’s Consolidated Balance Sheets. As of December 31, 2024, the Company determined it was necessary to take an impairment charge of $ 6,392,874
Asset Retirement Obligations	Asset Retirement Obligations For the Company, asset retirement obligations (“ARO”) represent the systematic, monthly accretion and depreciation of future abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, an adjustment is made to the full cost pool, with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. Although the Company’s domestic policy with respect to ARO is to assign depleted wells to a salvager for the assumption of abandonment obligations before the wells have reached their economic limits, the Company has estimated its future ARO obligation with respect to its domestic operations. The ARO assets, which are carried on the balance sheet as part of the full cost pool, have been included in our amortization base for the purposes of calculating depreciation, depletion and amortization expense. For the purposes of calculating the ceiling test, the future cash outflows associated with settling the ARO liability have been included in the computation of the discounted present value of estimated future net revenues. Asset retirement obligations are classified as Level 3 (unobservable inputs) fair value measurements.
Income Taxes	Income Taxes Deferred income taxes are provided on a liability method whereby deferred tax assets and liabilities are established for the difference between the financial reporting and income tax basis of assets and liabilities as well as operating loss and tax credit carry forwards. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.
Uncertain Tax Positions	Uncertain Tax Positions The Company evaluates uncertain tax positions to recognize a tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. Those tax positions failing to qualify for initial recognition are recognized in the first interim period in which they meet the more likely than not standard or are resolved through negotiation or litigation with the taxing authority, or upon expiration of the statute of limitations. De-recognition of a tax position that was previously recognized occurs when an entity subsequently determines that a tax position no longer meets the more likely than not threshold of being sustained. The Company is subject to ongoing tax exposures, examinations and assessments in various jurisdictions. Accordingly, the Company may incur additional tax expense based upon the outcomes of such matters, including any interest or penalties. In addition, when applicable, the Company will adjust tax expense to reflect the Company’s ongoing assessments of such matters, which require judgment and can materially increase or decrease its effective rate as well as impact operating results. There were no liabilities recorded for uncertain tax positions at December 31, 2024 and 2023.
Stock-Based Compensation	Stock-Based Compensation The Company measures the cost of employee services received in exchange for stock and stock options based on the grant date fair value of the awards. The Company determines the fair value of stock option grants using the Black-Scholes option pricing model. The Company determines the fair value of shares of non-vested stock based on the last quoted price of our stock on the date of the share grant. The fair value determined represents the cost for the award and is recognized over the vesting period during which an employee is required to provide service in exchange for the award. As stock-based compensation expense is recognized based on awards ultimately expected to vest, the Company reduces the expense for estimated forfeitures based on historical forfeiture rates. Previously recognized compensation costs may be adjusted to reflect the actual forfeiture rate for the entire award at the end of the vesting period. Excess tax benefits, if any, are recognized as an addition to paid-in capital.
Concentration of Risk	Concentration of Risk As a non-operator oil and gas exploration and production company, and through its interest in a limited liability company (“Hupecol Meta”) and concessions operated by Hupecol Meta in the South American country of Colombia, the Company is dependent on the personnel, management and resources of the operators of its various properties to operate efficiently and effectively. As a non-operating joint interest owner, the Company has a right of investment refusal on specific projects and the right to examine and contest its division of costs and revenues determined by the operator. The Company’s Permian Basin, Texas properties accounted for all of the Company’s oil and gas operations and substantially all of its oil and gas investments reflected in its consolidated financial statements in 2024. In the event of a significant negative change in operations or operating outlook pertaining to the Company’s Permian Basin properties, the Company may be forced to abandon or suspend such operations, which abandonment or suspension could be materially harmful to the Company. For 2024, the Company’s oil production from its mineral interests was sold to U.S. oil marketing companies based on the highest bid. The gas production is sold to U.S. natural gas marketing companies based on the highest bid. No purchaser accounted for more than 10 The Company reviews accounts receivable balances when circumstances indicate a balance may not be collectible. Based upon the Company’s review, no allowance for uncollectible accounts was deemed necessary at December 31, 2024 and 2023, respectively.
Recently Adopted Accounting Pronouncements	Recently Adopted Accounting Pronouncements In June 2016, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses of Financial Instruments, which was codified in Accounting Standards Codification (“ASC”) 326, Financial Instruments — Credit Losses (“ASC 326”). The standard changes the methodology for measuring credit losses on financial instruments and the timing of when such losses are recorded. Because the Company is a smaller reporting company based on the most recent determination as of November 15, 2019, ASC 326 became effective for the Company for fiscal years beginning after December 15, 2022. As such, the Company adopted ASC 326 effective January 1, 2023, utilizing the modified retrospective transition method. Upon adoption, the Company updated its impairment model to utilize a forward-looking current expected credit losses (“CECL”) model in place of the incurred loss methodology for financial instruments measured at amortized cost, primarily including its accounts receivable and contract asset. In relation to available-for-sale (“AFS”) debt securities, the guidance eliminates the concept of “other-than-temporary” impairment, and instead focuses on determining whether any impairment is a result of a credit loss or other factors. In accordance with Accounting Standards Updates ASU 2016-13, Financial Instruments-Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments In November 2023, the FASB issued Accounting Standards Update (“ASU”) 2023-07 “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures”.
Recently Issued Accounting Pronouncements	Recently Issued Accounting Pronouncements In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires disaggregated information about a reporting entity’s effective tax rate reconciliation, as well as information related to income taxes paid to enhance the transparency and decision usefulness of income tax disclosures. This ASU will be effective for the annual period ending December 31, 2025. The Company is currently evaluating the timing and impacts of adoption of this ASU.
Subsequent Events	Subsequent Events The Company evaluated subsequent events for disclosure from December 31, 2024 through the date the consolidated financial statements were issued. See Note 12.

NATURE OF COMPANY AND SUMMARY_3

NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
SCHEDULE OF COMPUTATION OF DILUTED NET LOSS PER SHARE	For the years ended December 31, 2024 and 2023, the following warrants and options to purchase shares of common stock were excluded from the computation of diluted net loss per share, as the inclusion of such shares would be anti-dilutive: SCHEDULE OF COMPUTATION OF DILUTED NET LOSS PER SHARE Year Ended December 31, 2024 2023 Stock warrants 94,400 94,400 Stock options 916,987 1,000,807 Totals 1,011,387 1,095,207

REVENUE FROM CONTRACTS WITH C_2

REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables)	12 Months Ended
	Dec. 31, 2024
Revenue from Contract with Customer [Abstract]
SCHEDULE OF DISAGGREGATES REVENUE BY SIGNIFICANT PRODUCT	The following table disaggregates revenue by significant product type for the years ended December 31, 2024 and 2023: SCHEDULE OF DISAGGREGATES REVENUE BY SIGNIFICANT PRODUCT 2024 2023 Year Ended December 31, 2024 2023 Oil sales $ 437,900 $ 590,486 Natural gas sales 8,869 79,443 Natural gas liquids sales 113,411 124,098 Total revenue from customers $ 560,180 $ 794,027

OIL AND GAS PROPERTIES (Tables)

OIL AND GAS PROPERTIES (Tables)	12 Months Ended
	Dec. 31, 2024
Extractive Industries [Abstract]
SCHEDULE OF EVALUATED OIL AND GAS PROPERTIES SUBJECT TO AMORTIZATION	Evaluated oil and gas properties subject to amortization at December 31, 2024 included the following: SCHEDULE OF EVALUATED OIL AND GAS PROPERTIES SUBJECT TO AMORTIZATION United States South America Total Evaluated properties being amortized $ 13,326,003 $ 49,444,654 $ 62,770,657 Accumulated depreciation, depletion, amortization and impairment (12,208,367 ) (49,444,654 ) (61,653,021 ) Net capitalized costs $ 1,117,636 $ — $ 1,117,636 Evaluated oil and gas properties subject to amortization at December 31, 2023 included the following: United States South America Total Evaluated properties being amortized $ 13,321,907 $ 49,444,654 $ 62,766,561 Accumulated depreciation, depletion, amortization and impairment (11,762,288 ) (49,444,654 ) (61,206,942 ) Net capitalized costs $ 1,559,619 $ — $ 1,559,619

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2024
Asset Retirement Obligation Disclosure [Abstract]
SCHEDULE OF CHANGES IN OUR ASSET RETIREMENT LIABILITY	The following table presents changes in our asset retirement liability (“ARO”) during each of the years ended December 31, 2024 and 2023. SCHEDULE OF CHANGES IN OUR ASSET RETIREMENT LIABILITY 2024 2023 ARO liability at January 1 $ 63,084 $ 72,789 Additions from new drilling — — Liabilities settled — (2,706 ) Changes in estimates (5,904 ) (9,706 ) Accretion expense — 2,707 ARO liability at December 31 $ 57,180 $ 63,084

STOCK-BASED COMPENSATION (Table

STOCK-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2024
Share-Based Payment Arrangement [Abstract]
SUMMARY OF STOCK OPTION ACTIVITY	Option activity during 2024 and 2023 was as follows: SUMMARY OF STOCK OPTION ACTIVITY Options Weighted Average Exercise Price Weighted Average Remaining Contractual Term (in Years) Aggregate Intrinsic Value Outstanding at December 31, 2022 944,177 $ 2.08 Granted 60,000 $ 2.09 Exercised — $ 3.84 Forfeited (3,370 ) $ 20.43 Outstanding at December 31, 2023 1,000,807 2.46 Granted 82,320 1.08 Exercised — Expired (166,140 ) 3.87 Outstanding at December 31, 2024 916,987 $ 2.06 6.10 $ 16,956 Exercisable at December 31, 2024 851,131 $ 2.13 5.86 $ 16,956
SCHEDULE OF STOCK-BASED COMPENSATION	The following table reflects stock-based compensation recorded by the Company for 2024 and 2023: SCHEDULE OF STOCK-BASED COMPENSATION 2024 2023 Stock-based compensation expense from stock options and common stock included in general and administrative expense $ 101,508 $ 238,314 Earnings per share effect of stock-based compensation expense $ (0.01 ) $ (0.02 )

CAPITAL STOCK (Tables)

CAPITAL STOCK (Tables)	12 Months Ended
	Dec. 31, 2024
Equity [Abstract]
SUMMARY OF WARRANT ACTIVITY	A summary of warrant activity and related information for 2024 and 2023 is presented below: SUMMARY OF WARRANT ACTIVITY Warrants Weighted-Average Aggregate Outstanding at December 31, 2022 94,400 $ 2.50 Issued — — Exercised — — Expired — $ — Outstanding at December 31, 2023 94,400 $ 2.50 Issued — — Exercised — — Expired — — Outstanding at December 31, 2024 94,400 $ 2.50 $ — Exercisable at December 31, 2024 94,400 $ 2.50 $ —

TAXES (Tables)

TAXES (Tables)	12 Months Ended
	Dec. 31, 2024
Income Tax Disclosure [Abstract]
SCHEDULE OF RECONCILIATION OF STATUTORY FEDERAL INCOME TAX	The following table sets forth a reconciliation of the statutory federal income tax for the years ended December 31, 2024 and 2023. SCHEDULE OF RECONCILIATION OF STATUTORY FEDERAL INCOME TAX 2024 2023 Income (loss) before income taxes $ (8,216,112 ) $ (3,211,277 ) Income tax expense (benefit) computed at statutory rates $ (1,725,727 ) $ (674,368 ) Permanent differences, nondeductible expenses 28 9 Increase (decrease) in valuation allowance 1,807,535 710,336 ) Expiration of options 32,060 — RTA True-Ups (227,729 ) (10,919 ) Deferred True-Up 113,833 (25,088 ) Tax provision $ — $ — Total provision Foreign $ — $ — Total provision (benefit) $ — $ —
SIGNIFICANT COMPONENTS OF DEFERRED TAX ASSET AND LIABILITY	SIGNIFICANT COMPONENTS OF DEFERRED TAX ASSET AND LIABILITY 2024 2023 Non-Current Deferred tax assets: Net operating loss carry forward 12,729,620 $ 12,355,137 Foreign tax credit carry forward 18,865 18,865 Deferred state tax — — Stock compensation 460,368 470,816 Book in excess of tax depreciation, depletion and capitalization methods on oil and gas properties 1,497,253 53,720 Other — — ASC 842 lease standard – building lease 248 281 Pass-through investment — — Total Non-Current Deferred tax assets 14,706,354 12,898,819 Valuation Allowance (14,706,354 ) (12,898,819 ) Net deferred tax asset — $ —

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
SCHEDULE OF FUTURE PAYMENTS UNDER LEASE AGREEMENT	SCHEDULE OF FUTURE PAYMENTS UNDER LEASE AGREEMENT Year Amount 2025 75,051 Thereafter — Total future lease payments 75,051 Less: imputed interest (3,969 ) Present value of future operating lease payments 71,082 Less: current portion of operating lease liabilities 71,082 Long-term operating lease liability $ —

SUPPLEMENTAL INFORMATION ON O_2

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2024
Extractive Industries [Abstract]
SCHEDULE OF OIL AND GAS REVENUES AND LEASE OPERATING EXPENSES	The following table shows the Company’s oil and gas revenues and lease operating expenses, which excludes the joint venture expenses incurred in South America, by geographic area: SCHEDULE OF OIL AND GAS REVENUES AND LEASE OPERATING EXPENSES 2024 2023 Revenues North America $ 560,180 $ 794,027 South America — — $ 560,180 $ 794,027 Production Cost North America $ 747,559 $ 473,925 South America — — $ 747,559 $ 473,925
CAPITALIZED COSTS AND ACCUMULATED DEPLETION RELATING TO OIL AND GAS PRODUCTION ACTIVITIES	Capitalized costs and accumulated depletion relating to the Company’s oil and gas producing activities as of December 31, 2024, all of which are onshore properties located in the United States and Colombia, South America are summarized below: CAPITALIZED COSTS AND ACCUMULATED DEPLETION RELATING TO OIL AND GAS PRODUCTION ACTIVITIES United States South America Total Unproved properties not being amortized $ — $ — $ — Proved properties being amortized 13,326,003 49,444,654 62,770,657 Accumulated depreciation, depletion, amortization and impairment (12,208,367 ) (49,444,654 ) (61,653,021 ) Net capitalized costs $ 1,117,636 $ — $ 1,117,636
SCHEDULE OF PROVED DEVELOPED AND UNDEVELOPED RESERVES BY PRODUCT TYPE	Total estimated proved developed, proved non-producing, and undeveloped reserves by product type and the changes therein are set forth below for the years indicated. SCHEDULE OF PROVED DEVELOPED AND UNDEVELOPED RESERVES BY PRODUCT TYPE United States Gas (mcf) Oil (bbls) Natural Gas Liquids (gallons) Total proved reserves Balance December 31, 2022 1,030,420 83,517 — Revisions of prior estimates (365,414 ) (16,947 ) — Production (57,360 ) (7,719 ) — Balance December 31, 2023 607,646 58,599 — Extensions and discoveries 78,980 17,000 502,614 Revisions to prior estimates (214,960 ) (23,217 ) 1,119,316 Production (53,476 ) (5,992 ) (159,680 ) Balance December 31, 2024 418,190 46,390 1,462,250 Proved developed reserves at December 31, 2023 607,646 58,599 1,621,930 at December 31, 2024 418,190 46,390 1,462,250 Proved undeveloped reserves at December 31, 2023 — — — at December 31, 2024 — — —
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS	Standardized measure of discounted future net cash flows at December 31, 2024: STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS United States South America Total Future cash flows from sales of oil and gas $ 4,427,982 — 4,427,982 Future production cost (2,400,990 ) — (2,400,990 ) Future development cost (155,628 ) — 155,628 Future net cash flows 1,871,364 — 1,871,364 10% annual discount for timing of cash flow (748,094 ) — (748,094 ) Standardized measure of discounted future net cash flow relating to proved oil and gas reserves $ 1,123,270 — 1,123,270 Changes in standardized measure: Change due to current year operations Sales, net of production costs $ 39,359 ) — 39,359 Sales, net of production costs $ 39,359 ) — 39,359 ) Change due to revisions in standardized variables: — — Accretion of discount 156,472 — 156,472 Net change in sales and transfer price, net of production costs (1,433,013 ) — (1,433,013 ) Net change in future development cost — — — Discoveries 585,420 — 585,420 Revision and others (33,056 ) — (33,056 ) Changes in production rates and other 243,364 — 243,364 Net (441,454 ) — (441,454 ) Beginning of year 1,564,724 — 1,564,724 End of year $ 1,123,270 — 1,123,270 Standardized measure of discounted future net cash flows at December 31, 2023: United States South America Total Future cash flows from sales of oil and gas $ 6,509,498 $ — $ 6,509,498 Future production cost (3,804,439 ) — (3,804,439 ) Future development cost — — — Future net cash flows 2,705,059 — 2,705,059 10% annual discount for timing of cash flow (1,140,335 ) — (1,140,335 ) Standardized measure of discounted future net cash flow relating to proved oil and gas reserves $ 1,564,724 $ — $ 1,564,724 Changes in standardized measure: Change due to current year operations Sales, net of production costs $ (196,003 ) $ — $ (196,003 ) Sales, net of production costs $ (196,003 ) $ — $ (196,003 ) Change due to revisions in standardized variables: Accretion of discount 516,316 — 516,316 Net change in sales and transfer price, net of production costs (3,117,105 ) — (3,117,105 Net change in future development cost — — — Discoveries — — — Revision and others (645,668 ) — (645,668 Changes in production rates and other (155,975 ) — (155,975 ) Net (3,598,435 ) — (3,598,435 Beginning of year 5,163,159 — 5,163,159 End of year $ 1,564,724 $ — $ 1,564,724

SCHEDULE OF COMPUTATION OF DILU

SCHEDULE OF COMPUTATION OF DILUTED NET LOSS PER SHARE (Details) - shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Totals	1,011,387	1,095,207
Warrant [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Totals	94,400	94,400
Share-Based Payment Arrangement, Option [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Totals	916,987	1,000,807

NATURE OF COMPANY AND SUMMARY_4

NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Jan. 01, 2020
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Accumulated deficit	$ 85,215,109	$ 76,998,997
Cash equivalents	0	0
Cash deposits	2,500,000
Current insured limit on interest bearing accounts	250,000
Depreciation depletion amortization	160,001	167,527
Accumulated amortization, depreciation and impairment	61,743,025	61,217,260
Impairment of oil and gas properties	275,760	537,686
Accumulated depreciation	61,743,025	61,307,264
Impairment charge	$ 6,392,874
Discount rate, net of related tax effects	10%
Office Equipment [Member]
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Accumulated depreciation	$ 90,004	90,004	$ 90,004
Oil and Gas [Member]
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Depreciation depletion amortization	$ 160,001	$ 167,526

SCHEDULE OF DISAGGREGATES REVEN

SCHEDULE OF DISAGGREGATES REVENUE BY SIGNIFICANT PRODUCT (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Disaggregation of Revenue [Line Items]
Total revenue from customers	$ 560,180	$ 794,027
Oil Sales [Member]
Disaggregation of Revenue [Line Items]
Total revenue from customers	437,900	590,486
Natural Gas Sales [Member]
Disaggregation of Revenue [Line Items]
Total revenue from customers	8,869	79,443
Natural Gas Liquids Sales [Member]
Disaggregation of Revenue [Line Items]
Total revenue from customers	$ 113,411	$ 124,098

REVENUE FROM CONTRACTS WITH C_3

REVENUE FROM CONTRACTS WITH CUSTOMERS (Details Narrative) - USD ($)	Dec. 31, 2024	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Remaining performance obligations	$ 0	$ 0

SCHEDULE OF EVALUATED OIL AND G

SCHEDULE OF EVALUATED OIL AND GAS PROPERTIES SUBJECT TO AMORTIZATION (Details) - USD ($)	Dec. 31, 2024	Dec. 31, 2023
Oil and Gas, Full Cost Method, Amortization Expense [Line Items]
Evaluated properties being amortized	$ 62,770,657	$ 62,766,561
Accumulated depreciation, depletion, amortization and impairment	(61,653,021)	(61,206,942)
Net capitalized costs	1,117,636	1,559,619
UNITED STATES
Oil and Gas, Full Cost Method, Amortization Expense [Line Items]
Evaluated properties being amortized	13,326,003	13,321,907
Accumulated depreciation, depletion, amortization and impairment	(12,208,367)	(11,762,288)
Net capitalized costs	1,117,636	1,559,619
South America [Member]
Oil and Gas, Full Cost Method, Amortization Expense [Line Items]
Evaluated properties being amortized	49,444,654	49,444,654
Accumulated depreciation, depletion, amortization and impairment	(49,444,654)	(49,444,654)
Net capitalized costs

OIL AND GAS PROPERTIES (Details

OIL AND GAS PROPERTIES (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Extractive Industries [Abstract]
Impairment, Oil and Gas, Property with Unproved and Proved Reserves	$ 275,760	$ 537,686

Equity Investment Accounted f_2

Equity Investment Accounted for at Cost (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Equity Investment Accounted For At Cost
Total distributions received during period	$ 922,719
Investment for capital contributions	1,900,000
Cost method investment		$ 4,500,000
Impairment charge	$ 6,392,874

SCHEDULE OF CHANGES IN OUR ASSE

SCHEDULE OF CHANGES IN OUR ASSET RETIREMENT LIABILITY (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
ARO liability at January 1	$ 63,084	$ 72,789
Additions from new drilling
Liabilities settled		(2,706)
Changes in estimates	(5,904)	(9,706)
Accretion expense		2,707
ARO liability at December 31	$ 57,180	$ 63,084

SUMMARY OF STOCK OPTION ACTIVIT

SUMMARY OF STOCK OPTION ACTIVITY (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Options Outstanding at beginning of the period	1,000,807	944,177
Weighted-Average Exercise Price Outstanding at beginning of the period	$ 2.46	$ 2.08
Options Granted	82,320	60,000
Weighted-Average Exercise Price Granted	$ 1.08	$ 2.09
Option exercised
Weighted Average Exercise Price Exercised		$ 3.84
Options Forfeited		(3,370)
Weighted-Average Exercise Price Forfeited		$ 20.43
Options Expired	(166,140)
Weighted-Average Exercise Price Expired	$ 3.87
Options Outstanding at end of the period	916,987	1,000,807
Weighted-Average Exercise Price Outstanding at end of the period	$ 2.06	$ 2.46
Weighted average remaining contractual term of the outstanding options	6 years 1 month 6 days
Aggregate Intrinsic Value Outstanding at end of the period		$ 16,956
Options Outstanding Exercisable at end of the period	851,131
Weighted-Average Exercise Price Outstanding Exercisable at end of the period	$ 2.13
Weighted average remaining contractual term of the exercisable options	5 years 10 months 9 days
Aggregate Intrinsic Value Outstanding Exercisable at end of the period	$ 16,956

SCHEDULE OF STOCK-BASED COMPENS

SCHEDULE OF STOCK-BASED COMPENSATION (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Stock-based compensation expense from stock options and common stock included in general and administrative expense	$ 101,508	$ 238,314
Earnings per share effect of stock-based compensation expense	$ (0.01)	$ (0.02)

STOCK-BASED COMPENSATION (Detai

STOCK-BASED COMPENSATION (Details Narrative) - USD ($)	1 Months Ended				12 Months Ended
	Dec. 31, 2024	Nov. 30, 2024	Jun. 30, 2024	Jun. 30, 2023	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2021	Dec. 31, 2017	Dec. 31, 2008
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Number of options granted during period					82,320	60,000
Ten-year life exercisable	$ 2.13				$ 2.13
Number of non-vested options					65,856
Unrecognized share-based compensation expense related to non-vested stock options	$ 40,790				$ 40,790
Weighted average period for unrecognition of compensation expense					2 months 26 days
Weighted average remaining contractual term of the outstanding options					6 years 1 month 6 days
Weighted average remaining contractual term of the exercisable options					5 years 10 months 9 days
Issuance of common stock, shares					87,680
Directors [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Number of options granted during period			60,000	60,000
Weighted average remaining contractual term options, outstanding			10 years	10 years
Ten-year life exercisable			$ 1.21	$ 2.09
Description on vesting of stock options			vest 20% on the date of grant and 80% ten months from the date of grant.	vest 20% on the date of grant and 80% ten months from the date of grant.
Fair value of options granted			$ 63,730	$ 119,252
Market value of common stock			$ 1.21	$ 2.09
Risk free interest rate			0%	0%
Expected dividend yield			0%	0%
Expected stock volatility			97.80%	116%
Weighted average expected life (in years)			10 years	10 years
Expected forfeiture rate			0%	0%
Chief Executive Officer [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Weighted average remaining contractual term options, outstanding		10 years
Ten-year life exercisable	$ 0.73	$ 0.76			$ 0.73
Description on vesting of stock options		vest 20% on the date of grant and 80% ten months from the date of grant.
Fair value of options granted	$ 13,225	$ 14,657
Market value of common stock	$ 1.36	$ 1.43			$ 1.36
Risk free interest rate		0%
Expected dividend yield		0%
Expected stock volatility		92%
Weighted average expected life (in years)		10 years
Expected forfeiture rate		0%
Number of options granted during period		$ 15,000
2008 Equity Incentive Plan [Member] | Maximum [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Number of options authorized to purchase shares of common stock									480,000
2017 Equity Incentive Plan [Member] | Maximum [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Number of options authorized to purchase shares of common stock								400,000
2021 Equity Incentive Plan [Member] | Maximum [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Number of options authorized to purchase shares of common stock							500,000

SUMMARY OF WARRANT ACTIVITY (De

SUMMARY OF WARRANT ACTIVITY (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Equity [Abstract]
Warrants Outstanding, Beginning	94,400	94,400
Weighted-Average Exercise Price Outstanding, Beginning	$ 2.50	$ 2.50
Warrants Outstanding, Beginning
Weighted-Average Exercise Price Outstanding, Beginning
Warrants Outstanding, Beginning
Weighted-Average Exercise Price Outstanding, Beginning
Warrants Outstanding, Beginning
Weighted-Average Exercise Price Outstanding, Beginning
Warrants Outstanding, Beginning	94,400	94,400
Weighted-Average Exercise Price Outstanding, Beginning	$ 2.50	$ 2.50
[custom:ShareBasedCompensationArrangementByShareBasedPaymentAwardOptionsOutstandingWarrantIntrinsicValue-0]
Warrants Outstanding, Beginning	94,400
Weighted-Average Exercise Price Outstanding, Beginning	$ 2.50
[custom:SharebasedCompensationArrangementBySharebasedPaymentAwardOptionsWarrantsExercisableIntrinsicValue1-0]

CAPITAL STOCK (Details Narrativ

CAPITAL STOCK (Details Narrative) - USD ($)	1 Months Ended		12 Months Ended
	Nov. 30, 2022	Sep. 30, 2019	Dec. 31, 2024	Dec. 31, 2023
Bridge Loan Warrants [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Expected life (in years)		10 years
Warrants expiration date		Sep. 18, 2029
Number of warrants issued to purchase common stock		94,400
Warrants exercise price		$ 2.50
Warrants fair value		$ 144,948
Risk free interest rate		1.80%
Expected stock volatility		82.90%
Expected dividend yield		0%
2022 ATM Offering [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Sale of stock shares of common stock value				$ 1,700,000
Number shares sold			2,180,180	578,707
2022 ATM Offering [Member] | West Park Capital LLC [Member] | Maximum [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Sale of stock shares of common stock value	$ 3,500,000
2021 ATM Offering [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Sale of stock shares of common stock value			$ 2,300,000

SCHEDULE OF RECONCILIATION OF S

SCHEDULE OF RECONCILIATION OF STATUTORY FEDERAL INCOME TAX (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Income (loss) before income taxes	$ (8,216,112)	$ (3,211,277)
Income tax expense (benefit) computed at statutory rates	(1,725,727)	(674,368)
Permanent differences, nondeductible expenses	28	9
Increase (decrease) in valuation allowance	1,807,535	710,336
Expiration of options	32,060
RTA True-Ups	(227,729)	(10,919)
Deferred True-Up	113,833	(25,088)
Tax provision
Foreign Income Tax Expense (Benefit), Continuing Operations
Income tax expense benefits

SIGNIFICANT COMPONENTS OF DEFER

SIGNIFICANT COMPONENTS OF DEFERRED TAX ASSET AND LIABILITY (Details) - USD ($)	Dec. 31, 2024	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Net operating loss carry forward	$ 12,729,620	$ 12,355,137
Foreign tax credit carry forward	18,865	18,865
Deferred state tax
Stock compensation	460,368	470,816
Book in excess of tax depreciation, depletion and capitalization methods on oil and gas properties	1,497,253	53,720
Other
ASC 842 lease standard – building lease	248	281
Pass-through investment
Total Non-Current Deferred tax assets	14,706,354	12,898,819
Valuation Allowance	(14,706,354)	(12,898,819)
Net deferred tax asset

TAXES (Details Narrative)

TAXES (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Federal tax loss carry forward	$ 12,741,145
Foreign tax credit carry forward	$ 18,865	$ 18,865
Description of net operating loss expiration year	Under the Tax Cuts and Jobs Act of 2017, net operating losses incurred for tax years beginning after December 31, 2017 will have no expiration date but utilization will be limited to 80% of taxable income. For losses generated prior to January 1, 2018, there will be no limitation on the utilization, but there is an expiration on the carryforward of 20 years for federal tax purposes.
Minimum [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Federal statutory income tax rate	80%
Maximum [Member]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items]
Federal statutory income tax rate	100%

SCHEDULE OF FUTURE PAYMENTS UND

SCHEDULE OF FUTURE PAYMENTS UNDER LEASE AGREEMENT (Details) - USD ($)	Dec. 31, 2024	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
2025	$ 75,051
Thereafter
Total future lease payments	75,051
Less: imputed interest	(3,969)
Present value of future operating lease payments	71,082
Less: current portion of operating lease liabilities	71,082	$ 75,276
Long-term operating lease liability		$ 71,083

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Details Narrative) - USD ($)	1 Months Ended	12 Months Ended
	Aug. 31, 2013	Dec. 31, 2024	Dec. 31, 2023
Loss Contingencies [Line Items]
Amortization of right of use asset		$ 75,120	$ 67,181
Rental expense		747,559	473,925
Description of production incentive compensation plan	The maximum percentage of the Company’s share of revenues from a well that may be designated to fund a Pool is 2% (the “Pool Cap”); provided, however, that with respect to wells with a net revenue interest to the 8/8 of less than 73%, the Pool Cap with respect to such wells shall be reduced on a 1-for-1 basis such that no portion of the Company’s revenues from a well may be designated to fund a Pool if the NRI is 71% or less.
Maximum percentage of revenue to fund a pool from a well	2%
Maximum percentage of revenue from a well considered for pool cap	73%
Maximum percentage of revenue from a well considered for pool nri	71%
Payment of overriding royalty interests		42,450	47,724
Accounts payable		$ 0	0
COLOMBIA | Current Director [Member]
Loss Contingencies [Line Items]
Percentage of royalty interest		1.50%
General and Administrative Expense [Member]
Loss Contingencies [Line Items]
Rental expense		$ 88,644	$ 88,644
Operating Lease Agreement [Member]
Loss Contingencies [Line Items]
Operating lease agreement expire date		Oct. 31, 2025
Operating cash outflows related to operating lease liabilities		$ 87,288
Amortization of right of use asset		$ 66,741
Operating lease, weighted average remaining lease term		9 months 29 days
Weighted average discount rate		12%

SCHEDULE OF REVENUES AND LONG L

SCHEDULE OF REVENUES AND LONG LIVED ASSETS ATTRIBUTABLE TO GEOGRAPHICAL AREA (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	$ 560,180	$ 794,027
Long Lived Assets, Net	1,117,636	1,559,301
North America [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	560,180	794,027
North America [Member] | Reportable Geographical Components [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues	560,180	794,027
Long Lived Assets, Net	1,117,636	1,559,301
South America [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues
South America [Member] | Reportable Geographical Components [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Revenues
Long Lived Assets, Net

SUBSEQUENT EVENTS (Details Narr

SUBSEQUENT EVENTS (Details Narrative) - USD ($)		1 Months Ended		12 Months Ended
	Feb. 20, 2025	Feb. 28, 2025	Jan. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Subsequent Event [Line Items]
Common stock, shares authorized				20,000,000	20,000,000
Common stock, shares issued				13,086,533	10,906,353
Options issued				82,320	60,000
Subsequent Event [Member]
Subsequent Event [Line Items]
Sale of stock number of shares issued in transaction			2,600,000
Sale of stock consideration received on transaction			$ 3,897,000
Subsequent Event [Member] | Chief Executive Officer [Member]
Subsequent Event [Line Items]
Options issued		10,638	24,202
Subsequent Event [Member] | Board [Member]
Subsequent Event [Line Items]
Options issued			24,202
Subsequent Event [Member] | Share Exchange Agreement [Member]
Subsequent Event [Line Items]
Description of share exchange agreement	Company entered into a Share Exchange Agreement with the members of Abundia Global Impact Group, LLC (“AGIG”). In the Share Exchange Agreement, the Company has agreed to issue to the members of AGIG a number of shares of our common stock equal to 94% of the Company’s issued and outstanding shares (after taking into account such issuance). As a result of entering into the Share Exchange Agreement, we will acquire all of the issued and outstanding units of AGIG, and AGIG will become a wholly-owned subsidiary of the Company. Under the Share Exchange Agreement, the Company is obligated to obtain shareholder approval for the amendment of our Certificate of Incorporation to increase the number of authorized shares of common stock to 300,000,000 and for the issuance of approximately 246,000,000 shares to the members of AGIG. The acquisition is subject to shareholder approval and standard closing conditions.
Common stock, shares authorized	300,000,000
Common stock, shares issued	246,000,000

SCHEDULE OF OIL AND GAS REVENUE

SCHEDULE OF OIL AND GAS REVENUES AND LEASE OPERATING EXPENSES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Oil and Gas, Full Cost Method, Amortization Expense [Line Items]
Revenues	$ 560,180	$ 794,027
Production Cost	747,559	473,925
North America [Member]
Oil and Gas, Full Cost Method, Amortization Expense [Line Items]
Revenues	560,180	794,027
Production Cost	747,559	473,925
South America [Member]
Oil and Gas, Full Cost Method, Amortization Expense [Line Items]
Revenues
Production Cost

CAPITALIZED COSTS AND ACCUMULAT

CAPITALIZED COSTS AND ACCUMULATED DEPLETION RELATING TO OIL AND GAS PRODUCTION ACTIVITIES (Details) - USD ($)	Dec. 31, 2024	Dec. 31, 2023
Oil and Gas, Full Cost Method, Amortization Expense [Line Items]
Unproved properties not being amortized
Proved properties being amortized	62,770,657
Accumulated depreciation, depletion, amortization and impairment	(61,653,021)	$ (61,206,942)
Net capitalized costs	1,117,636
UNITED STATES
Oil and Gas, Full Cost Method, Amortization Expense [Line Items]
Unproved properties not being amortized
Proved properties being amortized	13,326,003
Accumulated depreciation, depletion, amortization and impairment	(12,208,367)	(11,762,288)
Net capitalized costs	1,117,636
South America [Member]
Oil and Gas, Full Cost Method, Amortization Expense [Line Items]
Unproved properties not being amortized
Proved properties being amortized	49,444,654
Accumulated depreciation, depletion, amortization and impairment	(49,444,654)	$ (49,444,654)
Net capitalized costs

SCHEDULE OF PROVED DEVELOPED AN

SCHEDULE OF PROVED DEVELOPED AND UNDEVELOPED RESERVES BY PRODUCT TYPE (Details) - UNITED STATES	12 Months Ended
	Dec. 31, 2024 bbl Mcf gal	Dec. 31, 2024 bbl Mcf gal	Dec. 31, 2024 bbl Mcf gal	Dec. 31, 2023 bbl Mcf gal
Natural Gas [Member]
Oil and Gas, Full Cost Method, Amortization Expense [Line Items]
Oil and Gas, Proved Reserve, Quantity, Volume, Beginning Balance | Mcf		607,646		1,030,420
Oil and Gas, Proved Reserve, Quantity, Volume, Revision of Previous Estimate | Mcf		(214,960)		(365,414)
Oil and Gas, Proved Reserve, Quantity, Volume, Production | Mcf				(57,360)
[custom:ProvedDevelopedAndUndevelopedReservesRevisionsOfExtensionsAndDiscoveries] | Mcf		78,980
Oil and Gas, Proved Reserve, Quantity, Volume, Ending Balance | Mcf		418,190		607,646
Oil and Gas, Proved Developed Reserve, Quantity, Volume | Mcf	418,190	418,190	418,190	607,646
Oil and Gas, Proved Undeveloped Reserve, Quantity, Volume | Mcf
Oil [Member]
Oil and Gas, Full Cost Method, Amortization Expense [Line Items]
Oil and Gas, Proved Reserve, Quantity, Volume, Beginning Balance | bbl	58,599			83,517
Oil and Gas, Proved Reserve, Quantity, Volume, Revision of Previous Estimate | bbl	(23,217)			(16,947)
Oil and Gas, Proved Reserve, Quantity, Volume, Production	(5,992)	(53,476)		(7,719)
[custom:ProvedDevelopedAndUndevelopedReservesRevisionsOfExtensionsAndDiscoveries] | bbl	17,000
Oil and Gas, Proved Reserve, Quantity, Volume, Ending Balance | bbl	46,390			58,599
Oil and Gas, Proved Developed Reserve, Quantity, Volume | bbl	46,390	46,390	46,390	58,599
Oil and Gas, Proved Undeveloped Reserve, Quantity, Volume | bbl
Natural Gas Liquids (NGL) [Member]
Oil and Gas, Full Cost Method, Amortization Expense [Line Items]
Oil and Gas, Proved Reserve, Quantity, Volume, Beginning Balance | gal
Oil and Gas, Proved Reserve, Quantity, Volume, Revision of Previous Estimate | gal			1,119,316
Oil and Gas, Proved Reserve, Quantity, Volume, Production | gal			(159,680)
[custom:ProvedDevelopedAndUndevelopedReservesRevisionsOfExtensionsAndDiscoveries] | gal			502,614
Oil and Gas, Proved Reserve, Quantity, Volume, Ending Balance | gal			1,462,250
Oil and Gas, Proved Developed Reserve, Quantity, Volume | gal	1,462,250	1,462,250	1,462,250	1,621,930
Oil and Gas, Proved Undeveloped Reserve, Quantity, Volume | gal

STANDARDIZED MEASURE OF DISCOUN

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Oil and Gas, Full Cost Method, Amortization Expense [Line Items]
Future cash flows from sales of oil and gas	$ 4,427,982	$ 6,509,498
Future cash flows from sales of oil and gas	(2,400,990)	(3,804,439)
Future cash flows from sales of oil and gas	(155,628)
Future cash flows from sales of oil and gas	155,628
Future cash flows from sales of oil and gas	1,871,364	2,705,059
Future cash flows from sales of oil and gas	(748,094)	(1,140,335)
Future cash flows from sales of oil and gas	1,123,270	1,564,724	$ 5,163,159
Sales, net of production costs	39,359	(196,003)
Accretion of discount	156,472	516,316
Net change in sales and transfer price, net of production costs	(1,433,013)	(3,117,105)
Net change in future development cost
Discoveries	585,420
Revision and others	(33,056)	(645,668)
Changes in production rates and other	243,364	(155,975)
Net	(441,454)	(3,598,435)
Beginning of year	1,564,724	5,163,159
End of year	1,123,270	1,564,724
UNITED STATES
Oil and Gas, Full Cost Method, Amortization Expense [Line Items]
Future cash flows from sales of oil and gas	4,427,982	6,509,498
Future cash flows from sales of oil and gas	(2,400,990)	(3,804,439)
Future cash flows from sales of oil and gas	(155,628)
Future cash flows from sales of oil and gas	155,628
Future cash flows from sales of oil and gas	1,871,364	2,705,059
Future cash flows from sales of oil and gas	(748,094)	(1,140,335)
Future cash flows from sales of oil and gas	1,123,270	1,564,724	5,163,159
Sales, net of production costs	39,359	(196,003)
Accretion of discount	156,472	516,316
Net change in sales and transfer price, net of production costs	(1,433,013)	(3,117,105)
Net change in future development cost
Discoveries	585,420
Revision and others	(33,056)	(645,668)
Changes in production rates and other	243,364	(155,975)
Net	(441,454)	(3,598,435)
Beginning of year	1,564,724	5,163,159
End of year	1,123,270	1,564,724
South America [Member]
Oil and Gas, Full Cost Method, Amortization Expense [Line Items]
Future cash flows from sales of oil and gas
Future cash flows from sales of oil and gas
Future cash flows from sales of oil and gas
Future cash flows from sales of oil and gas
Future cash flows from sales of oil and gas
Future cash flows from sales of oil and gas
Future cash flows from sales of oil and gas
Sales, net of production costs
Accretion of discount
Net change in sales and transfer price, net of production costs
Net change in future development cost
Discoveries
Revision and others
Changes in production rates and other
Net
Beginning of year
End of year

SUPPLEMENTAL INFORMATION ON O_3

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details Narrative)	12 Months Ended
	Dec. 31, 2024 $ / shares
Oil and Gas, Full Cost Method, Amortization Expense [Line Items]
Period of average prices used in calculating proved oil and gas reserves	12 months
Minimum experience of Vice President of independent professional engineering firm	30 years
UNITED STATES
Oil and Gas, Full Cost Method, Amortization Expense [Line Items]
Amortization rate per unit	$ 10.75