NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE
1—NATURE OF COMPANY AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
Houston
American Energy Corp. (a Delaware Corporation) (“the Company” or “HUSA”) was incorporated in 2001. The Company
is engaged, as a non-operating joint owner, in the exploration, development, and production of natural gas, crude oil, and condensate
from properties. The Company’s principal properties are in the Texas Permian Basin and international holdings in Colombia, South
America, with additional holdings in Gulf Coast areas of the United States.
Consolidation
The
accompanying consolidated financial statements include all accounts of HUSA and its subsidiaries (HAEC Louisiana E&P, Inc., HAEC
Oklahoma E&P, Inc. and HAEC Caddo Lake E&P, Inc.). All significant inter-company balances and transactions have been eliminated
in consolidation.
Liquidity
and Capital Requirements
The
accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates
the realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following
the issuance date of these consolidated financial statements. The Company has incurred continuing losses since 2011, including a loss
of $744,279 for the year ended December 31, 2022. As a result of the steep global economic slowdown that began in March 2020 as the coronavirus
pandemic (“COVID-19”) spread, oil and gas demand and prices realized from oil and gas sales declined sharply. While the COVID-19
crisis has subsided and the global economy and oil and gas prices have recovered, future spikes in COVID-19 infection rates could result
in declines in global economic activity and oil and gas prices. Any such future declines in prices would adversely affect the Company’s
revenues and profitability.
During
2021 and 2022, the Company raised $6.6 million and $1.5 million, net of offering costs, from the sale of common stock. With those funds,
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 2023 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. As of December 31, 2022, the Company had $2 million remaining available from the 2022
ATM offering. 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, 2022 and 2021, the Company had no cash equivalents outstanding.
Concentration
of Credit Risk
Financial
instruments that potentially subject the Company to a concentration of credit risk include cash, cash equivalents and marketable securities
(if any). The Company had cash deposits of $4.3 million in excess of the FDIC’s current insured limit of $250,000 at December 31,
2022 for interest bearing accounts. The Company also had cash deposits of $3,665 in Colombian banks at December 31, 2022 that are not
insured by the FDIC. The Company has not experienced any losses on its deposits of cash and cash equivalents.
Revenue
Recognition
ASU
2014-09, “Revenue from Contracts with Customers (Topic 606)”. Topic 606 requires an entity to recognize revenue when
it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to
in exchange for those goods or services. The Company adopted Topic 606 on January 1, 2018, using the modified retrospective method applied
to contracts that were not completed as of January 1, 2018. Under the modified retrospective method, prior period financial positions
and results are not adjusted. The cumulative effect adjustment recognized in the opening balances included no significant changes as
a result of this adoption. While the Company’s 2018 net earnings were not materially impacted by revenue recognition timing changes,
Topic 606 requires certain changes to the presentation of revenues and related expenses beginning January 1, 2018. Refer to Note 2 –
Revenue from Contracts with Customers for additional information.
The
Company’s revenue is comprised principally of revenue from exploration and production activities. The Company’s oil is sold
primarily to marketers, gatherers, and refiners. Natural gas is sold primarily to interstate and intrastate natural-gas pipelines, direct
end-users, industrial users, local distribution companies, and natural-gas marketers. 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.
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, 2022 and 2021, 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, | |
| | |
2022 | | |
2021 | |
| Stock warrants | |
| 94,400 | | |
| 98,400 | |
| Stock options | |
| 944,177 | | |
| 990,177 | |
| Totals | |
| 1,038,577 | | |
| 1,088,577 | |
Accounts
Receivable
Accounts
receivable – other and escrow receivables have been evaluated for collectability and are recorded at their net realizable values.
Allowance
for Accounts Receivable
The
Company regularly reviews outstanding receivables and provides for estimated losses through an allowance for doubtful accounts when necessary.
In evaluating the need for an allowance, the Company makes judgments regarding its customers’ ability to make required payments,
economic events and other factors. As the financial condition of these parties change, circumstances develop or additional information
becomes available, an allowance for doubtful accounts may be required. When the Company determines that a customer may not be able to
make required payments, the Company increases the allowance through a charge to income in the period in which that determination is made.
As of December 31, 2022 and 2021, the Company evaluated their receivables and determined that no allowance was necessary.
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 $194,392 and $245,606 for the years ended December 31, 2022 and 2021, respectively,
and accumulated amortization, depreciation and impairment was $60,501,999 and $60,306,590 at December 31, 2022 and 2021, respectively.
Costs
Excluded
Oil
and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent costs of investments
in unproved properties. The Company excludes these costs on a country-by-country basis until proved reserves are found or until it is
determined that the costs are impaired. All costs excluded are reviewed quarterly to determine if impairment has occurred. The amount
of any impairment is transferred to the costs subject to amortization.
Ceiling
Test
Under
the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed
by SEC Regulation S-X. The ceiling test determines a limit, on a country-by-country basis, on the book value of oil and gas properties.
The capitalized costs of proved oil and gas properties, net of accumulated depreciation, depletion, amortization and impairment (“DD&A”)
and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, calculated
for 2022 and 2021 using the average oil and natural gas sales price received by the Company as of the first trading day of each month
over the preceding twelve months (such prices are held constant throughout the life of the properties) with consideration of price change
only to the extent provided by contractual arrangement, discounted at 10%, net of related tax effects. If capitalized costs exceed this
limit, the excess is charged to expense and reflected as additional accumulated DD&A. During 2022 and 2021, the Company recorded
no impairments of oil and gas properties.
Furniture
and Equipment
Office
equipment is stated at original cost and is depreciated on the straight-line basis over the useful life of the assets, which ranges from
three to five years.
Office
equipment having an original cost basis of $90,004 was fully depreciated as of January 1, 2020. Therefore, accumulated depreciation was
$90,004 and $90,004 at December 31, 2022 and 2021, respectively.
Cost
Method
Businesses
not accounted for under either the consolidation method or equity method
of accounting are accounted for under the cost method of accounting and are further discussed in Note 3, “Oil and Gas Properties.”
The Company’s share of the earnings and/or losses of cost method businesses is not included in the Consolidated Statements of Operations.
Income from cost method investments is only realized if and when distributions are made from the cost method business to its investors.
However, impairment charges related to cost method businesses are recognized in the company’s Consolidated Statements of Operations.
If circumstances suggest that the value of a cost method business 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 cost method businesses are reflected in the line
item “Cost method investment” in the Company’s Consolidated Balance Sheets.
Asset
Retirement Obligations
For
the Company, asset retirement obligations (“ARO”) represent the systematic, monthly accretion and depreciation of future
abandonment costs of tangible assets such as platforms, wells, service assets, pipelines, and other facilities. The fair value of a liability
for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can
be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability
is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset.
If the liability is settled for an amount other than the recorded amount, an adjustment is made to the full cost pool, with no gain or
loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. Although
the Company’s domestic policy with respect to ARO is to assign depleted wells to a salvager for the assumption of abandonment obligations
before the wells have reached their economic limits, the Company has estimated its future ARO obligation with respect to its domestic
operations. The ARO assets, which are carried on the balance sheet as part of the full cost pool, have been included in our amortization
base for the purposes of calculating depreciation, depletion and amortization expense. For the purposes of calculating the ceiling test,
the future cash outflows associated with settling the ARO liability have been included in the computation of the discounted present value
of estimated future net revenues. Asset retirement obligations are classified as Level 3 (unobservable inputs) fair value measurements.
Joint
Venture Expense
Joint
venture expense reflects the indirect field operating and regional administrative expenses billed by the operator of the Colombian concessions.
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, 2022 and 2021.
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”)
and concessions operated by Hupecol 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 drilling operations and substantially all of
its oil and gas investments in 2022 and 2021. In the event of a significant negative change in operations or operating outlook pertaining
to the Company’s Permian Basin properties, the Company may be forced to abandon or suspend such operations, which abandonment or
suspension could be materially harmful to the Company.
Additionally,
the Company currently has interests in concessions in Colombia and expects to be active in Colombia for the foreseeable future. The political
climate in Colombia is unstable and could be subject to radical change over a very short period of time. In the event of a significant
negative change in political and economic stability in the vicinity of the Company’s Colombian operations, the Company may be forced
to abandon or suspend its efforts. Either of such events could be harmful to the Company’s expected business prospects.
For
2022, the Company’s oil production from the its mineral interests was sold to U.S. oil marketing companies based on the highest
bid. The gas production is sold to U.S. natural gas marketing companies based on the highest bid. No purchaser accounted for more than
10% of our oil and gas sales.
The
Company reviews accounts receivable balances when circumstances indicate a balance may not be collectible. Based upon the Company’s
review, no allowance for uncollectible accounts was deemed necessary at December 31, 2022 and 2021, respectively.
Recent
Accounting Developments
The
Company does not expect the adoption of any recently issued accounting pronouncements to have a significant impact on its financial position,
results of operations, or cash flows.
Subsequent
Events
The
Company evaluated subsequent events for disclosure from December 31, 2022 through the date the consolidated financial statements were
issued.
NOTE
2—REVENUE FROM CONTRACTS WITH CUSTOMERS
Disaggregation
of Revenue from Contracts with Customers
The
following table disaggregates revenue by significant product type for the years ended December 31, 2022 and 2021:
SCHEDULE OF DISAGGREGATES REVENUE BY SIGNIFICANT PRODUCT
| | |
2022 | | |
2021 | |
| | |
Year Ended December 31, | |
| | |
2022 | | |
2021 | |
| Oil sales | |
$ | 995,083 | | |
$ | 913,809 | |
| Natural gas sales | |
| 377,534 | | |
| 247,992 | |
| Natural gas liquids sales | |
| 266,224 | | |
| 168,397 | |
| Total revenue from customers | |
$ | 1,638,841 | | |
$ | 1,330,198 | |
There
were no significant contract liabilities or transaction price allocations to any remaining performance obligations as of December 31,
2022 or 2021.
NOTE
3—OIL AND GAS PROPERTIES
Evaluated
Oil and Gas Properties
Evaluated
oil and gas properties subject to amortization at December 31, 2022 included the following:
SCHEDULE OF EVALUATED OIL AND GAS PROPERTIES SUBJECT TO AMORTIZATION
| | |
United States | | |
South America | | |
Total | |
| | |
| | |
| | |
| |
| Evaluated properties being amortized | |
$ | 13,331,565 | | |
$ | 49,444,654 | | |
$ | 62,776,219 | |
| Accumulated depreciation, depletion, amortization and impairment | |
| (11,057,345 | ) | |
| (49,444,654 | ) | |
| (60,501,999 | ) |
| Net capitalized costs | |
$ | 2,274,220 | | |
$ | — | | |
$ | 2,274,220 | |
Evaluated
oil and gas properties subject to amortization at December 31, 2021 included the following:
| | |
United States | | |
South America | | |
Total | |
| | |
| | |
| | |
| |
| Evaluated properties being amortized | |
$ | 13,326,568 | | |
$ | 49,444,654 | | |
$ | 62,771,222 | |
| Accumulated depreciation, depletion, amortization and impairment | |
| (10,861,936 | ) | |
| (49,444,654 | ) | |
| (60,306,590 | ) |
| Net capitalized costs | |
$ | 2,464,632 | | |
$ | — | | |
$ | 2,464,632 | |
Unevaluated
Oil and Gas Properties
Unevaluated
oil and gas properties not subject to amortization at December 31, 2022 included the following:
SCHEDULE OF UNEVALUATED OIL AND GAS
PROPERTIES NOT SUBJECT TO AMORTIZATION
| | |
United States | | |
South America | | |
Total | |
| | |
| | |
| | |
| |
| Leasehold acquisition costs | |
$ | — | | |
$ | 143,847 | | |
$ | 143,847 | |
| Geological, geophysical, screening and evaluation costs | |
| — | | |
| 2,199,279 | | |
| 2,199,279 | |
| Total | |
$ | — | | |
$ | 2,343,126 | | |
$ | 2,343,126 | |
Unevaluated
oil and gas properties not subject to amortization at December 31, 2021 included the following:
| | |
United States | | |
South America | | |
Total | |
| | |
| | |
| | |
| |
| Leasehold acquisition costs | |
$ | — | | |
$ | 143,847 | | |
$ | 143,847 | |
| Geological, geophysical, screening and evaluation costs | |
| — | | |
| 2,199,279 | | |
| 2,199,279 | |
| Total | |
$ | — | | |
$ | 2,343,126 | | |
$ | 2,343,126 | |
During
2022, the Company invested $1,661,405
for the acquisition and development of oil and gas properties, consisting of (1) drilling and development operations in the U.S.
Permian Basin ($15,045)
which have been classified as oil and gas properties subject to amortization, and (2) acquisition of additional interest in Hupecol
Meta LLC (“Hupecol Meta”) ($657,638)
and direct investments in Hupecol Meta relating to drilling operations in Colombia ($988,722).
Of the amount invested, we capitalized $15,045
to oil and gas properties subject to amortization and capitalized $1,646,360
as additional investment in Hupecol Meta, reflected in the cost method investment on the Company’s balance sheet. During 2021,
the Company capitalized $42,806
to oil and gas properties subject to amortization. See Note 4—Cost Method Investment for additional information
on the Company’s investment in Hupecol Meta.
NOTE
4—Cost Method Investment
The
Company’s carrying value of its holdings in cost method investment was $2.1 million and $0.5 million as of December 31, 2022 and
2021, respectively, as reflected in the line item “Cost method investment” in the company’s Consolidated Balance Sheets.
During
the year ended December 31, 2022, the Company paid $657,638 to increase its ownership interest in Hupecol Meta, to approximately 18%.
During 2022, the Company also made direct investments in Hupecol Meta of $988,722 for required capital contributions.
During
the year ended December 31, 2021, the Company contributed $99,716 to Hupecol Meta, increasing its ownership interest to 7.85%. During
2021, the Company also made direct investments in Hupecol Meta of $195,374 for required capital contributions.
Impairments
The
Company performs annual business reviews of its cost method investments to determine whether the carrying value in that investment is
impaired. The Company determined its carrying value in its cost method business was not impaired during the years ended December 31,
2022 and 2021.
NOTE
5—ASSET RETIREMENT OBLIGATIONS
The
following table describes changes in our asset retirement liability (“ARO”) during each of the years ended December 31,
2022 and 2021.
SCHEDULE OF CHANGES IN OUR ASSET RETIREMENT LIABILITY
| | |
2022 | | |
2021 | |
| | |
| | |
| |
| ARO liability at January 1 | |
$ | 68,209 | | |
$ | 63,929 | |
| Additions from new drilling | |
| — | | |
| — | |
| Dispositions from sales of oil and gas properties | |
| — | | |
| — | |
| Changes in estimates | |
| — | | |
| — | |
| Accretion expense | |
| 4,580 | | |
| 4,280 | |
| | |
| | | |
| | |
| ARO liability at December 31 | |
$ | 72,879 | | |
$ | 68,209 | |
NOTE
6—STOCK-BASED COMPENSATION
In
2008, the Company adopted the Houston American Energy Corp. 2008 Equity Incentive Plan (the “2008 Plan”). The terms of the
2008 Plan, as amended in 2012 and 2013, allow for the issuance of up to 480,000 shares of the Company’s common stock pursuant to
the grant of stock options and restricted stock.
In
2017, the Company adopted the Houston American Energy Corp. 2017 Equity Incentive Plan (the “2017 Plan”). The terms of the
2017 Plan allow for the issuance of up to 400,000 shares of the Company’s common stock pursuant to the grant of stock options and
restricted stock. Persons eligible to participate in the Plans are key employees, consultants and directors of the Company.
In
2021, the Company adopted the Houston American Energy 2021 Equity Incentive Plan (the “2021 Plan” and, together with the
2008 Plan and the 2017 Plan, the “Plans”). The terms of the 2021 Plan allow for the issuance of up to 500,000 shares of the
Company’s common stock pursuant to the grant of stock options and restricted stock. Persons eligible to participate in the Plans
are key employees, consultants and directors of the Company.
Stock
Option Activity
In
June 2021, options to purchase an aggregate of 210,000 shares of the Company’s common stock were granted to the Company’s
directors and sole officer. The options have a ten-year life and are exercisable at $1.77 per share. The 60,000 aggregate options granted
to directors vest 20% on the date of grant and 80% ten months from the date of grant. The 150,000 options granted to the Company’s
sole officer vest one year from the date of grant. The grant date fair value of these stock options was $340,308 based on the Black-Scholes
Option Pricing model based on the following assumptions: market value of common stock on grant date – $1.77; risk free interest
rate based on the applicable US Treasury bill rate – 1.27%; dividend yield – 0%; volatility factor based on the trading history
of the Company – 107.2%; weighted average expected life in years – 10; and expected forfeiture rate – 0%.
Additionally,
in June 2021, options to purchase 54,000 shares of the Company’s common stock, granted in November 2020 subject to shareholder
approval of the Company’s 2021 Plan, received the requisite approval of shareholders and are treated as granted during 2021. The
options have a ten-year life, are exercisable at $1.45 per share and vested in full on shareholder approval of the 2021 Plan. The
grant date fair value of these stock options was $70,279 based on the Black-Scholes Option Pricing model based on the following assumptions:
market value of common stock on grant date – $1.45; risk free interest rate based on the applicable US Treasury bill rate - 0%;
dividend yield – 0%; volatility factor based on the trading history of the Company – 103.3%; weighted average expected life
in years – 10; and expected forfeiture rate – 0%.
In
September 2022, options to purchase an aggregate of 60,000 shares of common stock were granted to the Company’s directors. The
options have a ten-year life and are exercisable at $3.91 per share. The options vest 20% on the date of grant and 80% nine months from
the date of grant. The grant date fair value of these stock options was $216,326 based on the Black-Scholes Option Pricing model with
the following parameters: (1) risk-free interest rate of 0% based on the applicable US Treasury bill rate; (2) expected life in years
of 10; (3) expected stock volatility of 121% based on the trading history of the Company; and (4) expected dividend yield of 0%. The
Company determined the options qualified as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was
used to estimate the expected option life.
Option
activity during 2022 and 2021 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, 2020 | |
| 730,973 | | |
$ | 5.07 | | |
| | | |
| | |
| Granted(1) | |
| 264,000 | | |
$ | 1.70 | | |
| | | |
| | |
| Forfeited | |
| (4,800 | ) | |
$ | 167.81 | | |
| | | |
| | |
| | |
| | | |
| | | |
| | | |
| | |
| Outstanding at December 31, 2021 | |
| 990,177 | | |
| 3.38 | | |
| | | |
| | |
| Granted | |
| 60,000 | | |
| 3.91 | | |
| | | |
| | |
| Exercised | |
| (48,000 | ) | |
| 3.84 | | |
| | | |
| | |
| Forfeited | |
| (58,000 | ) | |
| 20.43 | | |
| | | |
| | |
| | |
| | | |
| | | |
| | | |
| | |
| Outstanding at December 31, 2022 | |
| 944,177 | | |
$ | 2.08 | | |
| 7.85 | | |
$ | 1,025,655 | |
| Exercisable at December 31, 2022 | |
| 896,177 | | |
$ | 1.92 | | |
| 7.68 | | |
$ | 1,025,655 | |
| |
(1) |
54,000
options granted in November 2020 under the Company’s 2021 Plan pending shareholder approval were excluded from grants during
2020 and included in grants during 2021 when the 2021 Plan was approved by shareholders. |
During
2022 and 2021, the Company recognized $206,210 and $323,611, respectively, of stock-based compensation expense attributable to a stock
grant and outstanding stock option grants, including current period grants and unamortized expense associated with prior period grants.
As
of December 31, 2022, non-vested options totaled 48,000 and total unrecognized stock-based compensation expense related to non-vested
stock options was $163,735. The related unrecognized expense is expected to be recognized over a weighted average period of 2.08 years.
The weighted average remaining contractual term of the outstanding options and exercisable options at December 31, 2022 is 7.85 years
and 7.68 years, respectively.
As
of December 31, 2022, there were 181,333 shares of common stock available for issuance pursuant to future stock or option grants under
the Plans.
During
the year ended December 31, 2022, stock options covering 48,000 shares of common stock were issued pursuant to a cashless exercise resulting
in the issuance of 4,630 shares of common stock.
Stock-Based
Compensation Expense
During
2021, a non-executive employee was granted 5,000 shares of the Company’s common stock as compensation for services with a grant
date fair value of $10,825 based on the market price of the Company’s common stock on the grant date.
The
following table reflects stock-based compensation recorded by the Company for 2022 and 2021:
SCHEDULE OF STOCK-BASED COMPENSATION
| | |
2021 | | |
2021 | |
| | |
| | |
| |
| Stock-based compensation expense from stock options and common stock included in general and administrative expense | |
$ | 206,210 | | |
$ | 323,611 | |
| Earnings per share effect of stock-based compensation expense | |
$ | (0.02 | ) | |
$ | (0.03 | ) |
NOTE
7—CAPITAL STOCK
Common
Stock - At-the-Market Offerings
In
January 2021, the Company entered into an At-the-Market Issuance Sales Agreement (the “Sales Agreement”) with Univest Securities,
LLC (“Univest”) pursuant to which the Company could sell (the “2021 ATM Offering”), at its option, up to an aggregate
of $4.768 million in shares of its common stock through Univest, as sales agent. Sales of shares under the Sales Agreement (the “2021
ATM Offering”) were made, in accordance with placement notices delivered to Univest, which notices set parameters under which shares
could be sold. The 2021 ATM Offering was made pursuant to a shelf registration statement by methods deemed to be “at the market,”
as defined in Rule 415 promulgated under the Securities Act of 1933. The Company paid Univest a commission in cash equal to 3% of the
gross proceeds from the sale of shares in the 2021 ATM Offering. The Company reimbursed Univest for $18,000 of expenses incurred in connection
with the 2021 ATM Offering.
In
January 2021, the Company sold an aggregate of 2,108,520 shares in connection with the 2021 ATM Offering and received proceeds, net of
commissions and expenses, of $4.6 million.
In
February 2021, the Company entered into another Sales Agreement with Univest pursuant to which the Company could sell (the “2021
Supplemental ATM Offering”), at its option, up to an aggregate of $2.03 million in shares of its common stock through Univest,
as sales agent. Sales of shares under the Sales Agreement (the “2021 Supplemental ATM Offering”) were made, in accordance
with placement notices delivered to Univest, which notices set parameters under which shares could be sold. The 2021 Supplemental ATM
Offering was made pursuant to a shelf registration statement by methods deemed to be “at the market,” as defined in Rule
415 promulgated under the Securities Act of 1933. The Company paid Univest a commission in cash equal to 3% of the gross proceeds from
the sale of shares in the 2021 Supplemental ATM Offering. The Company reimbursed Univest for $18,000 of expenses incurred in connection
with the 2021 Supplemental ATM Offering.
In
February 2021, the Company sold an aggregate of 813,100 shares in connection with the 2021 Supplemental ATM Offering and received proceeds,
net of commissions and expenses, of $2.0 million.
In
November 2022, the Company entered into another Sales Agreement with Univest pursuant to which the Company could sell (the “2022
ATM Offering”), at its option, up to an aggregate of $3.5 million in shares of its common stock through Univest, as sales agent.
Sales of shares under the Sales Agreement (the “2022 Supplemental ATM Offering”) were made, in accordance with placement
notices delivered to Univest, which notices set parameters under which shares could be sold. The 2022 ATM Offering was made pursuant
to a shelf registration statement by methods deemed to be “at the market,” as defined in Rule 415 promulgated under the Securities
Act of 1933. The Company paid Univest a commission in cash equal to 3% of the gross proceeds from the sale of shares in the 2022 ATM
Offering. The Company reimbursed Univest for $25,000 of expenses incurred in connection with the 2022 ATM Offering.
In
December 2022, the Company sold an aggregate of 394,678 shares in connection with the 2022 ATM Offering and received proceeds, net of
commissions and expenses, of $1.5 million.
Preferred
Stock
The
Company has authorized 10,000,000 shares of preferred stock with a par value of $0.001. The Board of Directors shall determine the designations,
rights, preferences, privileges and voting rights of the preferred stock as well as any restrictions and qualifications thereon. As of
December 31, 2022, the Company had no shares of preferred stock issued and outstanding.
Series
A Convertible Preferred Stock
In
January 2017, the Company issued 1,200 shares of 12% Series A Convertible Preferred Stock (the “Series A Preferred Stock”)
for aggregate gross proceeds of $1.2 million. The Series A Preferred Stock (i) accrued a cumulative dividend, commencing July 1, 2017,
at 12% payable, if and when declared, quarterly; (ii) was convertible at the option of the holder into shares of common stock at a conversion
price of $2.50 per share, (iii) had a liquidation preference of $1,000 per share plus accrued and unpaid dividends; and (iv) was redeemable
at the Company’s option, commencing on the second anniversary of the issue date, at a premium to issue price, which premium decreases
from 12% to 0% following the fifth anniversary of the issue date, plus accrued and unpaid dividends.
During
2022 and 2021, respectively, the Company paid $0 and $21,501 of dividends on its Series A Preferred Stock.
In
February 2021, 60 shares of Series A Preferred Stock were converted into 24,000 shares of common stock, and the Company redeemed all
outstanding shares of Series A Preferred Stock for cash paid of $1.07 million plus accrued dividends totaling $21,501.
Series
B Convertible Preferred Stock
In
May 2017, the Company received $909,600 from the sale of 909.6 Units (the “Units”), each Unit consisting of one share of
12.0% Series B Convertible Preferred Stock (the “Series B Preferred Stock”) and a Warrant (the “Series B Warrant”).
The Series B Preferred Stock (i) accrued a cumulative dividend at 12% payable, if and when declared, quarterly; (ii) was convertible
at the option of the holder into shares of common stock at a conversion price of $4.50 per share, (iii) had a liquidation preference
of $1,000 per share plus accrued and unpaid dividends; and (iv) was redeemable at the Company’s option, commencing on the second
anniversary of the issue date, at a premium to issue price, which premium decreases from 12% to 0% following the fifth anniversary of
the issue date, plus accrued and unpaid dividends.
During
2022 and 2021, respectively, the Company paid $0 and $16,700 of dividends on its Series B Preferred Stock.
In
February 2021, the Company redeemed all outstanding shares of Series B Preferred Stock for cash paid of $0.9 million plus accrued dividends
of $16,700.
Warrants
Consultant
Warrants. In September 2017, the Company issued warrants (the “Consultant Warrants”) to a consultant. The Consultant
Warrants were exercisable to purchase 4,000 shares of common stock at $6.875 per share and expired on December 31, 2021. The relative
value of the warrants were valued on the date of grant at $16,132 using the Black-Scholes option-pricing model with the following parameters:
(1) risk-free interest rate of 1.63% based on the applicable US Treasury bill rate; (2) expected life in years of 4.32; (3) expected
stock volatility of 99.75% based on the trading history of the Company; and (4) expected dividend yield of 0%. The Company recognized
$0 of stock-based compensation expense related to the vesting of the Consultant Warrants during each of the years ended December 31,
2022 and 2021.
Bridge
Loan Warrants. In September 2019, the Company issued the warrants in conjunction with a bridge loan. The Bridge Loan Warrants
are exercisable, for a period of ten years, expiring September 18, 2029, to purchase an aggregate of 94,400 shares of common stock of
the Company at $2.50 per share. The relative fair value of the warrants was determined on the date of grant at $144,948 using the Black
Scholes option-pricing model with the following parameters: (1) risk free interest rate of 1.80% based on the applicable US Treasury
bill rate; (2) expected life in years of 10.0; (3) expected stock volatility of 82.9% based on the trading history of the Company; and
(4) expected dividend yield of 0%. The relative fair value of the warrants was recorded as debt discount on the Bridge Loan Notes and
was amortized as additional interest expense over the term of the notes.
A
summary of warrant activity and related information for 2022 and 2021 is presented below:
SUMMARY OF WARRANT ACTIVITY
| | |
Warrants | | |
Weighted-Average Exercise Price | | |
Aggregate Intrinsic Value | |
| | |
| | |
| | |
| |
| Outstanding at December 31, 2020 | |
| 98,400 | | |
$ | 2.63 | | |
| | |
| Issued | |
| — | | |
| — | | |
| | |
| Exercised | |
| — | | |
| — | | |
| | |
| Expired | |
| 4,000 | | |
$ | 6.88 | | |
| | |
| Outstanding at December 31, 2021 | |
| 94,400 | | |
$ | 2.50 | | |
| | |
| Issued | |
| — | | |
| — | | |
| | |
| Exercised | |
| — | | |
| — | | |
| | |
| Expired | |
| — | | |
| — | | |
| | |
| Outstanding at December 31, 2022 | |
| 94,400 | | |
$ | 2.50 | | |
$ | — | |
| Exercisable at December 31, 2022 | |
| 94,400 | | |
$ | 2.50 | | |
$ | — | |
NOTE
8—TAXES
The
following table sets forth a reconciliation of the statutory federal income tax for the years ended December 31, 2022 and 2021.
SCHEDULE
OF RECONCILIATION OF STATUTORY FEDERAL INCOME TAX
| | |
2022 | | |
2021 | |
| | |
| | |
| |
| | |
| | | |
| | |
| Income tax expense (benefit) computed at statutory rates | |
$ | (156,299 | ) | |
$ | (214,521 | ) |
| Permanent differences, nondeductible expenses | |
| 10,439 | | |
| 10,484 | |
| Increase (decrease) in valuation allowance | |
| (189,914 | ) | |
| (75,989 | ) |
| State and Local Taxes | |
| 3,003 | | |
| — | |
| Other adjustment | |
| 369,680 | | |
| 227,752 | |
| Deferred True-Up | |
| (33,082 | ) | |
| 48,276 | |
| ASC 842 lease standard adoption | |
| — | | |
| 3,998 | |
| Tax provision | |
$ | 3,827 | | |
$ | — | |
| | |
| | | |
| | |
| Total provision | |
| | | |
| | |
| Foreign | |
$ | — | | |
$ | — | |
| Total provision (benefit) | |
$ | 3,827 | | |
$ | — | |
At
December 31, 2022 the Company has a federal tax loss carry forward of $11,889,216 and a foreign tax credit carry forward of $27,745,
both of which have been fully reserved.
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, 2022 and 2021 are set out below.
SIGNIFICANT
COMPONENTS OF DEFERRED TAX ASSET AND LIABILITY
| | |
2022 | | |
2021 | |
| Non-Current Deferred tax assets: | |
| | | |
| | |
| Net operating loss carry forward | |
$ | 11,912,710 | | |
$ | 11,814,489 | |
| Foreign tax credit carry forward | |
| 27,745 | | |
| 394,745 | |
| Deferred state tax | |
| — | | |
| — | |
| Stock compensation | |
| 425,860 | | |
| 433,104 | |
| Book in excess of tax depreciation, depletion and capitalization methods on oil and gas properties | |
| (3,458 | ) | |
| (38,124 | ) |
| Other | |
| (174,401 | ) | |
| (225,368 | ) |
| ASC 842 lease standard – building lease | |
| (4 | ) | |
| (481 | ) |
| Pass-through investment | |
| — | | |
| — | |
| Total Non-Current Deferred tax assets | |
| 12,188,452 | | |
| 12,378,366 | |
| Valuation Allowance | |
| (12,188,452 | ) | |
| (12,378,366 | ) |
| Net deferred tax asset | |
$ | — | | |
$ | — | |
Schedule
of Net Operating Loss Carryforwards
The
Company is currently subject to a three-year statute of limitation for federal tax purposes and, in general, three to four-year statute
of limitation for state tax purposes. State NOL expiration will occur beginning in 2033 and Federal NOL expiration
will begin in 2032.
Under
the Tax Cuts and Jobs Act of 2017, net operating losses incurred for tax years beginning after December 31, 2017 will have no expiration
date but utilization will be limited to 80% of taxable income. For losses generated prior to January 1, 2018, there will be no limitation
on the utilization, but there is an expiration on the carryforward of 20 years for federal tax purposes.
The
provisions were subsequently amended further under the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) on
March 27, 2020. The CARES Act amended the net operating loss provisions in the 2017 Tax Cuts and Jobs Act (“TCJA”) and allows
for the carryback of NOL’s arising in the taxable years ending December 31, 2017 and before January 1, 2021, to each of the five
taxable years preceding the taxable year of the loss. Additionally, the 80% limitation related to application of NOL’s towards
current federal taxable income has been removed for taxable years prior to January 1, 2021; thereby allowing 100% of the NOL to be applied
to federal taxable income.
To the best of the Company’s knowledge, Hupecol Meta has made all requisite filings relative to its operations, including those
in Colombia, and that there are no known or expected tax issues, payments due, or judgments related to Hupecol Meta that would adversely
impact the Company’s cost method investment therein.
NOTE
9—COMMITMENTS AND CONTINGENCIES
Lease
Commitment
The
Company leases office facilities under an operating lease agreement that expires October 31, 2025. During the year ended December 31,
2022, the operating cash outflows related to operating lease liabilities were $86,373 and the expense for the amortization of the right
of use asset for operating leases was $59,445. As of December 31, 2022, the Company’s operating lease had a weighted-average remaining
term of 2.8 years and a weighted average discount rate of 12%. Below is a summary of the Company’s right of use assets and liabilities
as of December 31, 2022:
SCHEDULE OF FUTURE PAYMENTS UNDER LEASE AGREEMENT
| Right of use asset | |
$ | 212,202 | |
| | |
| |
| Year | |
Amount | |
| 2023 | |
$ | 87,288 | |
| 2024 | |
| 88,801 | |
| 2025 | |
| 75,051 | |
| Total future lease payments | |
| 251,140 | |
| Less: imputed interest | |
| 39,396 | |
| Present value of future operating lease payments | |
| 211,744 | |
| Less: current portion of operating lease liabilities | |
| (65,385 | ) |
| Long-term operating lease liability | |
$ | 146,359 | |
During
the years ended December 31, 2022 and 2021, the Company recognized operating lease expense of $86,644 and $80,998, respectively, which
is included in general and administrative expenses in the Company’s consolidated statements of operations. The Company does not
have any capital leases or other operating lease commitments.
Legal
Contingencies
The
Company is subject to legal proceedings, claims and liabilities that arise in the ordinary course of its business. The Company accrues
for losses associated with legal claims when such losses are probable and can be reasonably estimated. These accruals are adjusted as
further information develops or circumstances change.
Environmental
Contingencies
The
Company’s oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the
release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may
require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can
be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain
lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our
operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties,
incurrence of investigatory or remedial obligations or the imposition of injunctive relief. Changes in environmental laws and regulations
occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements
could require the Company to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on
its results of operations, competitive position or financial condition as well as the industry in general. Under these environmental
laws and regulations, the Company could be held strictly liable for the removal or remediation of previously released materials or property
contamination regardless of whether the Company was responsible for the release or if its operations were standard in the industry at
the time they were performed. The Company maintains insurance coverage, which it believes is customary in the industry, although the
Company is not fully insured against all environmental risks.
Development
Commitments
During
the ordinary course of oil and gas prospect development, the Company commits to a proportionate share for the cost of acquiring mineral
interests, drilling exploratory or development wells and acquiring seismic and geological information.
Production
Incentive Arrangements and ORRIs
In
conjunction with our efforts to secure oil and gas prospects, financing and services, we have, from time to time, granted overriding
royalty interests (“ORRI”) in various properties and have adopted a Production Incentive Compensation Plan under which grant
interests in pools, which may take the form of ORRIs, to provide additional incentive identify and secure attractive oil and gas properties.
Production
Incentive Compensation Plan. In August 2013, the Company’s compensation committee adopted a Production Incentive Compensation
Plan. The purpose of the Plan is to encourage employees and consultants participating in the Plan to identify and secure for the Company
participation in attractive oil and gas opportunities.
Under
that Plan, the committee may establish one or more Pools and designate employees and consultants to participate in those Pools and designate
prospects and wells, and a defined percentage of the Company’s revenues from those wells, to fund those Pools. Only prospects acquired
on or after establishment of the Plan, and excluding all prospects in Colombia, may be designated to fund a Pool. The maximum percentage
of the Company’s share of revenues from a well that may be designated to fund a Pool is 2% (the “Pool Cap”); provided,
however, that with respect to wells with a net revenue interest to the 8/8 of less than 73%, the Pool Cap with respect to such wells
shall be reduced on a 1-for-1 basis such that no portion of the Company’s revenues from a well may be designated to fund a Pool
if the NRI is 71% or less.
Designated
participants in a Pool will be assigned a specific percentage out of the Company’s revenues assigned to the Pool and will be paid
that percentage of such revenues from all wells designated to such Pool and spud during that participant’s employment or services
with the Company. In no event may the percentage assigned to the Company’s chief executive officer relative to any well within
a Pool exceed one-half of the applicable Pool Cap for that well. Payouts of revenues funded into Pools shall be made to participants
not later than 60 days following year end, subject to the committee’s right to make partial interim payouts. Participants will
continue to receive their percentage share of revenues from wells included in a Pool and spud during the term of their employment or
service so long as revenues continue to be derived by the Company from those wells even after termination of employment or services of
the Participant; provided, however, that a participant’s interest in all Pools shall terminate on the date of termination of employment
or services where such termination is for cause.
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
2022, no pools were established under the Plan.
The
Company records amounts payable under the plan as a reduction to revenue as revenues are recognized from prospects included in pools
covered by the plan based on the participants’ interest in such prospect revenues and records the same as accounts payable until
such time as such amounts are paid out.
ORRI
Grants. All present and future prospects in Colombia are subject to a 1.5% ORRI in favor of each of our Chairman and Chief Executive
Officer and a former director.
Payments
made by the Company under the Plan and ORRI’s totaled $17,725 and $15,081 in 2022 and 2021, respectively. As of December 31, 2022
and 2021, the Company had accrued $0 and $0, respectively, under the Plan as accounts payable.
NOTE
10—SUBSEQUENT EVENTS
Subsequent
to December 31, 2022, and through the date of this report, the Company issued a total of 294,872
shares of common stock under the 2022 ATM Offering
for proceeds, net of commissions and offering expenses, of $874,309.
NOTE
11—GEOGRAPHICAL INFORMATION
The
Company currently has operations in two geographical areas, the United States and Colombia. Revenues for the years ended December 31,
2022 and 2021 and long-lived assets as of December 31, 2022 and 2021 attributable to each geographical area are presented below:
SCHEDULE
OF REVENUES AND LONG LIVED ASSETS ATTRIBUTABLE TO GEOGRAPHICAL AREA
| | |
2022 | | |
2021 | |
| | |
Revenues | | |
Long Lived Assets, Net | | |
Revenues | | |
Long Lived Assets, Net | |
| North America | |
$ | 1,638,841 | | |
$ | 2,274,220 | | |
$ | 1,330,198 | | |
$ | 2,464,632 | |
| South America | |
| — | | |
| 2,343,126 | | |
| — | | |
| 2,343,126 | |
| Total | |
$ | 1,638,841 | | |
$ | 4,617,346 | | |
$ | 1,330,198 | | |
$ | 4,807,758 | |
NOTE
12—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
| | |
| 2022 | | |
| 2021 | |
| Revenues | |
| | | |
| | |
| North America | |
$ | 1,638,841 | | |
$ | 1,330,198 | |
| South America | |
| — | | |
| — | |
| | |
| | | |
| | |
| | |
$ | 1,638,841 | | |
$ | 1,330,198 | |
| | |
| | | |
| | |
| Production Cost | |
| | | |
| | |
| North America | |
$ | 631,033 | | |
$ | 626,210 | |
| South America | |
| — | | |
| — | |
| | |
| | | |
| | |
| | |
$ | 631,033 | | |
$ | 626,210 | |
Capital
Costs
Capitalized
costs and accumulated depletion relating to the Company’s oil and gas producing activities as of December 31, 2022, 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 | |
$ | — | | |
$ | 2,343,126 | | |
$ | 2,343,126 | |
| Proved properties being amortized | |
| 13,331,565 | | |
| 49,444,654 | | |
| 62,776,219 | |
| Accumulated depreciation, depletion, amortization and impairment | |
| (11,057,345 | ) | |
| (49,444,654 | ) | |
| (60,501,999 | ) |
| | |
| | | |
| | | |
| | |
| Net capitalized costs | |
$ | 2,274,220 | | |
$ | 2,343,126 | | |
$ | 4,617,346 | |
Amortization
Rate
The
amortization rate per unit based on barrel of oil equivalents was $8.95 for the United States for the year ended December 31, 2022.
Acquisition,
Exploration and Development Costs Incurred
Costs
incurred in oil and gas property acquisition, exploration and development activities as of December 31, 2022 and 2021 are summarized
below:
COSTS
INCURRED IN OIL AND GAS PROPERTY ACQUISITION , EXPLORATION AND DEVELOPMENT ACTIVITIES
| | |
United States | | |
South America | |
| | |
2022 | |
| | |
United States | | |
South America | |
| Property acquisition costs: | |
| | | |
| | |
| Proved | |
$ | — | | |
$ | — | |
| Unproved | |
| — | | |
| — | |
| Exploration costs | |
| — | | |
| — | |
| Development costs | |
| 15,045 | | |
| — | |
| | |
| | | |
| | |
| Total costs incurred | |
$ | 15,045 | | |
$ | — | |
| | |
United States | | |
South America | |
| | |
2021 | |
| | |
United States | | |
South America | |
| Property acquisition costs: | |
| | | |
| | |
| Proved | |
$ | 19,835 | | |
$ | — | |
| Unproved | |
| — | | |
| — | |
| Exploration costs | |
| — | | |
| — | |
| Development costs | |
| 22,971 | | |
| — | |
| | |
| | | |
| | |
| Total costs incurred | |
$ | 42,806 | | |
$ | — | |
Reserve
Information and Related Standardized Measure of Discounted Future Net Cash Flows
The
unaudited supplemental information on oil and gas exploration and production activities has been presented in accordance with reserve
estimation and disclosures rules issued by the SEC in 2008. Under those rules, average first-day-of-the-month price during the 12-month
period before the end of the year are used when estimating whether reserve quantities are economical to produce. This same 12-month average
price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of
discounted future net cash flows. The rules also allow for the use of reliable technology to estimate proved oil and gas reserves if
those technologies have been demonstrated to result in reliable conclusions about reserve volumes. Disclosures by geographic area include
the United States and South America, which consists of our interests in Colombia. The supplemental unaudited presentation of proved reserve
quantities and related standardized measure of discounted future net cash flows provides estimates only and does not purport to reflect
realizable values or fair market values of the Company’s reserves. Volumes reported for proved reserves are based on reasonable
estimates. These estimates are consistent with current knowledge of the characteristics and production history of the reserves. The Company
emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing
oil and gas properties. Accordingly, significant changes to these estimates can be expected as future information becomes available.
Proved
reserves are those estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and
engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic
and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment, and operating
methods.
The
reserve estimates set forth below were prepared by Russell K. Hall and Associates, Inc. (“R.K. Hall”), utilizing reserve
definitions and pricing requirements prescribed by the SEC. R.K. Hall is an independent professional engineering firm specializing in
the technical and financial evaluation of oil and gas assets. R.K. Hall’s report was conducted under the direction of Russell K.
Hall, founder and President of R.K. Hall. Mr. Hall holds a BS in Mechanical Engineering from the University of Oklahoma and is a registered
professional engineer with more than 30 years of experience in reserve evaluation services. R.K. Hall and their respective employees
have no interest in the Company and were objective in determining the results of the Company’s reserves.
Total
estimated proved developed and undeveloped reserves by product type and the changes therein are set forth below for the years indicated.
SCHEDULE OF PROVED DEVELOPED AND
UNDEVELOPED RESERVES BY PRODUCT TYPE
| | |
United States | | |
South America | | |
Total | |
| | |
Gas (mcf) | | |
Oil (bbls) | | |
Gas (mcf) | | |
Oil (bbls) | | |
Gas (mcf) | | |
Oil (bbls) | |
| Total proved reserves | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| Balance December 31, 2020 | |
| 764,274 | | |
| 96,513 | | |
| — | | |
| — | | |
| 764,274 | | |
| 96,513 | |
| | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| Revisions of prior estimates | |
| 202,713 | | |
| 12,405 | | |
| — | | |
| — | | |
| 202,713 | | |
| 12,405 | |
| Production | |
| (60,069 | ) | |
| (14,367 | ) | |
| — | | |
| — | | |
| (60,069 | ) | |
| (14,367 | ) |
| | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| Balance December 31, 2021 | |
| 906,918 | | |
| 94,551 | | |
| — | | |
| — | | |
| 906,918 | | |
| 94,551 | |
| | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| Revisions to prior estimates | |
| 197,137 | | |
| (346 | ) | |
| — | | |
| — | | |
| 197,137 | | |
| (346 | ) |
| Production | |
| (73,635 | ) | |
| (10,688 | ) | |
| — | | |
| — | | |
| (73,635 | ) | |
| (10,688 | ) |
| | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| Balance December 31, 2022 | |
| 1,030,420 | | |
| 83,517 | | |
| — | | |
| — | | |
| 1,030,420 | | |
| 83,517 | |
| | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| Proved developed reserves | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| at December 31, 2021 | |
| 906,918 | | |
| 94,551 | | |
| — | | |
| — | | |
| 906,918 | | |
| 94,551 | |
| at December 31, 2022 | |
| 1,030,420 | | |
| 83,517 | | |
| — | | |
| — | | |
| 1,030,420 | | |
| 83,517 | |
| | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| Proved undeveloped reserves | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | |
| at December 31, 2021 | |
| — | | |
| — | | |
| — | | |
| — | | |
| — | | |
| — | |
| at December 31, 2022 | |
| — | | |
| — | | |
| — | | |
| — | | |
| — | | |
| — | |
As
of December 31, 2022 and 2021, the Company had no proved undeveloped (“PUD”) reserves.
The
standardized measure of discounted future net cash flows relating to proved oil and gas reserves is computed using average first-day-of
the-month prices for oil and gas during the preceding 12 month period (with consideration of price changes only to the extent provided
by contractual arrangements), applied to the estimated future production of proved oil and gas reserves, less estimated future expenditures
(based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated related future income tax expenses
(based on year-end statutory tax rates, with consideration of future tax rates already legislated), and assuming continuation of existing
economic conditions. Future income tax expenses give effect to permanent differences and tax credits but do not reflect the impact of
continuing operations including property acquisitions and exploration. The estimated future cash flows are then discounted using a rate
of ten percent a year to reflect the estimated timing of the future cash flows.
Standardized
measure of discounted future net cash flows at December 31, 2022:
STANDARDIZED
MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
| | |
United States | | |
South America | | |
Total | |
| Future cash flows from sales of oil and gas | |
$ | 16,451,375 | | |
$ | — | | |
$ | 16,451,375 | |
| Future production cost | |
| (5,918,092 | ) | |
| — | | |
| (5,918,092 | ) |
| Future development cost | |
| — | | |
| — | | |
| — | |
| Future net cash flows | |
| 10,533,283 | | |
| — | | |
| 10,533,283 | |
| 10% annual discount for timing of cash flow | |
| (5,370,124 | ) | |
| — | | |
| (5,370,124 | ) |
| | |
| | | |
| | | |
| | |
| Standardized measure of discounted future net cash flow relating to proved oil and gas reserves | |
$ | 5,163,159 | | |
$ | — | | |
$ | 5,163,159 | |
| | |
| | | |
| | | |
| | |
| Changes in standardized measure: | |
| | | |
| | | |
| | |
Change due to current year operations
Sales, net of production costs | |
$ | (1,007,808 | ) | |
$ | — | | |
$ | (1,007,808 | ) |
| Change due to revisions in standardized variables: | |
| | | |
| | | |
| | |
| Accretion of discount | |
| 338,098 | | |
| — | | |
| 338,098 | |
| Net change in sales and transfer price, net of production costs | |
| 1,876,949 | | |
| — | | |
| 1,876,949 | |
| Net change in future development cost | |
| — | | |
| — | | |
| — | |
| Discoveries | |
| — | | |
| — | | |
| — | |
| Revision and others | |
| 691,609 | | |
| — | | |
| 691,609 | |
| Changes in production rates and other | |
| (116,667 | ) | |
| — | | |
| (116,667 | ) |
| | |
| | | |
| | | |
| | |
| Net | |
| 1,782,181 | | |
| — | | |
| 1,782,181 | |
| Beginning of year | |
| 3,380,978 | | |
| — | | |
| 3,380,978 | |
| End of year | |
$ | 5,163,159 | | |
$ | — | | |
$ | 5,163,159 | |
Standardized
measure of discounted future net cash flows at December 31, 2021:
| | |
United States | | |
South America | | |
Total | |
| Future cash flows from sales of oil and gas | |
$ | 11,281,236 | | |
$ | — | | |
$ | 11,281,236 | |
| Future production cost | |
| (4,726,717 | ) | |
| — | | |
| (4,726,717 | ) |
| Future development cost | |
| — | | |
| — | | |
| — | |
| Future net cash flows | |
| 6,554,519 | | |
| — | | |
| 6,554,519 | |
| 10% annual discount for timing of cash flow | |
| (3,173,541 | ) | |
| — | | |
| (3,173,541 | ) |
| | |
| | | |
| | | |
| | |
| Standardized measure of discounted future net cash flow relating to proved oil and gas reserves | |
$ | 3,380,978 | | |
$ | — | | |
$ | 3,380,978 | |
| | |
| | | |
| | | |
| | |
| Changes in standardized measure: | |
| | | |
| | | |
| | |
Change due to current year operations
Sales, net of production costs | |
$ | (678,014 | ) | |
$ | — | | |
$ | (678,014 | ) |
| Change due to revisions in standardized variables: | |
| | | |
| | | |
| | |
| Accretion of discount | |
| 117,413 | | |
| — | | |
| 117,413 | |
| Net change in sales and transfer price, net of production costs | |
| 2,650,901 | | |
| — | | |
| 2,650,901 | |
| Net change in future development cost | |
| — | | |
| — | | |
| — | |
| Discoveries | |
| — | | |
| — | | |
| — | |
| Revision and others | |
| 786,094 | | |
| — | | |
| 786,094 | |
| Changes in production rates and other | |
| (669,548 | ) | |
| — | | |
| (669,548 | ) |
| | |
| | | |
| | | |
| | |
| Net | |
| 2,206,846 | | |
| — | | |
| 2,206,846 | |
| Beginning of year | |
| 1,174,132 | | |
| — | | |
| 1,174,132 | |
| End of year | |
$ | 3,380,978 | | |
$ | — | | |
$ | 3,380,978 | |