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 with additional holdings
in Gulf Coast areas of the United States and international holdings in Colombia, South America.
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.
Reverse
Stock Split
In
July 2020, the Company’s shareholders approved a reverse split of the Company’s common stock in a ratio to be determined,
within a specified range, by the Company’s board of directors. The Company’s board of directors approved, and, effective
at the close of business on July 31, 2020, the Company’s Certificate of Incorporation was amended to affect a 1-for-12.5
reverse split (the “Reverse Split”) of the Company’s common stock. Fractional shares otherwise issuable pursuant
to the Reverse Split were rounded up to the next highest whole number of shares. As a result of the Reverse Split, the shares
of common stock outstanding immediately prior to the Reverse Split decreased from 87,007,145 to 6,960,575 shares and the shares
of common stock authorized for issuance decreased from 150,000,000 shares to 12,000,000 shares. Similarly, all shares of common
stock issuable under outstanding options, warrants and shares of convertible preferred stock were adjusted, and applicable conversion
or exercise prices were proportionately adjusted, to reflect the Reverse Split. The par value of the Company’s common stock
remained unchanged at $0.001 per share.
All
references to shares of common stock and per share data for all periods in the financial statements and notes thereto have been
adjusted to reflect the Reverse Split on a retroactive basis.
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 $4,037,074 for the year ended December 31, 2020. 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 and have only partially recovered as of December 31, 2020, with such demand and price declines
expected to persist until governments worldwide are confident that the pandemic is adequately contained to permit renewed economic
activity. Depending upon the duration of the pandemic and the resulting global economic slowdown, the Company may incur continuing
declines in revenues and increased losses, associated from lower demand for energy and resulting depressed oil and gas prices.
However, during 2020, the Company raised a total, net of offering costs, of $4.3 million in its ATM offering and, during January
and February 2021, the Company raised an additional $6.5 million, net of offering costs, in additional ATM offerings.
The
Company believes that it has the ability to fund, from cash on hand, its operating costs and anticipated drilling operations,
as well as mitigate the immediate impact of COVID-19, for at least the next twelve months following the issuance of these financial
statements.
The
actual timing and number of wells drilled during 2021 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 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, 2019 and 2020, 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 $908,997 in excess of the FDIC’s current insured limit of $250,000
at December 31, 2020 for interest bearing accounts. The Company also had cash deposits of $2,547 in Colombian banks at December
31, 2020 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)”, supersedes the revenue recognition requirements
and industry-specific guidance under Revenue Recognition (Topic 605). 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, 2019 and 2020, the following convertible preferred stock and 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:
|
|
Year
Ended December 31,
|
|
|
2019
|
|
2020
|
Series A Convertible Preferred
Stock
|
|
|
434,000
|
|
|
|
434,000
|
|
Series B Convertible Preferred Stock
|
|
|
185,644
|
|
|
|
185,644
|
|
Stock warrants
|
|
|
98,400
|
|
|
|
98,400
|
|
Stock options
|
|
|
480,973
|
|
|
|
784,977
|
|
Totals
|
|
|
1,199,017
|
|
|
|
1,503,021
|
|
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, 2019 and 2020, 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 $438,552 and $364,810 for the years ended December 31, 2019
and 2020, respectively, and accumulated amortization, depreciation and impairment was $57,177,141 and $60,060,984 at December
31, 2019 and 2020, 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 2020 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 2019 and 2020, the Company recorded impairments of oil and gas properties totaling $745,691
and $2,519,032, respectively. The current year ceiling test write-down was primarily related to a decline in energy prices
during 2020.
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, 2019. Therefore, the related depreciation
expense was $0 and $0 for 2019 and 2020, respectively, and accumulated depreciation was $90,004 and $90,004 at December 31, 2019
and 2020, respectively.
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, 2020 and 2019.
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 2019 and 2020. 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
2020, 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, 2019 and 2020, respectively.
Recent
Accounting Developments
In
December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU 2019-12, Income Taxes – Simplifying
the Accounting for Income Taxes. The new guidance simplifies the accounting for income taxes by removing several exceptions in
the current standard and adding guidance to reduce complexity in certain areas, such as requiring that an entity reflect the effect
of an enacted change in tax laws or rates in the annual effective tax rate computation in the interim period that includes the
enactment date. The new standard is effective for fiscal years, and interim periods within those fiscal years, beginning after
December 15, 2020, with early adoption permitted. The Company is currently assessing the impact that adopting this guidance will
have on its consolidated financial statements.
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, 2020 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, 2019 and 2020:
|
|
Year
Ended December 31,
|
|
|
2019
|
|
2020
|
Oil sales
|
|
$
|
762,039
|
|
|
$
|
381,611
|
|
Natural gas sales
|
|
|
79,889
|
|
|
|
62,103
|
|
Natural gas liquids sales
|
|
|
156,064
|
|
|
|
108,631
|
|
Total revenue from customers
|
|
$
|
997,992
|
|
|
$
|
552,345
|
|
There
were no significant contract liabilities or transaction price allocations to any remaining performance obligations as of December
31, 2019 or 2020.
NOTE
3—ESCROW RECEIVABLE
In
2010, the Company, and its operator in Colombia, Hupecol, sold its interests in two entities in Colombia. Pursuant to the terms
of those sales, a portion of the sales price was escrowed to secure certain representations of the selling parties. The Company’s
share of amounts escrowed was recorded as escrow receivables.
In
2016, the Company recorded an allowance in the amount of $262,016 relating to the undisbursed balance of escrow receivables.
In
October 2020, the Company received payments totaling $164,706 representing recoveries of escrowed funds related to the previously
written-off escrow receivables. As a result of the receipt of such funds, the Company recorded non-recurring other income of $164,706
during 2020 on the statement of operations.
NOTE
4—OIL AND GAS PROPERTIES
Evaluated
Oil and Gas Properties
Evaluated
oil and gas properties subject to amortization at December 31, 2020 included the following:
|
|
United
States
|
|
South
America
|
|
Total
|
|
|
|
|
|
|
|
Evaluated properties being
amortized
|
|
$
|
11,645,084
|
|
|
$
|
49,444,654
|
|
|
$
|
61,089,738
|
|
Accumulated depreciation,
depletion, amortization and impairment
|
|
|
(10,616,331
|
)
|
|
|
(49,444,654
|
)
|
|
|
(60,060,985
|
)
|
Net capitalized costs
|
|
$
|
1,028,753
|
|
|
$
|
—
|
|
|
$
|
1,028,753
|
|
Evaluated
oil and gas properties subject to amortization at December 31, 2019 included the following:
|
|
United
States
|
|
South
America
|
|
Total
|
|
|
|
|
|
|
|
Evaluated properties being
amortized
|
|
$
|
11,613,538
|
|
|
$
|
49,454,702
|
|
|
$
|
61,068,240
|
|
Accumulated depreciation, depletion,
amortization and impairment
|
|
|
(7,722,439
|
)
|
|
|
(49,454,702
|
)
|
|
|
(57,177,141
|
)
|
Net capitalized costs
|
|
$
|
3,891,099
|
|
|
$
|
—
|
|
|
$
|
3,891,099
|
|
Unevaluated
Oil and Gas Properties
Unevaluated
oil and gas properties not subject to amortization at December 31, 2020 included the following:
|
|
United
States
|
|
|
South
America
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
Leasehold acquisition costs
|
|
$
|
1,503,349
|
|
|
$
|
143,847
|
|
|
$
|
1,647,196
|
|
Geological, geophysical, screening and
evaluation costs
|
|
|
135,330
|
|
|
|
2,199,279
|
|
|
|
2,334,609
|
|
Total
|
|
$
|
1,638,679
|
|
|
$
|
2,343,126
|
|
|
$
|
3,981,805
|
|
Unevaluated
oil and gas properties not subject to amortization at December 31, 2019 included the following:
|
|
United
States
|
|
South
America
|
|
Total
|
|
|
|
|
|
|
|
Leasehold acquisition costs
|
|
$
|
—
|
|
|
$
|
143,847
|
|
|
$
|
143,847
|
|
Geological, geophysical, screening and
evaluation costs
|
|
|
135,330
|
|
|
|
2,199,279
|
|
|
|
2,334,609
|
|
Total
|
|
$
|
135,330
|
|
|
$
|
2,343,126
|
|
|
$
|
2,478,456
|
|
During
2020, the Company invested $1,573,272 for the acquisition and development of oil and gas properties, consisting of (1)
cost of acquisition, evaluation, and development of U.S. properties ($1,503,349), attributable to acreage acquired
in the Northern Shelf of the Permian Basin in Texas which have been classified as oil and gas properties not subject to amortization,
(2) drilling and development operations in the U.S. Permian Basin ($6,527) which have been classified as oil and gas properties
subject to amortization, and (3) investments in Hupecol Meta LLC (“Hupecol Meta”) relating to drilling
operations in Colombia ($63,396). Of the amount invested, we capitalized $1,503,349 to oil and gas properties not subject
to amortization, capitalized $6,527 to oil and gas properties subject to amortization and capitalized $63,396 as additional
investment in Hupecol Meta, reflected in the cost method investment on the Company’s balance sheet.
The
Company also sold its interests in two marginal wells and associated acreage in Louisiana for nominal consideration and relief
from the related asset retirement obligations.
NOTE
5—ASSET RETIREMENT OBLIGATIONS
The
following table describes changes in our asset retirement liability (“ARO”) during each of the years ended December
31, 2019 and 2020.
|
|
2019
|
|
|
2020
|
|
|
|
|
|
|
|
|
ARO liability at January
1
|
|
$
|
38,754
|
|
|
$
|
44,186
|
|
Additions from new drilling
|
|
|
—
|
|
|
|
26,685
|
|
Dispositions from sales of oil and
gas properties
|
|
|
—
|
|
|
|
(10,677
|
)
|
Changes in estimates
|
|
|
—
|
|
|
|
449
|
|
Accretion expense
|
|
|
5,432
|
|
|
|
3,286
|
|
|
|
|
|
|
|
|
|
|
ARO liability
at December 31
|
|
$
|
44,186
|
|
|
$
|
63,929
|
|
NOTE
6 – NOTES PAYABLE
Bridge
Loan Financing
In
September 2019, the Company issued promissory notes (the “Bridge Loan Notes”) with a total principal amount of $621,052,
an original issue discount of 5%, warrants (the “Bridge Loan Warrants”) to purchase 1,180,000 shares of common stock,
and a term of 120 days to the Company’s Chief Executive Officer and significant shareholder. Net proceeds received for the
Bridge Loan Notes and Warrants totaled $590,000.
The
Bridge Loan Notes were unsecured obligations bearing interest at 12.0% per annum and payable interest only on the last day of
each calendar month with any unpaid principal and accrued interest being payable in full on January 16, 2020.
The
Bridge Loan Notes were subject to mandatory prepayment from and to the extent of (i) 100% of net proceeds the Company receive
from any sales, for cash, of equity or debt securities (other than Bridge Loan Notes), (ii) 100% of net proceeds the Company receive
from the sale of assets (other than sales in the ordinary course of business); and (iii) 75% of net proceeds the Company receive
from the sale of oil and gas produced from our Hockley County, Texas properties. Additionally, the Company had the option to prepay
the Bridge Loan Notes, at its sole election, without penalty. The holders of the Bridge Loan Notes waived mandatory prepayment
at the end of each month during 2019.
The
Bridge Loan Notes were recorded net of debt discount that consists of (i) $31,052 of original issue discount on the Bridge Loan
Notes and (ii) the relative fair value of the Bridge Loan Warrants of $144,948. The debt discount is amortized over the life of
the Bridge Loan Notes as additional interest expense.
During
2019, interest expense paid in cash totaled $21,439, and interest expense attributable to amortization of debt discount totaled
$152,533.
During
2020, interest expense paid in cash totaled $3,350, and interest expense attributable to amortization of debt discount
totaled $23,467. The Bridge Loan Notes were repaid in full in January 2020.
The
holders of the Bridge Loan Notes were the CEO and a 10% shareholder of the Company.
OID
Promissory Note
In
October 2019, the Company issued a promissory note (the “OID Note”) with a principal amount of $100,000 and an original
issue discount of 10% to a significant shareholder of the Company. Net proceeds received for the OID Note totaled $90,000.
The
debt discount was amortized over the life of the OID Note as additional interest expense. During 2019, the Company recognized
additional interest expense of $10,000 related to the amortization of the OID Note debt discount.
The
OID Note was an unsecured obligation bearing interest at 0% per annum and payable from any and all of the Company’s cash
receipts, with any unpaid principal and accrued interest being payable in full on October 31, 2019. The OID Note was repaid in
full as of October 31, 2019.
The
holder of the OID Note was a 10% shareholder of the Company.
NOTE
7—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, subject to approval by shareholders within 12 months, 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 2019, options to purchase an aggregate of 88,000 shares of common stock were granted to the Company’s directors and
to a non-executive employee. The options have a ten-year life and are exercisable at $2.70625 per share, the market price on the
date of grant. 80,000 of the options vest one year from the date of grant. 8,000 of 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 $200,562 based on the Black-Scholes
Option Pricing model with the following parameters: (1) risk-free interest rate of 2.1%; (2) expected life in years of 10; (3)
expected stock volatility of 85.7%; and (4) expected dividend yield of 0%. The Company determined the options qualified as ‘plain
vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option life.
In
July 2020, options to purchase an aggregate of 8,000 shares of common stock were granted to the Company’s directors.
The options have a ten-year life and are exercisable at $1.61 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 $13,080 based on the Black-Scholes
Option Pricing model with the following parameters: (1) risk-free interest rate of 0.64% based on the applicable US Treasury
bill rate; (2) expected life in years of 10; (3) expected stock volatility of 97.34% based on the trading history of the
Company; and (4) expected dividend yield of 0%. The Company determined the options qualified as ‘plain vanilla’
under the provisions of SAB 107 and the simplified method was used to estimate the expected option life.
In
November 2020, options to purchase an aggregate of 300,000 shares of common stock were granted to the Company’s chief executive
officer and to a non-executive employee. The options have a ten-year life and are exercisable at $1.45 per share. 246,000 of the
options were granted under the 2017 Plan and vested on the date of grant and 54,000 of the options vest on approval of
the 2021 Plan by shareholders. Assessment of the 2021 Plan options is not determinable by the Company until such time as the
plan is approved by the shareholders. The grant date fair value of the stock options under the 2017 Plan was
$320,160 based on the Black-Scholes Option Pricing model with the following parameters: (1) risk-free interest rate of 0.00%
based on the applicable US Treasury bill rate; (2) expected life in years of 10; (3) expected stock volatility of 103.29%
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 2019 and 2020 was as follows:
|
|
Options
|
|
|
Weighted
Average
Exercise
Price
|
|
|
Weighted
Average
Remaining
Contractual
Term
(in Years)
|
|
|
Aggregate
Intrinsic
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2018
|
|
|
398,306
|
|
|
$
|
9.625
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
88,000
|
|
|
$
|
2.75
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(5,333
|
)
|
|
$
|
8.50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2019
|
|
|
480,973
|
|
|
$
|
8.50
|
|
|
|
|
|
|
|
|
|
Granted (1)
|
|
|
254,000
|
|
|
$
|
1.46
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(4,000
|
)
|
|
$
|
176.00
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2020
|
|
|
730,973
|
|
|
$
|
5.07
|
|
|
|
6.73
|
|
|
$
|
74,920
|
|
Exercisable at December 31, 2020
|
|
|
711,244
|
|
|
$
|
5.13
|
|
|
|
6.69
|
|
|
$
|
74,024
|
|
|
(1)
|
Excludes 54,000 of options granted
in November 2020 under the Company’s 2021 Plan, which is pending shareholder approval and which decision is outside
the Company’s control.
|
During
2019 and 2020, the Company recognized $156,091 and $434,581, 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.
Excluding
the stock options granted under the 2021 Plan, as of December
31, 2020, non-vested options totaled 19,733 and total unrecognized stock-based compensation expense related to non-vested
stock options was $15,110. The related unrecognized expense is expected to be recognized over a weighted average
period of 0.34 years. The weighted average remaining contractual term of the outstanding options and exercisable options
at December 31, 2020 is 6.73 years and 6.69 years, respectively.
As
of December 31, 2020, there were 446,553 shares of common stock available for issuance pursuant to future stock or option grants
under the Plans, including 446,000 shares issuable under the 2021 Plan subject to shareholder approval of the 2021 Plan.
Stock-Based
Compensation Expense
The
following table reflects stock-based compensation recorded by the Company for 2019 and 2020:
|
|
2019
|
|
|
2020
|
|
|
|
|
|
|
|
|
Stock-based compensation
expense from stock options and warrants included in general and administrative expense
|
|
$
|
156,091
|
|
|
$
|
434,581
|
|
Earnings per share effect of stock-based
compensation expense
|
|
$
|
(0.00
|
)
|
|
$
|
(0.06
|
)
|
NOTE
8 – CAPITAL STOCK
Common
Stock - At-the-Market Offerings
In
May 2019, the Company entered into an At-the-Market Issuance Sales Agreement (the “Sales Agreement”) with WestPark
Capital, Inc. (“WestPark Capital”) pursuant to which the Company could sell, at its option, up to an aggregate of
$5.2 million in shares of its common stock through WestPark Capital, as sales agent. Sales of shares under the Sales Agreement
(the “2019 ATM Offering”) were made, in accordance with one or more placement notices delivered by the Company to
WestPark Capital, which notices set parameters under which shares could be sold. The 2019 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 WestPark a commission in cash equal to 3% of the gross proceeds from the sale of shares
in the 2019 ATM Offering. Additionally, the Company reimbursed WestPark Capital for $18,000 of expenses incurred in connection
with the 2019 ATM Offering.
During
the year ended December 31, 2019, in connection with the 2019 ATM Offering, the Company sold an aggregate of 277,800 shares of
its common stock and received net proceeds of $606,960, net of commissions and expenses.
During
the year ended December 31, 2020, in connection with the
2019 ATM Officering, the Company (1) sold an aggregate of 1,684,760 shares in connection with the 2019 ATM Offering
and received proceeds, net of commissions and expenses, of $4,376,549, and (2) collected $58,575 of subscription receivable
attributable to shares sold under the 2019 ATM Offering during 2019.
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, 2020, the Company had 1,085 shares of 12.0% Series A Convertible Preferred Stock and 835 shares of
12.0% Series B Convertible 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) accrues a cumulative dividend, commencing July
1, 2017, at 12% payable, if and when declared, quarterly; (ii) is convertible at the option of the holder into shares of common
stock at a conversion price of $2.50 per share, (iii) has a liquidation preference of $1,000 per share plus accrued and unpaid
dividends; and (iv) is 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
2019 and 2020, respectively, the Company paid $129,450 and $130,950 of dividends on its Series A Preferred Stock.
At
December 31, 2020, there were 1,085 shares of Series A Preferred Stock issued and outstanding.
In
February 2021, 60 shares of Series A Preferred Stock were converted into 24,000 shares of common stock, and the Company
redeemed all remaining shares of Series A Preferred Stock for cash paid of $1.07 million plus accrued dividends totaling
$21,700.
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) accrues a cumulative dividend at 12% payable, if and when declared, quarterly; (ii) is convertible
at the option of the holder into shares of common stock at a conversion price of $4.50 per share, (iii) has a liquidation preference
of $1,000 per share plus accrued and unpaid dividends; and (iv) is 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
2019 and 2020, respectively, the Company paid $100,950 and $100,950 of dividends on its Series B Preferred Stock.
At
December 31, 2020, there were 835 shares of Series B Preferred Stock issued and outstanding.
In
February 2021, the Company redeemed all remaining 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 expire on December
31, 2021. The Consultant Warrants are first exercisable, subject to continuing provision of services under a services agreement,
as to 1,000 shares on each of December 6, 2017, September 6, 2018, September 6, 2019 and September 6, 2020. The consultant was
terminated in May 2018, resulting in the termination of the unvested portion of the warrant as to 3,000 shares. 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, 2019 and 2020.
Bridge
Loan Warrants. In September 2019, the Company issued the Bridge Loan Warrants in conjunction with the Bridge Loan Notes.
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 is amortized as additional interest expense over the term
of the notes.
A
summary of warrant activity and related information for 2019 and 2020 is presented below:
|
|
Warrants
|
|
|
Weighted-Average
Exercise
Price
|
|
|
Aggregate
Intrinsic
Value
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2018
|
|
|
4,000
|
|
|
$
|
6.87
|
|
|
|
|
|
Issued
|
|
|
94,400
|
|
|
|
2.50
|
|
|
|
|
|
Exercised
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
Expired
|
|
|
—
|
|
|
$
|
—
|
|
|
|
|
|
Outstanding at December 31, 2019
|
|
|
98,400
|
|
|
$
|
2.63
|
|
|
|
|
|
Issued
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
Exercised
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
Expired
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
Outstanding at December 31, 2020
|
|
|
98,400
|
|
|
$
|
2.63
|
|
|
$
|
151,403
|
|
Exercisable at December 31, 2020
|
|
|
98,400
|
|
|
$
|
2.63
|
|
|
$
|
151,403
|
|
NOTE
9—TAXES
The
following table sets forth a reconciliation of the statutory federal income tax for the years ended December 31, 2019 and 2020.
|
|
2019
|
|
|
2020
|
|
|
|
|
|
|
|
|
Income
(loss) before income taxes
|
|
$
|
(2,515,694
|
)
|
|
$
|
(4,037,074
|
)
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit) computed
at statutory rates
|
|
$
|
(528,296
|
)
|
|
$
|
(853,287
|
)
|
Permanent differences, nondeductible
expenses
|
|
|
376
|
|
|
|
9
|
|
Increase (decrease) in valuation allowance
|
|
|
613,162
|
|
|
|
801,291
|
|
State and Local Taxes
|
|
|
—
|
|
|
|
(54,257
|
)
|
Other adjustment
|
|
|
2,103
|
|
|
|
105,715
|
|
Deferred True-Up
|
|
|
(78,112
|
)
|
|
|
529
|
|
ASC 842 lease
standard adoption
|
|
|
(9,233
|
)
|
|
|
—
|
|
Tax provision
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
Total provision
|
|
|
|
|
|
|
|
|
Foreign
|
|
$
|
—
|
|
|
$
|
—
|
|
Total provision
(benefit)
|
|
$
|
—
|
|
|
$
|
—
|
|
For
years beginning January 1, 2018, the Tax Cuts and Jobs Act (“the Act”) includes significant changes to the U.S. corporate
income tax system including the reduction of the corporate tax rate from 35% to 21%.
At
December 31, 2020 the Company has a federal tax loss carry forward of $55,089,193 and a foreign tax credit carry forward
of $505,745, 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, 2019 and 2020 are set
out below.
|
|
2019
|
|
|
2020
|
|
Non-Current Deferred tax assets:
|
|
|
|
|
|
|
|
|
Net
operating loss carry forward
|
|
$
|
11,481,979
|
|
|
$
|
11,702,841
|
|
Foreign tax credit
carry forward
|
|
|
505,745
|
|
|
|
505,745
|
|
Deferred state tax
|
|
|
13,966
|
|
|
|
13,966
|
|
Stock compensation
|
|
|
502,210
|
|
|
|
482,661
|
|
Book in excess of
tax depreciation, depletion and capitalization methods on oil and gas properties
|
|
|
(661,614
|
)
|
|
|
(59,608
|
)
|
Other
|
|
|
(196,560
|
)
|
|
|
(196,560
|
)
|
ASC 842 lease standard
– building lease
|
|
|
7,520
|
|
|
|
5,310
|
|
Colombia future
tax obligations
|
|
|
—
|
|
|
|
|
|
Total Non-Current
Deferred tax assets
|
|
|
11,653,246
|
|
|
|
12,454,355
|
|
Valuation Allowance
|
|
|
(11,653,246
|
)
|
|
|
(12,454,355
|
)
|
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 began in 2019 and Federal NOL expiration will begin in 2035.
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.
Foreign
Income Taxes
The
Company owns direct ownership in several properties in Colombia operated by Hupecol. Colombia’s current income tax rate
is 25%. During 2019 and 2020, the Company recorded no foreign tax expense.
NOTE
10—COMMITMENTS AND CONTINGENCIES
Lease
Commitment
The
Company leases office facilities under an operating lease agreement that expires October 31, 2022. The implementation of ASU 842
resulted in a right of use asset of $281,489 and related lease liability of $317,300 (of which $97,890 was classified as current
on the consolidated balance sheet) as of December 31, 2019. During the year ended December 31, 2020, the operating cash outflows
related to operating lease liabilities were $130,717 and the expense for the amortization of the right of use asset for operating
leases was $87,366. As of December 31, 2020, the Company’s operating lease had a weighted-average remaining term
of 1.8 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, 2020:
Right of use asset
|
|
$
|
194,125
|
|
|
|
|
|
|
Operating lease, current liability
|
|
$
|
107,862
|
|
Long-term operating lease liability
|
|
|
111,548
|
|
Total lease liability
|
|
$
|
219,410
|
|
During
the years ended December 31, 2019 and 2020, the Company recognized operating lease expense of $120,193 and $120,193, 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
2020, a Pool was established under the Plan representing an aggregate of 1% of the Company’s interest in the Lou
Brock Prospect.
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 a current director
and our former Chairman and Chief Executive Officer.
Payments
made by the Company under the Plan and ORRI’s totaled $84 and $6,538 in 2019 and 2020, respectively. As of December
31, 2019 and 2020, the Company had accrued $0 and $0, respectively, under the Plan as accounts payable.
NOTE
11—SUBSEQUENT EVENTS
In
January 2021, the Company entered into a 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. We 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. We 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 $1.9 million.
In
early 2021, Hupecol Meta, acquired, an additional interest in the CPO-11 block in Colombia and the
Venus Exploration area and the Company agreed to contribute an additional $99,716 of capital to increase its ownership interest in Hupecol
Meta to 7.85%. Following the acquisition, the Company’s interest in the Venus Exploration Area will increase
to 6.99% and its interest in the balance of the CPO-11 block will increase to 3.495%.
NOTE
12—GEOGRAPHICAL INFORMATION
The
Company currently has operations in two geographical areas, the United States and Colombia. Revenues for the years ended December
31, 2019 and 2020 and long-lived assets as of December 31, 2019 and 2020 attributable to each geographical area are presented
below:
|
|
2019
|
|
|
2020
|
|
|
|
Revenues
|
|
|
Long
Lived Assets, Net
|
|
|
Revenues
|
|
|
Long
Lived Assets, Net
|
|
North America
|
|
$
|
997,992
|
|
|
$
|
4,026,429
|
|
|
$
|
552,345
|
|
|
$
|
2,667,432
|
|
South America
|
|
|
—
|
|
|
|
2,343,126
|
|
|
|
—
|
|
|
|
2,343,126
|
|
Total
|
|
$
|
997,992
|
|
|
$
|
6,369,555
|
|
|
$
|
552,345
|
|
|
$
|
5,010,558
|
|
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:
|
|
2019
|
|
|
2020
|
|
Revenues
|
|
|
|
|
|
|
North
America
|
|
$
|
997,992
|
|
|
$
|
552,345
|
|
South America
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
997,992
|
|
|
$
|
552,345
|
|
|
|
|
|
|
|
|
|
|
Production Cost
|
|
|
|
|
|
|
|
|
North America
|
|
$
|
789,708
|
|
|
$
|
403,974
|
|
South America
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
789,708
|
|
|
$
|
403,974
|
|
Capital
Costs
Capitalized
costs and accumulated depletion relating to the Company’s oil and gas producing activities as of December 31, 2020, all
of which are onshore properties located in the United States and Colombia, South America are summarized below:
|
|
United
States
|
|
|
South
America
|
|
|
Total
|
|
Unproved properties not
being amortized
|
|
$
|
1,638,679
|
|
|
$
|
2,343,126
|
|
|
$
|
3,981,805
|
|
Proved properties being amortized
|
|
|
11,645,084
|
|
|
|
49,444,654
|
|
|
|
61,089,738
|
|
Accumulated depreciation,
depletion, amortization and impairment
|
|
|
(10,616,331
|
)
|
|
|
(49,444,654
|
)
|
|
|
(60,060,985
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net capitalized costs
|
|
$
|
2,667,432
|
|
|
$
|
2,343,126
|
|
|
$
|
5,010,558
|
|
Amortization
Rate
The
amortization rate per unit based on barrel of oil equivalents was $15.89 for the United States and $0 for South America
for the year ended December 31, 2020.
Acquisition,
Exploration and Development Costs Incurred
Costs
incurred in oil and gas property acquisition, exploration and development activities as of December 31, 2019 and 2020 are summarized
below:
|
|
2019
|
|
|
|
United
States
|
|
|
South
America
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
531,417
|
|
|
$
|
—
|
|
Unproved
|
|
|
—
|
|
|
|
21,957
|
|
Exploration costs
|
|
|
—
|
|
|
|
—
|
|
Development costs
|
|
|
138,945
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
$
|
670,362
|
|
|
$
|
21,957
|
|
|
|
2020
|
|
|
|
United
States
|
|
|
South
America
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
3,521
|
|
|
$
|
—
|
|
Unproved
|
|
|
1,503,349
|
|
|
|
—
|
|
Exploration costs
|
|
|
—
|
|
|
|
—
|
|
Development costs
|
|
|
3,006
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
$
|
1,509,876
|
|
|
$
|
—
|
|
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.
|
|
United
States
|
|
|
South
America
|
|
|
Total
|
|
|
|
Gas
(mcf)
|
|
|
Oil (bbls)
|
|
|
Gas (mcf)
|
|
|
Oil (bbls)
|
|
|
Gas
(mcf)
|
|
|
Oil (bbls)
|
|
Total
proved reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
December 31, 2018
|
|
|
2,723,940
|
|
|
|
350,697
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2,723,940
|
|
|
|
350,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions
of prior estimates
|
|
|
(596,642
|
)
|
|
|
(89,787
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(596,642
|
)
|
|
|
(89,787
|
)
|
Production
|
|
|
(116,629
|
)
|
|
|
(13,674
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(116,629
|
)
|
|
|
(13,674
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December
31, 2019
|
|
|
2,010,669
|
|
|
|
247,236
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2,010,669
|
|
|
|
247,236
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discoveries
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions
to prior estimates
|
|
|
(1,176,962
|
)
|
|
|
(139,338
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(1,176,962
|
)
|
|
|
(139,338
|
)
|
Production
|
|
|
(69,433
|
)
|
|
|
(11,385
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(69,433
|
)
|
|
|
(11,385
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December
31, 2020
|
|
|
764,274
|
|
|
|
96,513
|
|
|
|
—
|
|
|
|
—
|
|
|
|
764,274
|
|
|
|
96,513
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
developed reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
at
December 31, 2019
|
|
|
1,254,526
|
|
|
|
91,746
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1,254,526
|
|
|
|
91,746
|
|
at
December 31, 2020
|
|
|
764,274
|
|
|
|
96,513
|
|
|
|
—
|
|
|
|
—
|
|
|
|
764,274
|
|
|
|
96,513
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
undeveloped reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
at
December 31, 2019
|
|
|
756,143
|
|
|
|
155,490
|
|
|
|
—
|
|
|
|
—
|
|
|
|
756,143
|
|
|
|
155,490
|
|
at
December 31, 2020
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
As
of December 31, 2019, the Company had proved undeveloped (“PUD”) reserves totaling 155,490 bbls and 756,143 mcf. As
of December 31, 2020, the Company had no PUD reserves. No PUD reserves were converted to proved developed producing reserves in
2019 or 2020.
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, 2019:
|
|
United
States
|
|
|
South
America
|
|
|
Total
|
|
Future cash flows from sales
of oil and gas
|
|
$
|
16,199,011
|
|
|
$
|
—
|
|
|
$
|
16,199,011
|
|
Future production cost
|
|
|
(4,665,423
|
)
|
|
|
—
|
|
|
|
(4,665,423
|
)
|
Future development
cost
|
|
|
(3,076,020
|
)
|
|
|
—
|
|
|
|
(3,076,020
|
)
|
Future net cash flows
|
|
|
8,457,568
|
|
|
|
—
|
|
|
|
8,457,568
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10%
annual discount for timing of cash flow
|
|
|
(4,891,475
|
)
|
|
|
—
|
|
|
|
(4,891,475
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized
measure of discounted future net cash flow relating to proved oil and gas reserves
|
|
$
|
3,566,093
|
|
|
$
|
—
|
|
|
$
|
3,566,093
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in standardized measure:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change due to current year operations
Sales, net of production costs
|
|
$
|
(208,284
|
)
|
|
$
|
—
|
|
|
$
|
(208,284
|
)
|
Change due to revisions in standardized
variables:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of discount
|
|
|
771,465
|
|
|
|
—
|
|
|
|
771,465
|
|
Net change in sales
and transfer price, net of production costs
|
|
|
(3,358,522
|
)
|
|
|
—
|
|
|
|
(3,358,522
|
)
|
Net change in future
development cost
|
|
|
1,558,788
|
|
|
|
—
|
|
|
|
(1,558,788
|
)
|
Discoveries
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Revision and others
|
|
|
(1,540,161
|
)
|
|
|
—
|
|
|
|
(1,540,161
|
)
|
Changes
in production rates and other
|
|
|
(1,371,841
|
)
|
|
|
—
|
|
|
|
(1,371,841
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
(4,148,555
|
)
|
|
|
—
|
|
|
|
(4,148,555
|
)
|
Beginning of year
|
|
|
7,714,648
|
|
|
|
—
|
|
|
|
7,714,648
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
$
|
3,566,093
|
|
|
$
|
—
|
|
|
$
|
3,566,093
|
|
Standardized
measure of discounted future net cash flows at December 31, 2020:
|
|
United
States
|
|
|
South
America
|
|
|
Total
|
|
Future cash flows from sales
of oil and gas
|
|
$
|
4,967,430
|
|
|
$
|
—
|
|
|
$
|
4,967,430
|
|
Future production cost
|
|
|
(3,127,015
|
)
|
|
|
—
|
|
|
|
(3,127,015
|
)
|
Future development
cost
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Future net cash flows
|
|
|
1,840,415
|
|
|
|
—
|
|
|
|
1,840,415
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10%
annual discount for timing of cash flow
|
|
|
(666,283
|
)
|
|
|
—
|
|
|
|
(666,283
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized
measure of discounted future net cash flow relating to proved oil and gas reserves
|
|
$
|
1,174,132
|
|
|
$
|
—
|
|
|
$
|
1,174,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in standardized measure:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change due to current year operations
Sales, net of production costs
|
|
$
|
(171,448
|
)
|
|
$
|
—
|
|
|
$
|
(171,448
|
)
|
Change due to revisions in standardized
variables:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of discount
|
|
|
356,609
|
|
|
|
—
|
|
|
|
356,609
|
|
Net change in sales
and transfer price, net of production costs
|
|
|
(2,859,773
|
)
|
|
|
—
|
|
|
|
(2,859,773
|
)
|
Net change in
future development cost
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Discoveries
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Revision and others
|
|
|
(1,164,932
|
)
|
|
|
—
|
|
|
|
(1,164,932
|
)
|
Changes
in production rates and other
|
|
|
1,447,583
|
|
|
|
—
|
|
|
|
1,447,583
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
(2,391,961
|
)
|
|
|
—
|
|
|
|
(2,391,961
|
)
|
Beginning of year
|
|
|
3,566,093
|
|
|
|
—
|
|
|
|
3,566,093
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
$
|
1,174,132
|
|
|
$
|
—
|
|
|
$
|
1,174,132
|
|
NOTE
14—SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
June
30,
|
|
|
Sept.
30,
|
|
|
Dec.
31,
|
|
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
250,720
|
|
|
$
|
209,193
|
|
|
$
|
264,935
|
|
|
$
|
273,144
|
|
Loss from operations
|
|
|
(240,987
|
)
|
|
|
(482,943
|
)
|
|
|
(284,445
|
)
|
|
|
(1,325,308
|
)
|
Net loss
|
|
|
(239,620
|
)
|
|
|
(482,423
|
)
|
|
|
(304,633
|
)
|
|
|
(1,489,018
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss per common share – basic
|
|
$
|
(0.00
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.02
|
)
|
Loss per common share – diluted
|
|
$
|
(0.00
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.02
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
147,136
|
|
|
$
|
77,928
|
|
|
$
|
126,425
|
|
|
$
|
200,856
|
|
Loss from operations
|
|
|
(828,098
|
)
|
|
|
(341,854
|
)
|
|
|
(262,494
|
)
|
|
|
(2,750,323
|
)
|
Net loss
|
|
|
(850,990
|
)
|
|
|
(336,502
|
)
|
|
|
(259,765
|
)
|
|
|
(2,589,817
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss per common share – basic
|
|
$
|
(0.01
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
(0.05
|
)
|
|
$
|
(0.38
|
)
|
Loss per common share – diluted
|
|
$
|
(0.01
|
)
|
|
$
|
(0.06
|
)
|
|
$
|
(0.05
|
)
|
|
$
|
(0.38
|
)
|