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.
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.
Reclassification
Certain
amounts for prior periods have been reclassified to conform to the current presentation.
Cash
and Cash Equivalents
Cash
and cash equivalents consist of demand deposits and cash investments with initial maturity dates of less than three months.
Concentration
of Credit Risk
Financial
instruments that potentially subject the Company to a concentration of credit risk include cash and cash equivalents. The Company
had cash deposits of approximately $56,830 in excess of the FDIC’s current insured limit of $250,000 at December 31, 2017
for interest bearing accounts. The Company has not experienced any losses on its deposits of cash and cash equivalents.
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, 2017, the Company evaluated their receivables and determined that no allowance
was necessary.
Oil
and Gas Revenues
The
Company recognizes sales revenues, net of royalties and net profits interests, based on the amount of gas, oil, and condensate
sold to purchasers when delivery to the purchaser has occurred and title has transferred. This occurs when production has been
delivered to a pipeline. The Company follows the sales method to account for natural gas imbalances. Sales may result in more
or less of the Company’s share of pro-rata production from certain wells. When natural gas sales volumes exceeds the Company’s
entitled share and the accumulated overproduced balance exceeds the Company’s share of the remaining estimated proved natural
gas reserves for a given property, the Company will record a liability. Historically, sales volumes have not materially differed
from the Company’s entitled share of natural gas production and the Company did not have a material imbalance position in
terms of volumes or values at December 31, 2017 or 2016.
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 $161,378 and $301,786 for the years ended December 31, 2017
and 2016, respectively and accumulated amortization, depreciation and impairment was $55,635,076 and $55,473,698 at December 31,
2017 and 2016, 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 2017 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 2017 and 2016, the Company impaired oil and gas properties in the amount of $0 and $584,086,
respectively.
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.
Depreciation
expense for office equipment was $111 and $996 for 2017 and 2016, respectively, and accumulated depreciation was $90,004 and $89,893
at December 31, 2017 and 2016, 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.
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.
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.
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, 2017, the Company had 1,175 shares of 12.0% Series A Convertible Preferred Stock and 895 shares of
12.0% Series B Convertible Preferred Stock issued and outstanding.
Net
Loss Per Share
Basic
net loss per share is computed by dividing the net loss attributable to common shareholders by the weighted-average number of
common shares outstanding during the period. Diluted net loss per share is computed by dividing the net loss attributable to common
shareholders by the weighted-average number of common and common equivalent shares outstanding during the period. Common share
equivalents included in the diluted computation represent shares issuable upon assumed exercise of stock options and warrants
using the treasury stock and shares issuable upon conversion of convertible preferred stock using the “if converted”
method. For periods in which net losses are incurred, weighted average shares outstanding is the same for basic and diluted loss
per share calculations, as the inclusion of common share equivalents would have an anti-dilutive effect.
For
the year ended December 31, 2017, outstanding options, warrants and convertible preferred stock exercisable to purchase, or convertible
into, 6,012,165 shares of common stock, 3,651,680 shares of common stock, 8,362,222 shares of common stock, respectively, were
excluded from the calculation of diluted net loss per share because they were anti-dilutive. For the year ended December 31, 2016,
outstanding options to purchase 5,232,165 shares of common stock were excluded from the calculation of diluted net loss per share
because they were anti-dilutive.
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 Reeves County, Texas properties accounted for all of the Company’s drilling operations and substantially
all of its oil and gas investments in 2017. In the event of a significant negative change in operations or operating outlook pertaining
to the Company’s Reeves County 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.
At
December 31, 2017, 63% of the Company’s net oil and gas property investment, and 72% of its revenue for the year ended December
31, 2017, was in or derived from its Reeves County holdings and 34% of the Company’s net oil and gas property investment
and 0% of its revenue for the year ended December 31, 2017 was with or derived from its interests operated in Colombia.
For
2017, our oil production from the Company’s 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, 2017 and 2016, respectively.
Subsequent
Events
The
Company evaluated subsequent events for disclosure from December 31, 2017 through the date the consolidated financial statements
were issued.
Recent
Accounting Developments
In
May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which supersedes
nearly all existing revenue recognition guidance under GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised
goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled
for those goods or services. ASU 2014-09 defines a five- step process to achieve this core principle and, in doing so, more judgment
and estimates may be required within the revenue recognition process than are required under existing GAAP. The guidance is effective
for annual and interim periods beginning after December 15, 2017. The standard is required to be adopted using either the full
retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment
to retained earnings on the opening balance sheet. The Company will adopt the new standard utilizing the modified retrospective
approach. The Company does not expect the adoption of this ASU to have a material impact on its financial statements. However,
we anticipate the new standard will result in more robust footnote disclosures. We cannot currently determine the extent of the
new footnote disclosures as further clarification is needed for certain practices common to the industry. We will continue to
evaluate the impacts that future contracts may have.
In
February 2016, a pronouncement was issued by the FASB that creates new accounting and reporting guidelines for leasing arrangements.
The new guidance requires organizations that lease assets to recognize assets and liabilities on the balance sheet related to
the rights and obligations created by those leases, regardless of whether they are classified as finance or operating leases.
Consistent with current guidance, the recognition, measurement and presentation of expenses and cash flows arising from a lease
primarily will depend on its classification as a finance or operating lease. The guidance also requires new disclosures to help
financial statement users better understand the amount, timing, and uncertainty of cash flows arising from leases. The new standard
is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period,
with early application permitted. The new standard is to be applied using a modified retrospective approach. The Company is still
in the process of evaluating the impact of this new standard; however, the Company believes the initial impact of adopting the
standard will result in increases to its assets and liabilities on its consolidated balance sheets, and changes to the timing
and presentation of certain operating expenses on its consolidated statements of operations.
In
August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230). ASU 2016-15 seeks to reduce the existing diversity
in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. This update
is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early
adoption permitted. The Company is currently evaluating the provisions of ASU 2016-15 and assessing the impact, if any, it may
have on its statement of consolidated cash flows.
In
May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation (Topic 718) Scope of Modification Accounting. The ASU clarifies
which changes to the terms or conditions of a stock-based payment award require an entity to apply modification accounting in
Topic 718. The standard is effective for the Company on January 1, 2018, with early adoption permitted. The impact of this new
standard will depend on the extent and nature of future changes to the terms of Company’s stock-based payment awards.
NOTE
2—OIL AND GAS PROPERTIES
Evaluated
Oil and Gas Properties
Evaluated
oil and gas properties subject to amortization at December 31, 2017 included the following:
|
|
United
States
|
|
|
South
America
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
Evaluated properties being
amortized
|
|
$
|
10,684,824
|
|
|
$
|
49,454,702
|
|
|
$
|
60,139,526
|
|
Accumulated depreciation,
depletion, amortization and impairment
|
|
|
(6,180,374
|
)
|
|
|
(49,454,702
|
)
|
|
|
(55,635,076
|
)
|
Net capitalized
costs
|
|
$
|
4,504,450
|
|
|
$
|
—
|
|
|
$
|
4,504,450
|
|
Evaluated
oil and gas properties subject to amortization at December 31, 2016 included the following:
|
|
United
States
|
|
|
South
America
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
Evaluated properties being
amortized
|
|
$
|
6,184,631
|
|
|
$
|
49,454,702
|
|
|
$
|
55,639,333
|
|
Accumulated depreciation,
depletion, amortization and impairment
|
|
|
(6,018,996
|
)
|
|
|
(49,454,702
|
)
|
|
|
(55,473,698
|
)
|
Net capitalized
costs
|
|
$
|
165,635
|
|
|
$
|
—
|
|
|
$
|
165,635
|
|
Unevaluated
Oil and Gas Properties
Unevaluated
oil and gas properties not subject to amortization at December 31, 2017 included the following:
|
|
United
States
|
|
|
South
America
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
Leasehold acquisition costs
|
|
$
|
—
|
|
|
$
|
141,318
|
|
|
$
|
141,318
|
|
Geological, geophysical,
screening and evaluation costs
|
|
|
—
|
|
|
|
2,168,023
|
|
|
|
2,168,023
|
|
Total
|
|
$
|
—
|
|
|
$
|
2,309,341
|
|
|
$
|
2,309,341
|
|
Unevaluated
oil and gas properties not subject to amortization at December 31, 2016 included the following:
|
|
United
States
|
|
|
South
America
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
Leasehold acquisition costs
|
|
$
|
—
|
|
|
$
|
141,318
|
|
|
$
|
141,318
|
|
Geological, geophysical,
screening and evaluation costs
|
|
|
6,994
|
|
|
|
2,142,869
|
|
|
|
2,149,863
|
|
Total
|
|
$
|
6,994
|
|
|
$
|
2,284,187
|
|
|
$
|
2,291,181
|
|
During
2017, the Company invested $4,512,353, net, for the acquisition and development of oil and gas properties consisting of (1) the
cost of the acquisition of U.S. properties of $1,043,977, net, principally attributable to acreage acquired in Reeves County,
Texas, (2) drilling and completion costs on U.S. properties of $3,443,222 attributable to operations of the Company’s Reeves
County, Texas, acreage, and (3) preparation and evaluation of costs in Colombia of $25,154. Of the amount invested, the Company
capitalized $25,154 to oil and gas properties not subject to amortization and capitalized $4,487,199 to oil and gas properties
subject to amortization.
NOTE
3—Asset Retirement Obligations
The
following table describes changes in our asset retirement liability during each of the years ended December 31, 2017 and 2016.
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
ARO liability at January
1
|
|
$
|
27,444
|
|
|
$
|
25,262
|
|
Accretion expense
|
|
|
2,214
|
|
|
|
552
|
|
Obligations incurred
for development of oil and gas properties
|
|
|
6,000
|
|
|
|
1,630
|
|
|
|
|
|
|
|
|
|
|
ARO liability
at December 31
|
|
$
|
35,658
|
|
|
$
|
27,444
|
|
NOTE
4 – NOTES PAYABLE
In
June 2017, the Company issued promissory notes (the “Bridge Loan Notes”) in the principal amount of $600,000, with
an original issue discount of 5%, and warrants (the “Bridge Loan Warrants”) to purchase 600,000 shares of the Company’s
common stock. The aggregate consideration received by the Company for the Bridge Loan Notes and Warrants was $570,000.
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 October 21, 2017.
The
Bridge Loan Notes were subject to mandatory prepayment from and to the extent of (i) 100% of net proceeds received by the Company
from any sales, for cash, of equity or debt securities (other than Bridge Loan Notes) of the Company, (ii) 100% of net proceeds
received by the Company from the sale of assets (other than sales in the ordinary course of business); and (iii) 75% of net proceeds
received from the sale of oil and gas produced from the Company’s Reeves County, Texas properties. Additionally, the Company
had the option to prepay the Bridge Loan Notes, at its sole election, without penalty.
The
Bridge Loan Notes were recorded net of debt discount in the amount of $158,734. The debt discount consists of (i) $30,000 excess
in the face amount of the Bridge Loan Notes over the consideration paid plus (ii) the value of the Bridge Loan Warrants, totaling
$128,734. The debt discount is amortized over the life of the Bridge Loan Notes as additional interest expense. During 2017, interest
expense paid in cash totaled $12,871 and interest expense attributable to amortization of debt discount totaled $158,734. See
“Note 6 – Capital Stock – Warrants – Bridge Loan Warrants.”
The
holders of $300,000 in the face amount of the Bridge Loan Notes waived mandatory prepayment at both July 31, 2017 and August 31,
2017 and the holders of the remaining $300,000 in face amount of the Bridge Loan Notes were repaid in full pursuant to the mandatory
prepayment provision. The balance of the Bridge Loan Notes, in the amount of $300,000, were repaid in full as of December 30,
2017.
NOTE
5—STOCK-BASED COMPENSATION
In
2005, the Company’s Board of Directors adopted the Houston American Energy Corp. 2005 Stock Option Plan (the “2005
Plan”). The terms of the 2005 Plan allow for the issuance of up to 500,000 options to purchase 500,000 shares of the Company’s
common stock.
In
2008, the Company’s Board of Directors 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 6,000,000 shares of the
Company’s common stock pursuant to the grant of stock options and restricted stock.
In
2017, the Company’s Board of Directors adopted the Houston American Energy Corp. 2017 Equity Incentive Plan (the “2017
Plan” and, together with the 2005 Plan and the 2008 Plan, the “Plans”). The terms of the 2017 Plan allow for
the issuance of up to 5,000,000 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
March 2016, options to purchase an aggregate of 20,000 shares were granted to non-employee directors. The options were granted
in connection with service on an ad hoc board committee and vest on the earlier of August 15, 2016, the termination of the committee
or termination of service on the committee due to death or disability. The options have a five-year life and an exercise price
of $0.1982 per share. The options were valued on the date of grant at $2,896 using the Black-Scholes option-pricing model with
the following parameters: (1) risk-free interest rate of 1.49%; (2) expected life in years of 4.99; (3) expected stock volatility
of 106.95%; (4) expected dividend yield of 0%; and (5) forfeiture rate of 15.22%. The Company determined the options qualify as
‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate the expected option
life.
In
June 2016, options to purchase an aggregate of 800,000 shares were granted to non-employee directors. The options, which included
a one-time supplemental grant to purchase an aggregate of 600,000 shares, were granted in connection with service on the board
of directors. 200,000 of the options granted to non-employee directors vested 20% on the grant date and vest as to the remaining
80% nine months from the grant date, have a ten-year life and have an exercise price of $0.2201 per share. Those option grants
were valued on the date of grant at $32,640 using the Black-Scholes option-pricing model with the following parameters: (1) risk-free
interest rate of 1.26%; (2) expected life in years of 5.28; (3) expected stock volatility of 108.5%; (4) expected dividend yield
of 0%; and (5) forfeiture rate of 15.01%. 600,000 of the options granted to non-employee directors vest (i) 50% on the earlier
of June 7, 2017 or the day preceding the next annual shareholders meeting at which directors are elected, (ii) 50% on the earlier
of June 7, 2018 or the day preceding the second annual shareholders meeting (after the grant date) at which directors are to be
elected, and (iii) in the event that the Company consummates a transaction(s) (after the option grant date) in the nature of a
sale of shares of equity securities for cash or assets resulting in a net addition(s) to the Company’s stockholders’
equity of not less than $2 million, all unvested options vest in full. Those options have a ten-year life and have an exercise
price of $0.2201 per share. Those option grants were valued on the date of grant at $83,421 using the Black-Scholes option-pricing
model with the following parameters: (1) risk-free interest rate of 1.26% (2) expected life in years of 5.28, and (3) expected
stock volatility of 108.5%. The Company determined the option qualifies as ‘plain vanilla’ under the provisions of
SAB 107 and the simplified method was used to estimate the expected option life.
In
March 2017, options to purchase an aggregate of 1,200,000 shares were granted to an executive officer, a non-executive officer
and an advisor to the Company. All of the options have a ten-year life and are exercisable at $0.30 per share, the fair market
value on date of grant. The executive officer’s option grant vests 1/3 on each of the first three anniversaries of the grant
date; subject to vesting in full on December 31, 2017 if the Company’s common stock continues to be listed on the NYSE MKT
(or another national securities exchange) on that date. The non-executive officer’s option grant vested 25% on June 12,
2017 and 25% on each of the first three anniversaries of the grant date. The advisor option grant vested on the grant date. The
non-executive officer options were forfeited unvested on termination of service to the Company during the six months ended June
30, 2017. The options were valued on the date of grant at $234,947 using the Black-Scholes option-pricing model with the following
parameters: (1) risk-free interest rate of 2.19%; (2) expected life in years of 5.50; (3) expected stock volatility of 109.16%;
and (4) expected dividend yield of 0%. The Company determined the options qualify as ‘plain vanilla’ under the provisions
of SAB 107 and the simplified method was used to estimate the expected option life.
In
September 2017, options to purchase an aggregate of 200,000 shares were granted to the Company’s independent directors.
All of the options have a ten-year life and are exercisable at $0.485 per share, the fair market value on date of grant. The options
vest 20% on the date of grant and 80% nine months from the date of grant. The options were valued on the date of grant at $71,064
using the Black-Scholes option-pricing model with the following parameters: (1) risk-free interest rate of 1.76%; (2) expected
life in years of 5.67; (3) expected stock volatility of 102.38%; and (4) expected dividend yield of 0%. The Company determined
the options qualify as ‘plain vanilla’ under the provisions of SAB 107 and the simplified method was used to estimate
the expected option life.
Option
activity during 2017 and 2016 was as follows:
|
|
Options
|
|
|
Weighted
Average
Exercise Price
|
|
|
Weighted
Average
Remaining Contractual Term (in Years)
|
|
|
Aggregate
Intrinsic
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at December 31, 2015
|
|
|
4,432,165
|
|
|
$
|
2.47
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
820,000
|
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(20,000
|
)
|
|
$
|
4.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at
December 31, 2016
|
|
|
5,232,165
|
|
|
$
|
2.11
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
1,400,000
|
|
|
$
|
0.33
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(620,000
|
)
|
|
$
|
0.47
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding
at December 31, 2017
|
|
|
6,012,165
|
|
|
$
|
1.86
|
|
|
|
5.90
|
|
|
$
|
253,483
|
|
Exercisable
at December 31, 2017
|
|
|
5,252,165
|
|
|
$
|
2.09
|
|
|
|
5.56
|
|
|
$
|
186,253
|
|
During
2017 and 2016, the Company recognized $304,189 and $138,912, respectively, of stock-based compensation expense attributable to
outstanding stock option grants, including current period grants and unamortized expense associated with prior period grants.
As
of December 31, 2017, non-vested options totaled 760,000 and total unrecognized stock-based compensation expense related to non-vested
stock options was $101,610. The unrecognized expense is expected to be recognized over a weighted average period of 1.42 years.
The weighted average remaining contractual term of the outstanding options and exercisable options at December 31, 2017 is 5.90
years and 5.17 years, respectively.
As
of December 31, 2017, there were 4,987,835 shares of common stock available for issuance pursuant to future stock or option grants
under the Plans.
Stock-Based
Compensation Expense
The
following table reflects stock-based compensation recorded by the Company for 2017 and 2016:
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Stock-based
compensation expense from stock options and warrants included in general and administrative expense
|
|
$
|
306,000
|
|
|
$
|
138,911
|
|
Earnings
per share effect of stock-based compensation expense
|
|
$
|
(0.00
|
)
|
|
$
|
(0.00
|
)
|
NOTE
6 – CAPITAL STOCK
Treasury
Stock
We
account for repurchases of common stock using the cost method with common stock in treasury classified in the consolidated balance
sheets as a reduction of shareholders’ equity. During the years ended December 31, 2017 and 2016, the Company acquired 0
and 702,557 shares of common stock, respectively, for $0 and $135,973, respectively.
In
March 2017, the Company’s board of directors approved the cancellation of all shares of common stock held in treasury. As
a result, 892,557 shares of common stock were cancelled and $174,125 previously classified on the balance sheet as treasury stock
was reclassified as a reduction in additional paid-in capital.
Common
Stock - At-the-Market Offering
In
July 2017, 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 may sell, at its option, up to an aggregate of $5
million in shares of its common stock through WestPark Capital, as sales agent. Sales of shares under the Sales Agreement (the
“ATM Offering”) will be made, in accordance with one or more placement notices delivered by the Company to WestPark
Capital, which notices shall set parameters under which shares may be sold. The 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 will pay WestPark a commission in cash equal to 3% of the gross proceeds from the sale of shares in the ATM
Offering. Additionally, the Company reimbursed WestPark Capital for $25,000 of expenses incurred in connection with the ATM Offering.
As of December 31, 2017, the Company had sold an aggregate of 7,817,157 shares in the ATM Offering and had received proceeds,
net of commissions and expenses, of $4,101,013.
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 $0.20 per share, (iii) has a liquidation preference of $1,000 per share plus accrued and unpaid
dividends; and (iv) is redeemable at our 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 2017, the Company paid $70,500 of dividends on its Series A Preferred Stock and 25 shares of Series A Preferred Stock were
converted to 125,000 shares of Common Stock.
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 $0.36 per share, (iii) has a liquidation preference
of $1,000 per share plus accrued and unpaid dividends; and (iv) is redeemable at our 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 2017, the Company paid $81,920 of dividends on its Series B Preferred Stock
and 14.6 shares of Series B Preferred Stock were converted to 40,556 shares of Common Stock.
Warrants
Series
B Warrants
.
The Series B Warrants, issued as part of Units along with Series B Preferred Stock, are exercisable,
for a period of 9 months, expiring February 3, 2018, to purchase an aggregate of 3,001,680 shares of common stock at $0.43 per
share. The relative value of the warrants were valued on the date of grant at $194,934 using the Black-Scholes option-pricing
model with the following parameters: (1) risk-free interest rate of 1.10%; (2) expected life in years of 0.75; (3) expected stock
volatility of 92.36%; and (4) expected dividend yield of 0%.
Bridge
Loan Warrants
.
The Bridge Loan Warrants, issued in conjunction with the Bridge Loan Notes, are exercisable, for
a period of one year, expiring June 23, 2018, to purchase an aggregate of 600,000 shares of common stock at $0.50 per share. The
relative fair value of the warrants were valued on the date of grant at $128,734 using the Black Scholes option-pricing model
with the following parameters: (1) risk free interest rate of 1.20%; (2) expected life in years of 1.00; (3) expected stock volatility
of 93.67%; and (4) expected dividend yield of 0%. The relative fair value of the warrants was recorded as debt discount of the
Bridge Loan Notes and is amortized over the life of the notes.
Consultant
Warrants
. In September 2017, the Company issued warrants (the “Consultant Warrants”) to a consultant. The
Consultant Warrants are exercisable to purchase 50,000 shares of common stock at $0.55 per share and expire December 31, 2021.
The Consultant Warrants are first exercisable, subject to continuing provision of services under a services agreement, as to 12,500
shares on each of December 6, 2017, September 6, 2018, September 6, 2019 and September 6, 2020. 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%; (2) expected life in years of 4.32; (3) expected stock volatility of 99.75%; and (4) expected dividend
yield of 0%. The Company recognized $1,811 of stock-based compensation expense related to the vesting of the Consultant Warrants
during 2017.
A
summary of warrant activity and related information for 2017 is presented below:
|
|
Warrants
|
|
|
Weighted-Average
Exercise Price
|
|
|
Aggregate
Intrinsic Value
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at January 1, 2017
|
|
|
—
|
|
|
$
|
—
|
|
|
|
|
|
Issued
|
|
|
3,651,680
|
|
|
|
0.44
|
|
|
|
|
|
Exercised
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
Expired
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
Outstanding at December 31, 2017
|
|
|
3,651,680
|
|
|
$
|
0.44
|
|
|
$
|
—
|
|
Exercisable at December 31, 2017
|
|
|
3,614,180
|
|
|
$
|
0.44
|
|
|
$
|
—
|
|
NOTE
7—TAXES
The
following table sets forth a reconciliation of the statutory federal income tax for the years ended December 31, 2017 and 2016.
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
Income
(loss) before income taxes
|
|
$
|
(2,037,615
|
)
|
|
$
|
(2,641,625
|
)
|
|
|
|
|
|
|
|
|
|
Income tax expense (benefit) computed
at statutory rates
|
|
$
|
(713,165
|
)
|
|
$
|
(924,569
|
)
|
Permanent differences, nondeductible
expenses
|
|
|
5,371
|
|
|
|
514
|
|
Increase (decrease) in valuation allowance
|
|
|
(7,283,514
|
)
|
|
|
874,987
|
|
Other adjustment
|
|
|
44,279
|
|
|
|
49,068
|
|
Federal tax rate
change
|
|
|
7,947,029
|
|
|
|
—
|
|
Tax provision
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
Total provision
|
|
|
|
|
|
|
|
|
Foreign
|
|
$
|
—
|
|
|
$
|
—
|
|
Total provision
(benefit)
|
|
$
|
—
|
|
|
$
|
—
|
|
At
December 31, 2017 the Company has a federal tax loss carry forward of $53,001,669 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, 2017 and 2016 are set
out below.
|
|
2017
|
|
|
2016
|
|
Non-Current Deferred tax assets:
|
|
|
|
|
|
|
|
|
Net
operating loss carry forward
|
|
$
|
11,130,350
|
|
|
$
|
16,872,064
|
|
Foreign tax credit
carry forward
|
|
|
505,745
|
|
|
|
505,745
|
|
Deferred state tax
|
|
|
13,966
|
|
|
|
23,277
|
|
Stock compensation
|
|
|
1,891,857
|
|
|
|
3,090,907
|
|
Book in excess of
tax depreciation, depletion and capitalization methods on oil and gas properties
|
|
|
(919,070
|
)
|
|
|
(454,590
|
)
|
Other
|
|
|
(196,560
|
)
|
|
|
(327,600
|
)
|
Colombia
future tax obligations
|
|
|
—
|
|
|
|
—
|
|
Total Non-Current
Deferred tax assets
|
|
|
12,426,288
|
|
|
|
19,709,803
|
|
Valuation
Allowance
|
|
|
(12,426,288
|
)
|
|
|
(19,709,803
|
)
|
Net deferred
tax asset
|
|
$
|
—
|
|
|
$
|
—
|
|
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 2017 and 2016, we recorded no foreign tax expense.
Effect
of New Federal Tax Reform Legislation
On
December 22, 2017, new federal tax reform legislation was enacted in the United States (the “2017 Tax Act”), resulting
in significant changes from previous tax law. The 2017 Tax Act reduces the federal corporate income tax rate to 21% from 35% effective
January 1, 2018. The rate change, along with certain immaterial changes in tax basis resulting from the 2017 Tax Act, resulted
in a reduction of the Company’s deferred tax assets of $7,947,029 and a corresponding reduction in the valuation allowance.
NOTE
8—COMMITMENTS AND CONTINGENCIES
Lease
Commitment
The
Company leases office facilities under an operating lease agreement that expires October 31, 2022. The lease agreement requires
future payments as follows:
Year
|
|
Amount
|
|
|
|
|
|
2018
|
|
$
|
125,978
|
|
2019
|
|
|
128,348
|
|
2020
|
|
|
130,717
|
|
2021
|
|
|
133,087
|
|
2022
|
|
|
112,551
|
|
|
|
|
|
|
Total
|
|
$
|
630,681
|
|
Total
rental expense was $119,619 and $107,620 in 2017 and 2016, respectively. 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
2017, a Pool was established under the Plan representing an aggregate of 2% of the Company’s interest in the Company’s
Reeves County acreage.
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. During 2017, ORRIs were issued to two employees in full settlement of obligations
under the Plan with respect to the Pool established relating to the Reeves County acreage.
Payments
made by the Company under the Plan and ORRI’s paid totaled $6,016 and $0 in 2017 and 2016, respectively. As of December
31, 2017 and 2016, the Company had accrued $7,781 and $616, respectively, under the Plan as accounts payable.
NOTE
9—SUBSEQUENT EVENTS
Preferred Stock
Conversion
. In January 2018, the Company issued 250,000 shares of Common Stock on conversion of 50 shares of Series A
Convertible Preferred Stock.
Consultant Warrants
.
In January 2018, the Company issued warrants (the “Consultant Warrants”) to a consultant. The Consultant Warrants
are exercisable to purchase 50,000 shares of common stock at $0.40 per share and expire December 31, 2020. The Consultant Warrants
are first exercisable, subject to continuing provision of services under a services agreement, on February 28, 2018.
Stock Option
Grants
. In February and March 2018, options to purchase an aggregate of 1,500,000 shares were granted to an executive
officer and an employee of the Company. All of the options have a ten-year life and are exercisable at prices ranging from $0.2922
to $0.30 per share, the fair market value on the dates of grant. The option grants vest 1/3 on each of the first three anniversaries
of the grant date.
NOTE
10—GEOGRAPHICAL INFORMATION
The
Company currently has operations in two geographical areas, the United States and Colombia. Revenues for the years ended December
31, 2017 and 2016 and long-lived assets as of December 31, 2017 and 2016 attributable to each geographical area are presented
below:
|
|
2017
|
|
|
2016
|
|
|
|
Revenues
|
|
|
Long
Lived Assets, Net
|
|
|
Revenues
|
|
|
Long
Lived Assets, Net
|
|
North
America
|
|
$
|
630,392
|
|
|
$
|
4,504,450
|
|
|
$
|
165,910
|
|
|
$
|
260,110
|
|
South
America
|
|
|
—
|
|
|
|
2,309,341
|
|
|
|
—
|
|
|
|
2,284,187
|
|
Total
|
|
$
|
630,392
|
|
|
$
|
6,813,791
|
|
|
$
|
165,910
|
|
|
$
|
2,544,297
|
|
NOTE
11—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:
|
|
2017
|
|
|
2016
|
|
Revenues
|
|
|
|
|
|
|
|
|
North
America
|
|
$
|
630,392
|
|
|
$
|
165,910
|
|
South
America
|
|
|
—
|
|
|
|
—
|
|
|
|
$
|
630,392
|
|
|
$
|
165,910
|
|
|
|
|
|
|
|
|
|
|
Production Cost
|
|
|
|
|
|
|
|
|
North America
|
|
$
|
216,429
|
|
|
$
|
97,203
|
|
South
America
|
|
|
—
|
|
|
|
—
|
|
|
|
$
|
216,429
|
|
|
$
|
97,203
|
|
Capital
Costs
Capitalized
costs and accumulated depletion relating to the Company’s oil and gas producing activities as of December 31, 2017, 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
|
|
$
|
—
|
|
|
$
|
2,309,341
|
|
|
$
|
2,309,341
|
|
Proved
properties being amortized
|
|
|
10,684,824
|
|
|
|
49,454,702
|
|
|
|
60,139,526
|
|
Accumulated
depreciation, depletion, amortization and impairment
|
|
|
(6,180,374
|
)
|
|
|
(49,454,702
|
)
|
|
|
(55,635,076
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
capitalized costs
|
|
$
|
4,504,450
|
|
|
$
|
2,309,341
|
|
|
$
|
6,813,791
|
|
Amortization
Rate
The
amortization rate per unit based on barrel of oil equivalents was $10.61 for the United States and $0 for South America for the
year ended December 31, 2017.
Acquisition,
Exploration and Development Costs Incurred
Costs
incurred in oil and gas property acquisition, exploration and development activities as of December 31, 2017 and 2016 are summarized
below:
|
|
2017
|
|
|
|
United
States
|
|
|
South
America
|
|
Property
acquisition costs:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
1,043,977
|
|
|
$
|
—
|
|
Unproved
|
|
|
—
|
|
|
|
25,154
|
|
Exploration
costs
|
|
|
3,443,222
|
|
|
|
—
|
|
Development
costs
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Total
costs incurred
|
|
$
|
4,487,199
|
|
|
$
|
25,154
|
|
|
|
2016
|
|
|
|
United
States
|
|
|
South
America
|
|
Property
acquisition costs:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
—
|
|
|
$
|
—
|
|
Unproved
|
|
|
6,994
|
|
|
|
—
|
|
Exploration
costs
|
|
|
31,415
|
|
|
|
170,812
|
|
Development
costs
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Total
costs incurred
|
|
$
|
38,409
|
|
|
$
|
170,812
|
|
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”) and Lonquist
& Co., LLC (“Lonquist”), utilizing reserve definitions and pricing requirements prescribed by the SEC. R.K. Hall
and Lonquist are independent professional engineering firms 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. Lonquist’s report was conducted under the direction of Don E.
Charbula, P.E., Vice President of Lonquist. Mr. Charbula holds a BS in Petroleum Engineering from The University of Texas at Austin
and is a registered professional engineer with more than 30 years of experience in production engineering, reservoir engineering,
acquisitions and divestments, field operations and management. R.K. Hall, Lonquist and their respective employees have no interest
in the Company, and were objective in determining the results of the Company’s reserves. Lonquist used a combination of
production performance, offset analogies, seismic data and their interpretation, subsurface geologic data and core data, along
with estimated future operating and development costs as provided by the Company and based upon historical costs adjusted for
known future changes in operations or development plans, to estimate our reserves. The Company does not operate any of its oil
and gas properties.
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, 2015
|
|
|
57,700
|
|
|
|
8,850
|
|
|
|
—
|
|
|
|
—
|
|
|
|
57,700
|
|
|
|
8,850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions of prior estimates
|
|
|
2,524
|
|
|
|
2,763
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2,524
|
|
|
|
2,763
|
|
Production
|
|
|
(20,204
|
)
|
|
|
(2,933
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(20,204
|
)
|
|
|
(2,933
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2016
|
|
|
40,020
|
|
|
|
8,680
|
|
|
|
—
|
|
|
|
—
|
|
|
|
40,020
|
|
|
|
8,680
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discoveries
|
|
|
2,782,055
|
|
|
|
389,455
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2,782,055
|
|
|
|
389,455
|
|
Revisions to prior estimates
|
|
|
48,983
|
|
|
|
3,116
|
|
|
|
—
|
|
|
|
—
|
|
|
|
48,983
|
|
|
|
3,116
|
|
Production
|
|
|
(30,997
|
)
|
|
|
(10,038
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(30,997
|
)
|
|
|
(10,038
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2017
|
|
|
2,840,061
|
|
|
|
391,213
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2,840,061
|
|
|
|
391,213
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
at December
31, 2016
|
|
|
40,020
|
|
|
|
8,680
|
|
|
|
—
|
|
|
|
—
|
|
|
|
40,020
|
|
|
|
8,680
|
|
at December
31, 2017
|
|
|
1,666,031
|
|
|
|
149,088
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1,666,031
|
|
|
|
149,088
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
at December
31, 2016
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
at December
31, 2017
|
|
|
1,174,030
|
|
|
|
242,125
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1,174,030
|
|
|
|
242,125
|
|
As
of December 31, 2017, the Company had proved undeveloped (“PUD”) reserves totaling 242,125 bbls and 1,174,030 mcf.
As of December 31, 2016, the Company had no PUD reserves. No PUD reserves were converted to proved developed producing reserves
in 2017 or 2016.
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, 2017:
|
|
United
States
|
|
|
South
America
|
|
|
Total
|
|
Future cash flows from sales
of oil and gas
|
|
$
|
27,514,923
|
|
|
$
|
—
|
|
|
$
|
27,514,923
|
|
Future production cost
|
|
|
(6,628,886
|
)
|
|
|
—
|
|
|
|
(6,628,886
|
)
|
Future development
cost
|
|
|
(4,758,170
|
)
|
|
|
—
|
|
|
|
(4,758,170
|
)
|
Future net cash flows
|
|
|
16,127,867
|
|
|
|
—
|
|
|
|
16,127,867
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10%
annual discount for timing of cash flow
|
|
|
(9,279,012
|
)
|
|
|
—
|
|
|
|
(9,279,012
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized
measure of discounted future net cash flow relating to proved oil and gas reserves
|
|
$
|
6,848,855
|
|
|
$
|
—
|
|
|
$
|
6,848,855
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in standardized measure:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change due to current year operations
Sales, net of production costs
|
|
$
|
(413,962
|
)
|
|
$
|
—
|
|
|
$
|
(413,962
|
)
|
Change due to revisions in standardized
variables:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of discount
|
|
|
16,413
|
|
|
|
—
|
|
|
|
16,413
|
|
Net change in sales
and transfer price, net of production costs
|
|
|
197
|
|
|
|
—
|
|
|
|
197
|
|
Net change in future
development cost
|
|
|
(4,758,170
|
)
|
|
|
—
|
|
|
|
(4,758,170
|
)
|
Discoveries
|
|
|
6,517,865
|
|
|
|
—
|
|
|
|
6,517,865
|
|
Revision and others
|
|
|
(57,247
|
)
|
|
|
—
|
|
|
|
(57,247
|
)
|
Changes
in production rates and other
|
|
|
5,379,629
|
|
|
|
—
|
|
|
|
5,379,629
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
6,684,725
|
|
|
|
—
|
|
|
|
6,684,725
|
|
Beginning of year
|
|
|
164,130
|
|
|
|
—
|
|
|
|
164,130
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
$
|
6,848,855
|
|
|
$
|
—
|
|
|
$
|
6,848,855
|
|
Standardized
measure of discounted future net cash flows at December 31, 2016:
|
|
United
States
|
|
|
South
America
|
|
|
Total
|
|
Future cash flows from sales
of oil and gas
|
|
$
|
460,760
|
|
|
$
|
—
|
|
|
$
|
460,760
|
|
Future production
cost
|
|
|
(264,730
|
)
|
|
|
—
|
|
|
|
(264,730
|
)
|
Future net cash flows
|
|
|
196,030
|
|
|
|
—
|
|
|
|
196,030
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10%
annual discount for timing of cash flow
|
|
|
(31,900
|
)
|
|
|
—
|
|
|
|
(31,900
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized
measure of discounted future net cash flow relating to proved oil and gas reserves
|
|
$
|
164,130
|
|
|
$
|
—
|
|
|
$
|
164,130
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in standardized measure:
|
|
|
|
|
|
|
|
|
|
|
|
|
Change due to current year operations
Sales, net of production costs
|
|
$
|
(68,707
|
)
|
|
$
|
—
|
|
|
$
|
(68,707
|
)
|
Change due to revisions in standardized
variables:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of discount
|
|
|
25,438
|
|
|
|
—
|
|
|
|
25,438
|
|
Net change in sales
and transfer price, net of production costs
|
|
|
(147,362
|
)
|
|
|
—
|
|
|
|
(147,362
|
)
|
Revision and others
|
|
|
(43,109
|
)
|
|
|
—
|
|
|
|
(43,109
|
)
|
Changes
in production rates and other
|
|
|
143,490
|
|
|
|
—
|
|
|
|
143,490
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
(90,250
|
)
|
|
|
—
|
|
|
|
(90,250
|
)
|
Beginning of year
|
|
|
254,380
|
|
|
|
—
|
|
|
|
254,380
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year
|
|
$
|
164,130
|
|
|
$
|
—
|
|
|
$
|
164,130
|
|
NOTE
12—SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
|
June
30,
|
|
|
Sept.
30,
|
|
|
Dec.
31,
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
57,633
|
|
|
$
|
46,275
|
|
|
$
|
111,741
|
|
|
$
|
414,743
|
|
Loss from operations
|
|
|
(502,514
|
)
|
|
|
(469,238
|
)
|
|
|
(621,778
|
)
|
|
|
(282,663
|
)
|
Net loss
|
|
|
(502,399
|
)
|
|
|
(466,274
|
)
|
|
|
(786,278
|
)
|
|
|
(282,663
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss per common share – basic
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.00
|
)
|
Loss per common share – diluted
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.00
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenue
|
|
$
|
48,260
|
|
|
$
|
33,887
|
|
|
$
|
39,738
|
|
|
$
|
44,025
|
|
Loss from operations
|
|
|
(343,411
|
)
|
|
|
(492,202
|
)
|
|
|
(371,192
|
)
|
|
|
(1,442,026
|
)
|
Net loss
|
|
|
(339,451
|
)
|
|
|
(490,406
|
)
|
|
|
(370,343
|
)
|
|
|
(1,441,425
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss per common share – basic
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.03
|
)
|
Loss per common share – diluted
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
(0.03
|
)
|