General
We are an independent energy company focused on the development, exploration,
exploitation, acquisition, and production of natural gas and crude oil
properties with principal holdings in the U.S. Permian Basin and additional
holdings in the U.S. Gulf Coast region and in the South American country of
Colombia.
Our mission is to deliver outstanding net asset value per share growth to our
investors via attractive oil and gas investments. Our strategy is to focus on
early identification of, and opportunistic entrance into, existing and emerging
resource plays. We do not operate wells but typically seek to partner with
larger operators in development of resources or retain interests, with or
without contribution on our part, in prospects identified, packaged and promoted
to larger operators. By entering these plays earlier, identifying stranded
blocks and partnering with, or promoting to, larger operators, we believe we can
capture larger resource potential at lower cost and minimize our exposure to
drilling risks and costs and ongoing operating costs.
We, along with our partners, actively manage our resources through opportunistic
acquisitions and divestitures where reserves can be identified, developed,
monetized and financial resources redeployed with the objective of growing
reserves, production and shareholder value.
Generally, we generate nearly all our revenues and cash flows from the sale of
produced natural gas and crude oil, whether through royalty interests, working
interests or other arrangements. We may also realize gains and additional cash
flows from the periodic divestiture of assets.
Recent Developments
Lease Activity
Permian Basin. In 2018, we acquired a 12.5% working interest, subject to a
proportionate 10% back-in after payout, in an approximately 650-acre lease block
in Yoakum County, Texas. The acreage lay in the Midland Basin region of the
larger Permian Basin. During 2020, we acquired a 100% working interest in 46.1
acres adjoining our Yoakum County acreage. Pursuant to an area of mutual
interest agreement among the partners in our Yoakum County acreage, we will
offer to our partners the right to participate in the 46.1-acre block.
In 2019, we acquired, for $587,100, a 20% working interest in an approximately
5,871-acre lease block in the Northern Shelf of the Permian Basin in Texas. We
were required to pay 26.667% of costs on the initial well on the block through
the point at which the well is drilled, completed, equipped and ready for
operation, production or disposal. Pursuant to the agreement to acquire such
interest, we also secured the right to participate, at cost and for a period of
five years, in a 20,367-acre area of mutual interest (the "Hockley County AMI"),
including the acquired lease block. During 2020, pursuant to our rights with
respect to the Hockley County AMI, we acquired a 20% working interest in two
blocks totaling 820 gross acres. After giving effect to such acquisitions and
various lease expirations within the block, our acreage position in the Northern
Shelf of the Permian Basin covered approximately 5,080 gross acres at December
31, 2020.
In 2020, we experienced a lease expiration with respect to undeveloped acreage
in Reeves County, Texas, reducing our acreage holdings to 480 gross acres at
December 31, 2020.
Louisiana. In 2020, we sold our interest in two marginal wells and associated
acreage in Louisiana for nominal consideration and relief from plugging and
abandonment liability. Also during 2020, the lease pertaining to acreage
associated with our Crown Paper #01 well in East Baton Rouge Parish, Louisiana
was amended reducing our royalty interest with respect to the acreage to 20%.
Colombia. In 2019, we acquired a 2% interest in Hupecol Meta, LLC ("Hupecol
Meta") (the "Hupecol Meta Acquisition"). Pursuant to the terms of the Hupecol
Meta Acquisition, we paid total consideration of approximately $197,000. During
2020, we invested an additional $63,405 in Hupecol Meta. In early 2021, we
agreed to contribute an additional $99,716 to Hupecol Meta, increasing our
ownership interest to 7.85%.
Hupecol Meta holds a working interest in the 639,405 gross acre CPO-11 block in
the Llanos Basin in Colombia, comprised of the 69,128 acre Venus Exploration
Area and 570,277 acres, which was 50% farmed out by Hupecol Meta. As a result of
Hupecol Meta's 2021 purchase of additional interest in the CPO-11 block and our
agreement to increase our ownership interest in Hupecol Meta, through our
membership interest in Hupecol Meta, we will hold a 6.99% interest in the Venus
Exploration Area and a 3.495% interest in the remainder of the block.
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Drilling Activity and Well Operations
During 2020, we drilled the Frost #2H well in Yoakum County, Texas, reaching
total depth of approximately 10,230 feet, including an approximately 5,363-foot
horizontal leg. The well was fractured, production facilities constructed and
the well came on production in September 2020 at which time oil production
commenced while the well commenced unloading of frac fluid.
During 2020, we drilled the Lou Brock #1-H well in Hockley County, Texas,
reaching total depth of approximately 10,750 feet, including an approximately
5,950-foot horizontal leg. As a result of hydraulic fracturing, the well has
been shut-in pending evaluation of options to remedy those issues.
During 2020, Hupecol Meta drilled the 5,658-foot Montuno-1 vertical well on the
CPO-11 block in Colombia. The drilling operation resulted in a dry hole.
During 2020, the O'Brien #3-H well in Reeves County, Texas was shut-in for
repairs for approximately five months and was shut-in at year-end.
During 2020, the Crown Paper #01 well, in East Baton Rouge Parish, Louisiana,
underwent a failed rework. The well operator has proposed to recomplete the well
in a different zone. We hold a royalty interest in the subject acreage.
Capital Investments
During 2020, our capital investment expenditures for acreage acquisitions,
drilling, completion and related operations, as well as investments in Hupecol
Meta, totaled $1,573,272, principally relating to acreage in the Permian Basin.
Reverse Stock Split
In July 2020, we amended our Certificate of Incorporation to effect a 1-for-12.5
reverse split (the "Reverse Split") of our common stock. All references to
shares of common stock and per share data for all periods in this Management
Discussion and Analysis of Financial Condition and Results of Operations have
been adjusted to reflect the Reverse Split on a retroactive basis for all
periods presented in the financial statements.
Financing Activities
During 2019, 2020 and early 2021, we undertook the following financing
activities to support our acquisitions of additional acreage positions and to
support drilling operations:
2019 At-the-Market Offering. In May 2019, we entered into an At-the-Market
Issuance Sales Agreement (the "Sales Agreement") with WestPark Capital pursuant
to which we could sell, at our option, up to an aggregate of $5.2 million in
shares of common stock through WestPark Capital, as sales agent. Sales of shares
under the Sales Agreement (the "2019 ATM Offering") were made, in accordance
with placement notices delivered 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. We
paid WestPark a commission in cash equal to 3% of the gross proceeds from the
sale of shares in the 2019 ATM Offering. Additionally, we reimbursed WestPark
Capital for $18,000 of expenses incurred in connection with the 2019 ATM
Offering.
During 2019, we sold an aggregate of 277,800 shares in the 2019 ATM Offering and
received proceeds, net of commissions, of $606,960. During 2020, we sold an
aggregate of 1,684,760 shares in the 2019 ATM Offering and received proceeds,
net of commissions and expenses, of $4,375,594 and collected $58,575 of
subscriptions receivable attributable to shares sold under the 2019 ATM Offering
during 2019.
2021 At-the-Market Offering. In January 2021, we entered into a Sales Agreement
with Univest Securities, LLC ("Univest") pursuant to which we could sell, at our
option, up to an aggregate of $4,768,428 in shares of 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. Additionally,
we reimbursed Univest for $18,000 of expenses incurred in connection with the
2021 ATM Offering.
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During January 2021, we sold an aggregate of 2,108,520 shares in the 2021 ATM
Offering and received proceeds, net of commissions, of $4,625,361.
2021 Supplemental At-the-Market Offering. In February 2021, we entered into a
second Sales Agreement with Univest pursuant to which we could sell, at our
option, up to an aggregate of $2,030,000 in shares of 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. Additionally, we reimbursed Univest for
$18,000 of expenses incurred in connection with the 2021 Supplemental ATM
Offering.
During February 2021, we sold an aggregate of 813,100 shares in the 2021
Supplemental ATM Offering and received proceeds, net of commissions, of
$1,969,092.
Conversion and Redemption of Preferred Stock. In February 2021, 60 shares of 12%
Series A Convertible Preferred Stock were converted into 24,000 shares of our
common stock and we redeemed all remaining outstanding shares of our 12% Series
A Convertible Preferred Stock and 12% Series B Convertible Preferred Stock for
$1.97 million plus accrued dividends totaling $32,700.
Bridge Loan Financing. In September 2019, we 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. 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 we receive from any sales, for cash, of
equity or debt securities (other than Bridge Loan Notes), (ii) 100% of net
proceeds we receive from the sale of assets (other than sales in the ordinary
course of business); and (iii) 75% of net proceeds we receive from the sale of
oil and gas produced from our Hockley County, Texas properties. Additionally, we
had the option to prepay the Bridge Loan Notes, at our 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 and 2020, interest expense paid in cash totaled $21,439 and $3,350,
respectively, and interest expense attributable to amortization of debt discount
totaled $152,533 and $23,467, respectively. The Bridge Loan Notes were repaid in
full in January 2020.
The holders of the Bridge Loan Notes were our Chief Executive Officer and a 10%
shareholder.
OID Promissory Note. In October 2019, we issued a promissory note (the "OID
Note") with a principal amount of $100,000 and an original issue discount of
10%. Net proceeds received for the OID Note totaled $90,000.
The OID Note was an unsecured obligation bearing interest at 0% per annum and
payable from any and all of our 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.
Recovery of Escrow Account
In 2010, we, and our operator in Colombia, Hupecol, sold our 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. Our share of amounts escrowed was recorded as escrow receivables.
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In 2016, we recorded an allowance in the amount of $262,016 relating to the
undisbursed balance of escrow receivables.
In 2020, we received payments totaling $164,706, net, representing recoveries of
escrowed funds relating to the previously written-off escrow receivables. As a
result of the receipt of such funds, we recorded non-recurring other income in
the amount of $164,706 in 2020.
COVID-19
In early 2020, global health care systems and economies began to experience
strain from the spread of the COVID-19 Coronavirus. As the virus spread, global
economic activity began to slow and future economic activity was forecast to
slow with a resulting decline in oil and gas demand and prices. Such decline in
prices adversely affected our revenues and profitability in 2020 and, if price
declines persist, will adversely affect the economics of our existing wells and
planned future wells, possibly resulting in impairment charges to existing
properties and delaying or abandoning planned drilling operations as
uneconomical.
In response to the COVID-19 pandemic, our staff has begun working remotely and
many of our key vendors, service suppliers and partners have similarly begun to
work remotely. As a result of such remote work arrangements, we anticipate that
certain operational, reporting, accounting and other processes will slow which
may result in longer time to execute critical business functions, higher
operating costs and uncertainties regarding the quality of services and
supplies, any of which could substantially adversely affect our operating
results for as long as the current pandemic persists and potentially for some
time after the pandemic subsides.
Critical Accounting Policies
The following describes the critical accounting policies used in reporting our
financial condition and results of operations. In some cases, accounting
standards allow more than one alternative accounting method for reporting. Such
is the case with accounting for oil and gas activities described below. In those
cases, our reported results of operations would be different should we employ an
alternative accounting method.
Full Cost Method of Accounting for Oil and Gas Activities. We follow the full
cost method of accounting for oil and gas property acquisition, exploration and
development activities. Under this method, all productive and nonproductive
costs incurred in connection with the exploration for and development of oil and
gas reserves are capitalized. Capitalized costs include lease acquisition,
geological and geophysical work, delay rentals, costs of drilling, completing
and equipping successful and unsuccessful oil and gas wells and related internal
costs that can be directly identified with acquisition, exploration and
development activities, but does not include any cost related to production,
general corporate overhead or similar activities. Gain or loss on the sale or
other disposition of oil and gas properties is not recognized unless significant
amounts of oil and gas reserves are involved. No corporate overhead has been
capitalized as of December 31, 2020. The capitalized costs of oil and gas
properties, plus estimated future development costs relating to proved reserves,
are amortized on a units-of-production method over the estimated productive life
of the reserves. Unevaluated oil and gas properties are excluded from this
calculation. The capitalized oil and gas property costs, less accumulated
amortization, are limited to an amount (the ceiling limitation) equal to the sum
of: (a) the present value of estimated future net revenues from the projected
production of proved oil and gas reserves, calculated using the average oil and
natural gas sales price received by the Company as of the first trading day of
each month over the preceding twelve months (such prices are held constant
throughout the life of the properties) and a discount factor of 10%; (b) the
cost of unproved and unevaluated properties excluded from the costs being
amortized; (c) the lower of cost or estimated fair value of unproved properties
included in the costs being amortized; and (d) related income tax effects. Costs
in excess of this ceiling are charged to proved properties impairment expense.
Revenue recognition. On January 1, 2018, we adopted the new revenue guidance
using the modified retrospective method for contracts that were not complete at
December 31, 2017. ASU 2014-09, "Revenue from Contracts with Customers (Topic
606)", 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. We adopted Topic 606 on January 1,
2018, using the modified retrospective method applied to contracts that were not
completed as of January 1, 2018. Under the modified retrospective method, prior
period financial positions and results are not adjusted. The cumulative effect
adjustment recognized in the opening balances included no significant changes as
a result of this adoption. While our 2018 net earnings were not materially
impacted by revenue recognition timing changes, Topic 606 requires certain
changes to the presentation of revenues and related expenses beginning January
1, 2018.
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Our revenue is comprised principally of revenue from exploration and production
activities. Our oil is sold primarily to marketers, gatherers, and refiners.
Natural gas is sold primarily to interstate and intrastate natural-gas
pipelines, direct end-users, industrial users, local distribution companies, and
natural-gas marketers. NGLs are sold primarily to direct end-users, refiners,
and marketers. Payment is generally received from the customer in the month
following delivery.
Contracts with customers have varying terms, including spot sales or
month-to-month contracts, contracts with a finite term, and life-of-field
contracts where all production from a well or group of wells is sold to one or
more customers. We recognize sales revenues for oil, natural gas, and NGLs based
on the amount of each product sold to a customer when control transfers to the
customer. Generally, control transfers at the time of delivery to the customer
at a pipeline interconnect, the tailgate of a processing facility, or as a
tanker lifting is completed. Revenue is measured based on the contract price,
which may be index-based or fixed, and may include adjustments for market
differentials and downstream costs incurred by the customer, including
gathering, transportation, and fuel costs.
Revenues are recognized for the sale of our net share of production volumes.
Unevaluated Oil and Gas Properties. Unevaluated oil and gas properties consist
principally of our cost of acquiring and evaluating undeveloped leases, net of
an allowance for impairment and transfers to depletable oil and gas properties.
When leases are developed, expire or are abandoned, the related costs are
transferred from unevaluated oil and gas properties to oil and gas properties
subject to amortization. Additionally, we review the carrying costs of
unevaluated oil and gas properties for the purpose of determining probable
future lease expirations and abandonments, and prospective discounted future
economic benefit attributable to the leases.
Unevaluated oil and gas properties not subject to amortization include the
following at December 31, 2019 and 2020:
At At
December 31, December 31,
2019 2020
Acquisition costs $ 279,177 $ 1,647,196
Evaluation costs 2,199,279 2,334,609
Total $ 2,478,456 $ 3,981,805The carrying value of unevaluated oil and gas prospects includes $2,343,126 and
$2,343,126 expended for properties in South America at December 31, 2019 and
2020, respectively. We are maintaining our interest in these properties.
Stock-Based Compensation. We use the Black-Scholes option-pricing model, which
requires the input of highly subjective assumptions. These assumptions include
estimating the volatility of our common stock price over the expected life of
the options, dividend yield, an appropriate risk-free interest rate and the
number of options that will ultimately not complete their vesting requirements.
Changes in the subjective assumptions can materially affect the estimated fair
value of stock-based compensation and consequently, the related amount
recognized on the Statements of Operations.
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Results of Operations
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
Oil and Gas Revenues. Total oil and gas revenues decreased 45% to $552,345 in
2020 from $997,992 in 2019. The decrease in revenues was attributable to a
combination of lower production, lower average prices realized from oil and gas
sales and decreased royalties from our Crown Paper well.
The following table sets forth the gross and net producing wells, net oil and
gas production volumes and average hydrocarbon sales prices for 2019 and 2020:
2019 2020
Gross producing wells 4 4
Net producing wells 0.49 0.68
Net oil production (Bbls) 13,674 11,385
Net gas production (Mcf) 116,629 69,433
Oil-Average sales price per barrel $ 55.73 $ 35.63
Gas-Average sales price per mcf $ 2.02 $ 1.14The change in gross/net producing wells resulted from cessation of operation,
and the ultimate sale, of two uneconomical wells in Louisiana, offset by the
commencement of operations of two wells in Yoakum County, Texas. The decrease in
production was principally attributable to the shut-in of our O'Brien #3-H well
for repair and natural decline in production from our Reeves County, Texas
wells, partially offset by production from two Yoakum County wells commencing in
mid-2019 and the last week of the 2020 third quarter.
The change in average sales prices realized reflects the steep decline, and
partial recovery, in global commodity prices associated with a decline in energy
demand associated with the COVID-19 pandemic.
Royalties from our Crown Paper well decreased from approximately $28,558 in 2019
to $13,875 in 2020. The Crown Paper well underwent an unsuccessful rework in
October 2020. No future royalties are expected from the Crown Paper well unless
and until the well is successfully recompleted by the operator.
All oil and gas sales and royalty revenues are attributable to U.S. operations.
Lease Operating Expenses. Lease operating expenses decreased 49% to $403,974 in
2020 from $789,708 in 2019.
The decrease in lease operating expenses was attributable to reduced production
and reduced severance taxes due to lower sales.
All lease operating expenses during 2019 and 2020 were attributable to U.S.
operations.
Depreciation and Depletion Expense. Depreciation and depletion expense decreased
by 17% to $364,810 in 2020 from $438,553 in 2019. The decrease in depreciation
and depletion during 2020 was due to a decline in production volumes partially
offset by an increase in capitalized costs subject to amortization and
commencement of production from our Yoakum County, Texas wells.
Impairment Expense. Impairment expense totaled $2,519,032 in 2020 compared to
$745,691 in 2019. The impairment expense for both periods was due to a decrease
in the market price of oil and gas as well as downward adjustments to the
projected future production from our wells.
General and Administrative Expenses (Excluding Stock-Based Compensation).
General and administrative expense decreased by 25% to $1,012,717 in 2020 from
$1,357,723 in 2019. The change in general and administrative expense was
primarily attributable to a decrease in insurance expense, partially offset by
increased exchange listing fees and professional fees.
Stock-Based Compensation. Stock-based compensation increased to $434,581 in 2020
from $156,091 in 2019. The change was attributable to the issuance of fully
vested stock options during 2020.
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Other Income (Expense). Other income/expense, net, totaled $145,695 of income
during 2020, compared to $182,011 of expense during 2019. Other income during
2020 consisted of $12,748 of interest earned on cash balances and $164,706 of
other income arising from the recovery of escrowed funds previously written-off,
partially offset by interest expense of $31,759 relating to the Bridge Loan
Notes. Other expense during 2019 consisted of $1,961 of interest income, offset
by interest expense of $183,972 relating to the Bridge Loan Notes and the OID
Note.
Financial Condition
Liquidity and Capital Resources. At December 31, 2020, we had a cash balance of
$1,242,560 and working capital of $1,142,512, compared to a cash balance of
$97,915 and a deficit in working capital of $748,426 at December 31, 2019.
Cash Flows. Operating activities used cash of $864,787 during 2020, compared to
$725,019 used during 2019. The change in cash flows from operating activities
was attributable to changes in net operating assets and liabilities partially
offset by a reduction in cash expenses that exceeded the decline in revenues.
Investing activities used cash of $1,571,785 during 2020, compared to $889,328
used during 2019. The increase in cash used in investing activities reflects
increased development and acquisition costs, which, during 2020, included the
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, (2) drilling and development operations in the U.S.
Permian Basin ($6,527), and (3) investments in Hupecol Meta relating to drilling
operations in Colombia ($63,396), partially offset by cash proceeds from the
sale of certain oil and gas properties ($1,487). During 2019, our development
and acquisition costs totaled $692,319 and the acquisition of our interest in
the Hupecol Meta LLC cost $197,009.
Financing activities provided cash of $3,581,217 during 2020, compared to
$956,560 provided during 2019. During 2020, cash provided by financing
activities was attributable to funds received from the sale of common stock
under our 2019 ATM Offering, totaling $4,434,169, partially offset by repayment
of Bridge Loan Notes in the amount of $621,052 and payment of dividends on our
preferred stock of $231,900. During 2019, cash provided by financing activities
consisted of sales of common stock in our 2019 ATM Offering of $606,960, sales
of Bridge Loan Notes of $590,000 and sales of the OID Note of $90,000, partially
offset by distributions with respect to outstanding preferred stock of $230,400
and repayment of the OID Note of $100,000.
Long-Term Liabilities. At December 31, 2020, we had long-term liabilities of
$171,791, compared to $263,596 at December 31, 2019. Long-term liabilities, as
of December 31, 2020, consisted of a reserve for plugging costs of $63,929 and a
lease liability of $107,862.
Capital and Exploration Expenditures and Commitments. Our principal capital and
exploration expenditures relate to ongoing efforts to acquire, drill and
complete prospects, in particular our Permian Basin acreage and our newly
acquired Colombian acreage. Given the current economic environment and the
current COVID-19 pandemic, all planned additional acquisition, drilling and
development operations were deferred from March 2020 through June 30, 2020
pending improved conditions. We selectively resumed acquisition, drilling and
development operations during the third quarter of 2020 with the acquisition in
July 2020, for $33,228, of a 20% working interest in additional acreage in
Hockley County, fracking operations on our Frost #2H well, the commencement of
drilling operations on our San Andres acreage, and the acquisition in October
2020, for $25,194, of a 20% interest in further additional acreage in Hockley
County. The actual timing and number of well operations undertaken during 2021
will be principally controlled by the operators of our 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 our control or that of our operators.
During 2020, we 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, (2) drilling and development
operations in the U.S. Permian Basin ($6,527), and (3) investments in 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.
As our allocable share of well costs will vary depending on the timing and
number of wells drilled as well as our working interest in each such well and
the level of participation of other interest owners, we have not established a
drilling budget but will budget on a well-by-well basis as our operators propose
wells.
With our receipt, during 2020, of $4.4 million from sales of common stock under
our 2019 ATM Offering and our receipt in early 2021 of $6.5 million from sales
of common stock under our 2021 ATM Offering and 2021 Supplemental ATM Offering,
we believe that we have the ability, through our cash on-hand, to fund
operations and our cost for all planned wells expected to be drilled during
2021. We used a portion of those funds in early 2021 to fund redemption of our
12% Series A Convertible Preferred Stock and 12% Series B Convertible Preferred
Stock at an approximate cost of $1.97 million.
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In the event that we pursue additional acreage acquisitions or expand our
drilling plans, we may be required to secure additional funding beyond our
resources on hand. While we may, among other efforts, seek additional funding
from "at-the-market" sales of common stock, and private sales of equity and debt
securities, we presently have no commitments to provide additional funding, and
there can be no assurance that we can secure the necessary capital to fund our
share of drilling, acquisition or other costs on acceptable terms or at all. If,
for any reason, we are unable to fund our share of drilling and completion costs
and fail to satisfy commitments relative to our interest in our acreage, we may
be subject to penalties or to the possible loss of some of our rights and
interests in prospects with respect to which we fail to satisfy funding
commitments and we may be required to curtail operations and forego
opportunities. Unless and until the depressing economic effects of the
coronavirus recede, we expect that new capital to fund projects will be
difficult, if not impossible, to secure.
Contractual Obligations. At December 31, 2020, our only material contractual
obligation requiring determinable future payments on our part was our lease
relating to our executive offices.
The following table details our contractual obligations as of December 31, 2020:
Payments due by period
Total <1 year 1-3 years 3-5 years >5 years
Operating leases $ 245,638 $ 133,087 $ 112,551 $ - $ -
Total $ 245,638 $ 133,087 $ 112,551 $ - $ -
In addition to the contractual obligations requiring that we make fixed
payments, 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 may grant ORRIs in the future,
pursuant to which we will be obligated to pay a portion of our interest in
revenues from various prospects to third parties. Our Permian Basin acreage is
subject to a ORRI's ranging from 1% to 2%, in aggregate, in favor of current and
former employees and officers. All present and future prospects in Colombia are
subject to a 1.5% ORRI in favor of each of a current employee and a former
director.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements or guarantees of third party
obligations at December 31, 2020.
Inflation
We believe that inflation has not had a significant impact on our operations
since inception.
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