NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
Torchlight Energy
Resources, Inc. (“Company”) was incorporated in October
2007 under the laws of the State of Nevada as Pole Perfect Studios,
Inc. (“PPS”). From its incorporation to November 2010,
the company was primarily engaged in business start-up
activities.
On November 23,
2010, we entered into and closed a Share Exchange Agreement (the
“Exchange Agreement”) between the major shareholders of
PPS and the shareholders of Torchlight Energy, Inc.
(“TEI”). As a result of the transactions effected by
the Exchange Agreement, at closing TEI became our wholly-owned
subsidiary, and the business of TEI became our sole business. TEI
was incorporated under the laws of the State of Nevada in June
2010. We are engaged in the acquisition, exploitation and/or
development of oil and natural gas properties in the United States.
We operate our business through our subsidiaries Torchlight Energy
Inc., Torchlight Energy Operating, LLC, and Hudspeth Oil
Corporation, Torchlight Hazel LLC, and Winkler Properties
LLC.
At December 31,
2018, the Company had not yet achieved profitable operations. We
had a net loss of $5,806,612 for the year ended December 31, 2018
and had accumulated losses of $89,314,305 since our inception. We
expect to incur further losses in the development of our business.
The Company had a working capital deficit as of December 31, 2018
of $676,690. These conditions raise substantial doubt about the
Company’s ability to continue as a going
concern.
The Company’s
ability to continue as a going concern is dependent on its ability
to generate future profitable operations and/or to obtain the
necessary financing to meet its obligations and repay its
liabilities arising from normal business operations when they come
due. Management’s plan to address the Company’s ability
to continue as a going concern includes: (1) obtaining debt or
equity funding from private placement or institutional sources; (2)
obtain loans from financial institutions, where possible, or (3)
participating in joint venture transactions with third parties.
Although management believes that it will be able to obtain the
necessary funding to allow the Company to remain a going concern
through the methods discussed above, there can be no assurances
that such methods will prove successful.
These consolidated
financial statements have been prepared assuming that the Company
will continue as a going concern and therefore, the financial
statements do not include any adjustments to reflect the possible
future effects on the recoverability and classification of assets
or the amount and classifications of liabilities that may result
from the outcome of this uncertainty.
3.
|
SIGNIFICANT ACCOUNTING
POLICIES
|
The Company
maintains its accounts on the accrual method of accounting in
accordance with accounting principles generally accepted in the
United States of America. Accounting principles followed and the
methods of applying those principles, which materially affect the
determination of financial position, results of operations and cash
flows are summarized below:
Use of
estimates
– The preparation of financial
statements in conformity with accounting principles generally
accepted in the United States of America requires management to
make estimates and certain assumptions that affect the amounts
reported in these consolidated financial statements and
accompanying notes. Actual results could differ from these
estimates.
Basis of
presentation
—The financial statements are
presented on a consolidated basis and include all of the accounts
of Torchlight Energy Resources Inc. and its wholly owned
subsidiaries, Torchlight Energy, Inc., Torchlight Energy Operating,
LLC, Hudspeth Oil Corporation, Torchlight Hazel LLC, and Warwink
Properties LLC. All significant intercompany balances and
transactions have been eliminated.
Certain
reclassifications have been made to the 2017 consolidated financial
statements to make them consistent with the 2018 presentation.
Total stockholders’ equity and net loss are unchanged due to
these reclassifications made in cash flow statement.
Risks and
uncertainties
– The Company’s operations
are subject to significant risks and uncertainties, including
financial, operational, technological, and other risks associated
with operating an emerging business, including the potential risk
of business failure.
Concentration
of risks
– At times the Company’s cash
balances are in excess of amounts guaranteed by the Federal Deposit
Insurance Corporation. The Company’s cash is placed with a
highly rated financial institution, and the Company regularly
monitors the credit worthiness of the financial institutions with
which it does business.
Fair value of
financial instruments
– Financial instruments
consist of cash, receivables, payables and promissory notes, if
any. The estimated fair values of cash, receivables, and payables
approximate the carrying amount due to the relatively short
maturity of these instruments. The carrying amounts of any
promissory notes approximate their fair value giving affect for the
term of the note and the effective interest rates.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
3.
|
SIGNIFICANT ACCOUNTING POLICIES
- continued
|
For assets and
liabilities that require re-measurement to fair value the Company
categorizes them in a three-level fair value hierarchy as
follows:
●
|
Level 1 inputs are
quoted prices (unadjusted) in active markets for identical assets
or liabilities.
|
●
|
Level 2 inputs are
quoted prices for similar assets and liabilities in active markets
or inputs that are observable for the asset or liability, either
directly or indirectly through market corroboration.
|
●
|
Level 3 inputs are
unobservable inputs based on management’s own assumptions
used to measure assets and liabilities at fair value.
|
A financial asset
or liability’s classification within the hierarchy is
determined based on the lowest level input that is significant to
the fair value measurement.
Cash and cash
equivalents -
Cash and cash equivalents include
certain investments in highly liquid instruments with original
maturities of three months or less.
Accounts
receivable
– Accounts receivable consist of
uncollateralized oil and natural gas revenues due under normal
trade terms, as well as amounts due from working interest owners of
oil and gas properties for their share of expenses paid on their
behalf by the Company. Management reviews receivables periodically
and reduces the carrying amount by a valuation allowance that
reflects management’s best estimate of the amount that may
not be collectible. As of December 31, 2018 and December 31, 2017,
no valuation allowance was considered necessary.
As of December 31,
2017 accounts receivable included $419,839 the Company computed as
being due from Husky Ventures with respect to the sale of Chisholm
Trail properties in 2015 and in dispute as part of the Husky legal
action in process at that dates. Additionally, a payment of
$520,400 made by Husky Ventures which is also disputed by the
Company had been included in current liabilities captioned
“Funds received pending settlement”. The Company
settled the matter with Husky during the quarter ended June 30,
2018.
Oil and gas
properties
– The Company uses the full cost
method of accounting for exploration and development activities as
defined by the Securities and Exchange Commission
(“SEC”). Under this method of accounting, the costs of
unsuccessful, as well as successful, exploration and development
activities are capitalized as properties and equipment. This
includes any internal costs that are directly related to property
acquisition, exploration and development activities but does not
include any costs 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 the
gain or loss would significantly alter the relationship between
capitalized costs and proved reserves.
Oil and gas
properties include costs that are excluded from costs being
depleted or amortized. Oil and natural gas property costs excluded
represent investments in unevaluated properties and include
non-producing leasehold, geological, and geophysical costs
associated with leasehold or drilling interests and exploration
drilling costs. The Company allocates a portion of its acquisition
costs to unevaluated properties based on relative value. Costs are
transferred to the full cost pool as the properties are evaluated
over the life of the reservoir. Unevaluated properties are reviewed
for impairment at least quarterly and are determined through an
evaluation considering, among other factors, seismic data,
requirements to relinquish acreage, drilling results, remaining
time in the commitment period, remaining capital plan, and
political, economic, and market conditions.
Gains and losses on
the sale of oil and gas properties are not generally reflected in
income unless the gain or loss would significantly alter the
relationship between capitalized costs and proved reserves. Sales
of less than 100% of the Company’s interest in the oil and
gas property are treated as a reduction of the capital cost of the
field, with no gain or loss recognized, as long as doing so does
not significantly affect the unit-of-production depletion rate.
Costs of retired equipment, net of salvage value, are usually
charged to accumulated depreciation.
Capitalized
interest –
The Company capitalizes interest on
unevaluated properties during the periods in which they are
excluded from costs being depleted or amortized. During the years
ended December 31, 2018 and 2017, the Company capitalized
$2,020,019 and $1,010,868, respectively, of interest on unevaluated
properties.
Depreciation,
depletion, and amortization
– The depreciable
base for oil and natural gas properties includes the sum of all
capitalized costs net of accumulated depreciation, depletion, and
amortization (“DD&A”), estimated future development
costs and asset retirement costs not included in oil and natural
gas properties, less costs excluded from amortization. The
depreciable base of oil and natural gas properties is amortized on
a unit-of-production method.
Ceiling
test
– Future production volumes from oil and
gas properties are a significant factor in determining the full
cost ceiling limitation of capitalized costs. Under the full cost
method of accounting, the Company is required to periodically
perform a “ceiling test” that determines a limit on the
book value of oil and gas properties. If the net capitalized cost
of proved oil and gas properties, net of related deferred income
taxes, plus the cost of unproved oil and gas properties, exceeds
the present value of estimated future net cash flows discounted at
10 percent, net of related tax affects, plus the cost of unproved
oil and gas properties, the excess is charged to expense and
reflected as additional accumulated DD&A. The ceiling test
calculation uses a commodity price assumption which is based on the
unweighted arithmetic average of the price on the first day of each
month for each month within the prior 12 month period and excludes
future cash outflows related to estimated abandonment
costs.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
3.
|
SIGNIFICANT ACCOUNTING POLICIES
- continued
|
The determination
of oil and gas reserves is a subjective process, and the accuracy
of any reserve estimate depends on the quality of available data
and the application of engineering and geological interpretation
and judgment. Estimates of economically recoverable reserves and
future net cash flows depend on a number of variable factors and
assumptions that are difficult to predict and may vary considerably
from actual results. In particular, reserve estimates for wells
with limited or no production history are less reliable than those
based on actual production. Subsequent re-evaluation of reserves
and cost estimates related to future development of proved oil and
gas reserves could result in significant revisions to proved
reserves. Other issues, such as changes in regulatory requirements,
technological advances, and other factors which are difficult to
predict could also affect estimates of proved reserves in the
future.
Asset
retirement obligations
–The fair value of a
liability for an asset’s retirement obligation
(“ARO”) is recognized in the period in which it is
incurred if a reasonable estimate of fair value can be made, with
the corresponding charge capitalized as part of the carrying amount
of the related long-lived asset. The liability is accreted to its
then-present value each subsequent period, and the capitalized cost
is depleted over the useful life of the related asset. Abandonment
costs incurred are recorded as a reduction of the ARO
liability.
Inherent in the
fair value calculation of an ARO are numerous assumptions and
judgments including the ultimate settlement amounts, inflation
factors, credit adjusted discount rates, timing of settlement, and
changes in the legal, regulatory, environmental, and political
environments. To the extent future revisions to these assumptions
impact the fair value of the existing ARO liability, a
corresponding adjustment is made to the oil and gas property
balance. Settlements greater than or less than amounts accrued as
ARO are recorded as a gain or loss upon settlement.
Income
taxes
-
Income taxes are accounted for under the
asset and liability method. Deferred tax assets and liabilities are
recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases and
operating loss carry forwards. Deferred tax assets and liabilities
are measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are
expected to be recovered or settled. The effect on deferred tax
assets and liabilities of a change in tax rates is recognized in
income in the period that includes the enactment date. A valuation
allowance is established to reduce deferred tax assets if it is
more likely than not that the related tax benefits will not be
realized.
Authoritative
guidance for uncertainty in income taxes requires that the Company
recognize the financial statement benefit of a tax position only
after determining that the relevant tax authority would more likely
than not sustain the position following an examination. Management
has reviewed the Company’s tax positions and determined there
were no uncertain tax positions requiring recognition in the
consolidated financial statements. Company tax returns remain
subject to Federal and State tax examinations. Generally, the
applicable statutes of limitation are three to four years from
their respective filings.
Estimated interest
and penalties related to potential underpayment on any unrecognized
tax benefits are classified as a component of tax expense in the
statement of operation. The Company has not recorded any interest
or penalties associated with unrecognized tax benefits for any
periods covered by these financial statements.
Share-based
compensation
– Compensation cost for equity
awards is based on the fair value of the equity instrument on the
date of grant and is recognized over the period during which an
employee is required to provide service in exchange for the
award.
The Company
accounts for stock option awards using the calculated value method.
The expected term was derived using the simplified method provided
in Securities and Exchange Commission release Staff Accounting
Bulletin No. 110, which averages an awards weighted average vesting
period and contractual term for “plain vanilla” share
options.
The Company
accounts for any forfeitures of options when they occur. Previously
recognized compensation cost for an award is reversed in the period
that the award is forfeited.
The Company also
issues equity awards to non-employees. The fair value of these
option awards is estimated when the award recipient completes the
contracted professional services. The Company recognizes expense
for the estimated total value of the awards during the period from
their issuance until performance completion.
In June 2018, the
FASB issued ASU 2018-07,
Compensation - Stock Compensation (Topic 718):
Improvements to Nonemployee Share-Based Payment Accounting
,
which simplifies the accounting for share-based payments granted to
nonemployees for goods and services. Under this ASU, the guidance
on such payments to nonemployees is aligned with the requirements
for share-based payments granted to employees. ASU 2018-07 is
effective for fiscal years beginning after December 15, 2018,
however the Company has opted for early adoption effective July 1,
2018. The amendments in this ASU are to be applied through a
cumulative-effect adjustment to retained earnings as of the first
reporting period in which the ASU is effective. In evaluating early
adoption the Company has determined that the change does not have a
material impact on its consolidated financial
statements.
The Company values
warrant and option awards using the Black-Scholes option pricing
model.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
3.
|
SIGNIFICANT ACCOUNTING POLICIES
- continued
|
Revenue
recognition
– On January 1, 2018, the Company
adopted ASC 606, Revenue from Contracts with Customers, and the
related guidance in ASC 340-40 (the new revenue standard), and
related guidance on gains and losses on derecognition of
nonfinancial assets ASC 610-20, using the modified retrospective
method applied to those contracts which were not completed as of
January 1, 2018. Under the modified retrospective method, the
Company recognizes the cumulative effect of initially applying the
new revenue standard as an adjustment to the opening balance of
retained earnings; however, no significant adjustment was required
as a result of adopting the new revenue standard. Results for
reporting periods beginning after January 1, 2018 are presented
under the new revenue standard. The comparative information has not
been restated and continues to be reported under the historic
accounting standards in effect for those periods. The impact of the
adoption of the new revenue standard was immaterial to the
Company’s net income.
The Company’s
revenue is typically generated from contracts to sell natural gas,
crude oil or NGLs produced from interests in oil and gas properties
owned by the Company. Contracts for the sale of natural gas and
crude oil are evidenced by (1) base contracts for the sale and
purchase of natural gas or crude oil, which document the general
terms and conditions for the sale, and (2) transaction
confirmations, which document the terms of each specific sale. The
transaction confirmations specify a delivery point which represents
the point at which control of the product is transferred to the
customer. These contracts frequently meet the definition of a
derivative under ASC 815, and are accounted for as derivatives
unless the Company elects to treat them as normal sales as
permitted under that guidance. The Company elects to treat
contracts to sell oil and gas production as normal sales, which are
then accounted for as contracts with customers. The Company has
determined that these contracts represent multiple performance
obligations which are satisfied when control of the commodity
transfers to the customer, typically through the delivery of the
specified commodity to a designated delivery point.
Revenue is measured
based on consideration specified in the contract with the customer,
and excludes any amounts collected on behalf of third parties. The
Company recognizes revenue in the amount that reflects the
consideration it expects to be entitled to in exchange for
transferring control of those goods to the customer. Amounts
allocated in the Company’s price contracts are based on the
standalone selling price of those products in the context of
long-term contracts. Payment is generally received one or two
months after the sale has occurred.
Gain or loss on
derivative instruments is outside the scope of ASC 606 and is not
considered revenue from contracts with customers subject to ASC
606. The Company may in the future use financial or physical
contracts accounted for as derivatives as economic hedges to manage
price risk associated with normal sales, or in limited cases may
use them for contracts the Company intends to physically settle but
do not meet all of the criteria to be treated as normal
sales.
Producer Gas Imbalances.
The Company
applies the sales method of accounting for natural gas revenue.
Under this method, revenues are recognized based on the actual
volume of natural gas sold to purchasers.
Basic and
diluted earnings (loss) per share
–
Basic earnings (loss) per
common share is computed by dividing net income (loss) available to
common shareholders by the weighted average number of common shares
outstanding during the period. Diluted earnings (loss) per common
share is computed in the same way as basic earnings (loss) per
common share except that the denominator is increased to include
the number of additional common shares that would be outstanding if
all potential common shares had been issued and if the additional
common shares were dilutive. The calculation of diluted earnings
per share excludes 14,814,586 shares issuable upon the exercise of
outstanding warrants and options because their effect would be
anti-dilutive.
Environmental
laws and regulations
– The Company is subject
to extensive federal, state, and local environmental laws and
regulations. Environmental expenditures are expensed or capitalized
depending on their future economic benefit. The Company believes
that it is in compliance with existing laws and
regulations.
Recent accounting pronouncements
– In February 2016 the FASB, issued ASU, 2016-02, Leases. The
ASU requires companies to recognize on the balance sheet the assets
and liabilities for the rights and obligations created by leased
assets. ASU 2016-02 will be effective for the Company in the first
quarter of 2019, with early adoption permitted. The Company is
currently evaluating the impact that the adoption of ASU 2016-02
will have on the Company’s consolidated financial statements
and related disclosures.
Other recently
issued or adopted accounting pronouncements are not expected to
have, or did not have, a material impact on the Company’s
financial position or results from operations.
Subsequent
events –
The Company evaluated subsequent
events through March 18, 2019, the date of issuance of these
financial statements. Subsequent events are disclosed in Note
11.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
4. OIL & GAS PROPERTIES
The following table
presents the capitalized costs for oil & gas properties of the
Company as of December 31, 2018 and 2017:
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
Evaluated costs subject
to amortization
|
|
$
|
11,664,586
|
|
|
$
|
5,022,129
|
|
Unevaluated
costs
|
|
|
31,746,477
|
|
|
|
26,100,749
|
|
Total capitalized
costs
|
|
|
43,411,063
|
|
|
|
31,122,878
|
|
Less accumulated
depreciation, depletion and amortization
|
|
|
(6,845,602
|
)
|
|
|
(5,543,599
|
)
|
Total oil and gas
properties
|
|
$
|
36,565,461
|
|
|
$
|
25,579,279
|
|
Unevaluated costs
as of December 31, 2018 include cumulative costs on developing
projects including the Orogrande, Hazel, and Winkler projects in
West Texas.
The Company
identified impairment of $2,300,626 in 2017 related to its
unevaluated properties. Although we had no recognized impairment
expense in 2017, the Company has adjusted the separation of
evaluated versus unevaluated costs within its full cost pool to
recognize the value impairment related to the expiration of
unevaluated leases in 2017 in the amount of $2,300,626. The impact
of this change will be to increase the basis for calculation of
future period’s depletion, depreciation and amortization to
include $2,300,626 of cost which will effectively recognize the
impairment on the Consolidated Statement of Operations over future
periods. The $2,300,626 has also become an evaluated cost for
purposes of future period’s Ceiling Tests and which may
further recognize the impairment expense recognized in future
periods. The impact of this cost reclassification at March 31, 2018
was a recognized impairment expense of $139,891. No additional
impairment adjustment was required through December 31,
2018.
Due to the
volatility of commodity prices, should oil and natural gas prices
decline in the future, it is possible that a further write-down
could occur. Proved reserves are estimated quantities of crude oil,
natural gas, and natural gas liquids, which geological and
engineering data demonstrate with reasonable certainty to be
recoverable from known reservoirs under existing economic and
operating conditions. The independent engineering estimates include
only those amounts considered to be proved reserves and do not
include additional amounts which may result from new discoveries in
the future, or from application of secondary and tertiary recovery
processes where facilities are not in place or for which
transportation and/or marketing contracts are not in place.
Estimated reserves to be developed through secondary or tertiary
recovery processes are classified as unevaluated
properties.
Orogrande Project, West
Texas
On August 7, 2014,
we entered into a Purchase Agreement with Hudspeth Oil Corporation
(“Hudspeth”), McCabe Petroleum Corporation
(“MPC”), and Gregory McCabe, our Chairman. Mr. McCabe
was the sole owner of both Hudspeth and MPC. Under the terms and
conditions of the Purchase Agreement, at closing, we purchased 100%
of the capital stock of Hudspeth which holds certain oil and gas
assets, including a 100% working interest in approximately 172,000
mostly contiguous acres in the Orogrande Basin in West Texas. As of
December 31, 2017, leases covering approximately 133,000 acres
remain in effect. This acreage is in the primary term under
five-year leases that carry additional five-year extension
provisions. As consideration, at closing we issued 868,750
restricted shares of our common stock to Mr. McCabe and paid a
total of $100,000 in geologic origination fees to third parties.
Additionally, Mr. McCabe has, at his option, a 10% working interest
back-in after payout and a reversionary interest if drilling
obligations are not met, all under the terms and conditions of a
participation and development agreement among Hudspeth, MPC and Mr.
McCabe. We believe all drilling obligations through December 31,
2018 have been met.
On September 23,
2015, Hudspeth entered into a Farmout Agreement with Pandora
Energy, LP (“Pandora”), Founders Oil & Gas, LLC
(“Founders”), and for the limited purposes set forth
therein, MPC and Mr. McCabe, for the entire Orogrande Project in
Hudspeth County, Texas. The Farmout Agreement provided that
Hudspeth and Pandora (collectively referred to as
“Farmor”) would assign to Founders an undivided 50% of
the leasehold interest and a 37.5% net revenue interest in the oil
and gas leases and mineral interests in the Orogrande Project,
which interests, except for any interests retained by Founders,
would be reassigned to Farmor by Founders if Founders did not spend
a minimum of $45.0 million on actual drilling operations on the
Orogrande Project by September 23, 2017. Under a joint operating
agreement also entered into on September 23, 2015, Founders was
designated as operator of the leases.
On March 22, 2017,
Founders, Founders Oil & Gas Operating, LLC, Founders’
operating partner, Hudspeth and Pandora signed a Drilling and
Development Unit Agreement (the “DDU Agreement”), with
the Commissioner of the General Land Office, on behalf of the State
of Texas, and as approved by the Board for Lease of University
Lands, or University Lands, on the Orogrande Project. The DDU
Agreement has an effective date of January 1, 2017 and required a
payment from Founders, Hudspeth and Pandora, collectively, of
$335,323 as the initial consideration fee. The initial
consideration fee was paid by Founders in April 2017 and was to be
deducted from the required spud fee payable to us at commencement
of the next well drilled.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
4. OIL & GAS PROPERTIES
-
continued
The DDU Agreement
allows for all 192 existing leases covering approximately 133,000
net acres leased from University Lands to be combined into one
drilling and development unit for development purposes. The term of
the DDU Agreement expires on December 31, 2023, and the time to
drill on the drilling and development unit continues through
December 2023. The DDU Agreement also grants the right to extend
the DDU Agreement through December 2028 if compliance with the DDU
Agreement is met and the extension fee associated with the
additional time is paid. Our drilling obligations began with one
well to be spudded and drilled on or before September 1, 2017, and
increased to two wells in year 2018, three wells in year 2019, four
wells in year 2020 and five wells per year in years 2021, 2022 and
2023. The drilling obligations are minimum yearly requirements and
may be exceeded if acceleration is desired. The DDU Agreement
replaces all prior agreements, and will govern future drilling
obligations on the drilling and development unit if the DDU
Agreement is extended. The Company drilled three wells during
fourth quarter, 2018.
There are two
vertical tests wells in the Orogrande Project, the Orogrande Rich
A-11 test well and the University Founders B-19 #1 test well. The
Orogrande Rich A-11 test well was spudded on March 31, 2015,
drilled in the second quarter of 2015 and was evaluated and
numerous scientific tests were performed to provide key data for
the field development thesis. We believe that future utility of
this well may be conversion to a salt water disposal well in the
course of further development of the Orogrande acreage. The
University Founders B-19 #1 was spudded on April 24, 2016 and
drilled in the second quarter of 2016. The well successfully pumped
down completion fluid in the third quarter of 2016 and indications
of hydrocarbons were seen at the surface on this second Orogrande
Project test well. We believe that future utility of this well may
be conversion to a salt water disposal well in the course of
further development of the Orogrande acreage.
During the fourth
quarter of 2017, we took back operational control from Founders on
the Orogrande Project. We were joined by Wolfbone Investments, LLC,
(“Wolfbone”), a company owned by Mr. McCabe. We, along
with Hudspeth, Wolfbone and, for the limited purposes set forth
therein, Pandora, entered into an Assignment of Farmout Agreement
with Founders, (the “Assignment of Farmout Agreement”),
pursuant to which we and Wolfbone will share the remaining
commitments under the Farmout Agreement. All original provisions of
our carried interest were to remain in place including
reimbursement to us on each wellbore. Founders was to remain a 9.5%
working interest owner in the Orogrande Project for the $9.5
million it had spent as of the date of the Assignment of Farmout
Agreement, and such interests were to be carried until $40.5
million is spent by Wolfbone and us, with each contributing 50% of
such capital spend, under the existing agreement. Our working
interest in the Orogrande Project thereby increased by 20.25% to a
total of 67.75% and Wolfbone then owned 20.25%.
Founders was to
operate a newly drilled horizontal well called the University
Founders #A25 (at 5,540’ depth in a 1,000’ lateral)
with supervision from us and our partners. The University Founders
#A25 was spudded on November 28, 2017. During the month of April,
2018, we, MPC and Mr. McCabe were to assume full operational
control including managing drilling plans and timing for all future
wells drilled in the project.
On July 25, 2018,
we and Hudspeth entered into a Settlement & Purchase Agreement
(the “Settlement Agreement”) with Founders (and
Founders Oil & Gas Operating, LLC), Wolfbone and MPC, which
agreement provides for Hudspeth and Wolfbone to each immediately
pay $625,000 and for Hudspeth or the Company and Wolfbone or MPC to
each pay another $625,000 on July 20, 2019, as consideration for
Founders assigning all of its working interest in the oil and gas
leases of the Orogrande Project to Hudspeth and Wolfbone equally.
The assignments to Hudspeth and Wolfbone were made in July when the
first payments were made. The payments to Founders in 2019 are not
securitized. Future well capital spending obligations will require
the same 50% contribution from Hudspeth and 50% from Wolfbone until
such time as the $40.5 million to be spent on the project (as per
our Assignment of Farmout Agreement with Founders) is completed.
The Company estimates that there is still approximately $23 million
remaining to be spent on the project until such time as the capital
expenditures revert back to the percentages of the working interest
owners.
After the
assignment by Founders (for which Hudspeth’s total
consideration is $1,250,000), Hudspeth’s working interest
increased to 72.5%. Additionally, the Settlement Agreement provides
that the Founders parties will assign to the Company, Hudspeth,
Wolfbone and MPC their claims against certain vendors for damages,
if any, against such vendors for negligent services or defective
equipment. Further, the Settlement Agreement has a mutual release
and waivers among the parties.
Rich Masterson, our
consulting geologist, is credited with originating the Orogrande
Project in Hudspeth County in the Orogrande Basin. With Mr.
Masterson’s assistance, we have identified target payzone
depths between 4,100’ and 6,100’ with primary pay,
described as the WolfPenn formation, located at depths of 5,300 to
5,900’. Based on our geologic analysis to date, the Wolfpenn
formation is prospective for oil and high British thermal unit
(Btu) gas, with a 70/30 mix expected, respectively
.
Recently, the
Company drilled three additional test wells in the Orogrande in
order to stay in compliance with University Lands D&D Unit
Agreement, as well as, to test for potential shallow pay zones and
deeper pay zones that may be present on structural plays. At the
time of this writing, the results have not been
published.
Hazel Project in the Midland Basin in
West Texas
Effective April 4,
2016, TEI acquired from MPC a 66.66% working interest in
approximately 12,000 acres in the Midland Basin in exchange for
1,500,000 warrants to purchase shares of our common stock with an
exercise price of $1.00 for five years and a back-in after payout
of a 25% working interest to MPC.
Initial development
of the first well on the property, the Flying B Ranch #1, began
July 9, 2016 and development continued through September 30, 2016.
This well is classified as a test well in the development pursuit
of the Hazel Project. We believe that this wellbore will be
utilized as a salt water disposal well in support of future
development.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
4. OIL & GAS PROPERTIES
-
continued
In October 2016,
the holders of all of our then-outstanding shares of Series C
Preferred Stock (which were issued in July 2016) elected to convert
into a total 33.33% working interest in our Hazel Project, reducing
our ownership from 66.66% to a 33.33% working interest. As of
December 31, 2018, no shares of our Series C Preferred Stock were
outstanding.
On December 27,
2016, drilling activities commenced on the second Hazel Project
well, the Flying B Ranch #2. The well is a vertical test similar to
our first Hazel Project well, the Flying B Ranch #1. Recompletion
in an alternative geological formation for this well was performed
during the three months ended September 30, 2017; however, we
believe that the results were uneconomic for continuing production.
We believe that this wellbore will be utilized as a salt water
disposal well in support of future development.
We commenced
planning to drill the Flying B Ranch #3 horizontal well in the
Hazel Project in June 2017 in compliance with the continuous
drilling obligation. The well was spudded on June 10, 2017. The
well was completed and began production in late September
2017.
Acquisition of Additional Interests in Hazel
Project
On January 30,
2017, we and our then wholly-owned subsidiary, Torchlight
Acquisition Corporation, a Texas corporation (“TAC”),
entered into and closed an Agreement and Plan of Reorganization and
a Plan of Merger with Line Drive Energy, LLC, a Texas limited
liability company (“Line Drive”), and Mr. McCabe, under
which agreements TAC merged with and into Line Drive and the
separate existence of TAC ceased, with Line Drive being the
surviving entity and becoming our wholly-owned subsidiary. Line
Drive, which was wholly-owned by Mr. McCabe, owned certain assets
and securities, including approximately 40.66% of 12,000 gross
acres, 9,600 net acres, in the Hazel Project and 521,739 warrants
to purchase shares of our common stock (which warrants had been
assigned by Mr. McCabe to Line Drive). Upon the closing of the
merger, all of the issued and outstanding shares of common stock of
TAC automatically converted into a membership interest in Line
Drive, constituting all of the issued and outstanding membership
interests in Line Drive immediately following the closing of the
merger, the membership interest in Line Drive held by Mr. McCabe
and outstanding immediately prior to the closing of the merger
ceased to exist, and we issued Mr. McCabe 3,301,739 restricted
shares of our common stock as consideration therefor. Immediately
after closing, the 521,739 warrants held by Line Drive were
cancelled, which warrants had an exercise price of $1.40 per share
and an expiration date of June 9, 2020. A Certificate of Merger for
the merger transaction was filed with the Secretary of State of
Texas on January 31, 2017. Subsequent to the closing the name of
Line Drive Energy, LLC was changed to Torchlight Hazel, LLC. We are
required to drill one well every six months to hold the entire
12,000 acre block for eighteen months, and thereafter two wells
every six months starting June 2018.
Also on January 30,
2017, TEI entered into and closed a Purchase and Sale Agreement
with Wolfbone. Under the agreement, TEI acquired certain of
Wolfbone’s Hazel Project assets, including its interest in
the Flying B Ranch #1 well and the 40 acre unit surrounding the
well, for consideration of $415,000, and additionally, Wolfbone
caused to be cancelled a total of 2,780,000 warrants to purchase
shares of our common stock, including 1,500,000 warrants held by
MPC, and 1,280,000 warrants held by Green Hill Minerals, an entity
owned by Mr. McCabe’s son, which warrant cancellations were
effected through certain Warrant Cancellation Agreements. The
1,500,000 warrants held by MPC that were cancelled had an exercise
price of $1.00 per share and an expiration date of April 4, 2021.
The warrants held by Green Hill Minerals that were cancelled
included 100,000 warrants with an exercise price of $1.73 and an
expiration date of September 30, 2018 and 1,180,000 warrants with
an exercise price of $0.70 and an expiration date of February 15,
2020.
Since Mr. McCabe
held the controlling interest in both Line Drive and Wolfbone, the
transactions were combined for accounting purposes. The working
interest in the Hazel Project was the only asset held by Line
Drive. The warrant cancellation was treated in the aggregate as an
exercise of the warrants with the transfer of the working interests
as the consideration. We recorded the transactions as an increase
in its investment in the Hazel Project working interests of
$3,644,431, which is equal to the exercise price of the warrants
plus the cash paid to Wolfbone.
Upon the closing of
the transactions, our working interest in the Hazel Project
increased by 40.66% to a total ownership of 74%.
Effective June 1,
2017, we acquired an additional 6% working interest from unrelated
working interest owners in exchange for 268,656 shares of common
stock valued at $373,430, increasing our working interest in the
Hazel project to 80%, and an overall net revenue interest of
74-75%.
Mr. Masterson is
credited with originating the Hazel Project in the Midland Basin.
With Mr. Masterson’s assistance, we are targeting prospects
in the Midland Basin that have 150 to 130 feet of thickness, are
likely to require six to eight laterals per bench, have the
potential for twelve to sixteen horizontal wells per section, and
200 long lateral locations, assuming only two benches.
In April 2018, we
announced that we have commenced a process that could result in the
monetization of the Hazel Project. We believe the development
activity at the Hazel Project, coupled with nearby activities of
other oil and gas operators, suggests that this project has
achieved a level of value worth monetizing. We anticipate that the
liquidity that would be provided from selling the Hazel Project
could be redeployed into the Orogrande Project. While this process
is underway, we will take all necessary steps to maintain the
leasehold as required. In May, the working interest partners in the
Hazel Project drilled a shallow well to test a zone at 2500’.
As of this filing, we continue to maintain the leases in good
standing and continue to market the acreage in an effort to focus
on the Orogrande Project.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
4. OIL & GAS PROPERTIES
-
continued
Winkler Project, Winkler County,
Texas
On December 1,
2017, the Agreement and Plan of Reorganization that we and our then
wholly-owned subsidiary, Torchlight Wolfbone Properties, Inc., a
Texas corporation (“TWP”), entered into with MPC and
Warwink Properties, LLC (Warwink Properties) on November 14, 2017
closed. Under the agreement, TWP merged with and into Warwink
Properties and the separate existence of TWP ceased, with Warwink
Properties being the surviving entity and becoming our wholly-owned
subsidiary. Warwink Properties was wholly owned by MPC. Warwink
Properties owns certain assets, including a 10.71875% working
interest in approximately 640 acres in Winkler County, Texas. Upon
the closing of the merger, all of the issued and outstanding shares
of common stock of TWP converted into a membership interest in
Warwink Properties, constituting all of the issued and outstanding
membership interests in Warwink Properties immediately following
the closing of the merger, the membership interest in Warwink
Properties held by MPC and outstanding immediately prior to the
closing of the merger ceased to exist, and we issued MPC 2,500,000
restricted shares of our common stock as consideration. Also on
December 1, 2017, MPC closed its transaction with MECO IV, LLC
(” MECO”), for the purchase and sale of certain assets
as contemplated by the Purchase and Sale Agreement dated November
9, 2017 among MPC, MECO and additional parties thereto (the
“MECO PSA”), to which we are not a party. Under the
MECO PSA, Warwink Properties received a carry from MECO (through
the tanks) of up to $1,179,076 in the next well drilled on the
Winkler County leases. A Certificate of Merger for the merger
transaction was filed with the Secretary of State of Texas on
December 5, 2017.
Also on December 1,
2017, the transactions contemplated by the Purchase Agreement that
TEI entered into with MPC closed. Under the Purchase Agreement,
which was entered into on November 14, 2017, TEI acquired
beneficial ownership of certain of MPC’s assets, including
acreage and wellbores located in Ward County, Texas (the
“Ward County Assets”). As consideration under the
Purchase Agreement, at closing TEI issued to MPC an unsecured
promissory note in the principal amount of $3,250,000, payable in
monthly installments of interest only beginning on January 1, 2018,
at the rate of 5% per annum, with the entire principal amount
together with all accrued interest due and payable on January 1,
2021. In connection with TEI’s acquisition of beneficial
ownership in the Ward County Assets, MPC sold those same assets, on
behalf of TEI, to MECO at closing of the MECO PSA, and accordingly,
TEI received $3,250,000 in cash for its beneficial interest in the
Ward County Assets. Additionally, at closing of the MECO PSA, MPC
paid TEI a performance fee of $2,781,500 in cash as compensation
for TEI’s marketing and selling the Winkler County assets of
MPC and the Ward County Assets as a package to MECO.
Addition to the Winkler
Project
As of May 7, 2018
our Winkler project in the Delaware Basin had begun the drilling
phase of the first Winkler Project well, the UL 21 War-Wink 47 #2H.
Our operating partner, MECO had begun the pilot hole on the
project. The plan is to evaluate the various potential zones for a
lateral leg to be drilled once logging is completed. We expect the
most likely target to be the Wolfcamp A interval. The well is on
320 newly acquired acres offsetting the original leasehold we
entered into in December, 2017. The additional acreage was leased
by our operating partner under the Area of Mutual Interest
Agreement (AMI) and we exercised its right to participate for its
12.5% in the additional 1,080 gross acres at a cash cost of
$447,847 in July, 2018. Our carried interest in the first well, as
outlined in the agreement, was originally planned to be on the
first acreage acquired. That carried interest is being applied to
this new well and will allow MECO to drill and produce potential
revenues sooner than originally planned. The primary leasehold is a
320-acre block directly west of the current position and will allow
for 5,000-foot lateral wells to be drilled. The well was completed
and began production in October, 2018.
Two additional
wells are planned for development by MECO in 2019.
In December, 2018,
the Company began to take measures on its own to market the Warwink
Project in an effort to focus on the Orogrande.
5.
|
RELATED PARTY PAYABLES
|
As of December 31,
2018 and 2017, related party payables consisted of accrued and
unpaid compensation to one of our executive officers totaling
$45,000.
6.
|
COMMITMENTS AND
CONTINGENCIES
|
Leases
The Company has a
noncancelable lease for its office premises that expires on
November 30, 2019 and which requires the payment of base lease
amounts and executory costs such as taxes, maintenance and
insurance. Rental expense for lease was $82,075 and $84,197 for the
years ended December 31, 2018 and 2017, respectively.
Approximate future
minimum rental commitments under the office premises lease
are:
Year Ending December 31,
|
|
Rent
|
|
|
|
|
|
To 2019
Expiration
|
|
|
88,605
|
|
Total
|
|
$
|
88,605
|
|
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
Environmental matters
The Company is
subject to contingencies as a result of environmental laws and
regulations. Present and future environmental laws and regulations
applicable to the Company’s operations could require
substantial capital expenditures or could adversely affect its
operations in other ways that cannot be predicted at this time. As
of December 31, 2018 and 2017, no amounts had been recorded because
no specific liability has been identified that is reasonably
probable of requiring the Company to fund any future material
amounts.
Common Stock
During
the years ended December 31, 2018 and 2017, the Company issued
5,750,000 and -0- shares of common stock, respectively, for cash of
$6,049,734 and $-0-.
During
the years ended December 31, 2018 and 2017, the Company issued
450,000 and 507,897 shares of common stock, respectively, with
total fair values of $545,000 and $579,754 as compensation for
services.
During
the years ended December 31, 2018 and 2017, the Company issued -0-
and 6,420,395 shares of common stock respectively, for lease
interests with total fair values of $-0- and
$6,812,362.
During
the year ended December 31, 2017 the Company issued 1,007,890
shares of common stock, in conversions of notes payable valued at
$1,007,890.
During
the year ended December 31, 2018 the Company issued 172,342 shares
of common stock, in payment in kind on notes payable valued at
$221,024.
During
the year ended December 31, 2018 and 2017, the Company issued
400,000 and 307,349 shares of common stock, respectively, resulting
from warrant exercises for consideration totaling $200,000 and
$243,300.
Warrants and Options
During the years
ended December 31, 2018 and 2017, the Company issued/vested
1,820,000 and 1,808,026 warrants and options with total fair values
of $854,325 and $1,093,104, respectively, as compensation for
services.
A summary of
warrants outstanding as of December 31, 2018 and 2017 by exercise
price and year of expiration is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
0.70
|
-
|
420,000
|
-
|
-
|
-
|
420,000
|
$
0.77
|
100,000
|
-
|
-
|
-
|
-
|
100,000
|
$
1.00
|
25,116
|
-
|
-
|
-
|
-
|
25,116
|
$
1.03
|
-
|
-
|
120,000
|
-
|
-
|
120,000
|
$
1.08
|
37,500
|
-
|
-
|
-
|
-
|
37,500
|
$
1.14
|
-
|
-
|
-
|
-
|
600,000
|
600,000
|
$
1.21
|
-
|
-
|
-
|
-
|
120,000
|
120,000
|
$
1.40
|
-
|
1,121,736
|
|
-
|
-
|
1,121,736
|
$
1.50
|
-
|
|
100,000
|
-
|
-
|
100,000
|
$
1.64
|
-
|
-
|
200,000
|
-
|
-
|
200,000
|
$
1.80
|
-
|
1,250,000
|
-
|
-
|
-
|
1,250,000
|
$
2.00
|
-
|
-
|
400,000
|
-
|
-
|
400,000
|
$
2.23
|
-
|
832,512
|
|
-
|
-
|
832,512
|
$
2.50
|
35,211
|
-
|
-
|
-
|
-
|
35,211
|
$
3.50
|
15,000
|
-
|
-
|
-
|
-
|
15,000
|
$
4.50
|
700,000
|
-
|
-
|
-
|
-
|
700,000
|
$
6.00
|
22,580
|
-
|
-
|
-
|
-
|
22,580
|
|
700,000
|
-
|
-
|
-
|
-
|
700,000
|
|
1,635,407
|
3,624,248
|
820,000
|
-
|
720,000
|
6,799,655
|
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
7.
|
STOCKHOLDERS’ EQUITY
- continued
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
0.50
|
400,000
|
-
|
-
|
-
|
400,000
|
$
0.70
|
-
|
-
|
420,000
|
-
|
420,000
|
$
0.77
|
-
|
100,000
|
-
|
-
|
100,000
|
$
1.00
|
-
|
25,116
|
-
|
-
|
25,116
|
$
1.03
|
-
|
-
|
-
|
120,000
|
120,000
|
$
1.08
|
-
|
37,500
|
-
|
-
|
37,500
|
$
1.40
|
-
|
-
|
1,121,736
|
|
1,121,736
|
$
1.64
|
-
|
-
|
-
|
200,000
|
200,000
|
$
1.73
|
100,000
|
-
|
-
|
-
|
100,000
|
$
1.80
|
-
|
-
|
1,250,000
|
-
|
1,250,000
|
$
2.00
|
1,906,249
|
-
|
-
|
-
|
1,906,249
|
$
2.03
|
2,000,000
|
-
|
-
|
-
|
2,000,000
|
$
2.09
|
2,800,000
|
-
|
-
|
-
|
2,800,000
|
$
2.23
|
-
|
-
|
832,512
|
-
|
832,512
|
$
2.29
|
120,000
|
-
|
-
|
-
|
120,000
|
$
2.50
|
-
|
35,211
|
-
|
-
|
35,211
|
$
2.82
|
38,174
|
-
|
-
|
-
|
38,174
|
$
3.50
|
-
|
15,000
|
-
|
-
|
15,000
|
$
4.50
|
-
|
700,000
|
-
|
-
|
700,000
|
$
6.00
|
523,123
|
22,580
|
-
|
-
|
545,703
|
$
7.00
|
-
|
700,000
|
-
|
-
|
700,000
|
|
7,887,546
|
1,635,407
|
3,624,248
|
320,000
|
13,467,201
|
A summary of stock
options outstanding as of December 31, 2018 and 2017 by exercise
price and year of expiration is presented below:
Exercise
|
|
|
Expiration Date
in
|
|
|
2018
|
|
Price
|
|
|
2019
|
|
|
2020
|
|
|
2021
|
|
|
2022
|
|
|
2023
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
0.97
|
|
|
|
-
|
|
|
|
-
|
|
|
|
259,742
|
|
|
|
-
|
|
|
|
-
|
|
|
|
259,742
|
|
$
|
1.10
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
800,000
|
|
|
|
-
|
|
|
|
800,000
|
|
$
|
1.19
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
600,000
|
|
|
|
600,000
|
|
$
|
1.57
|
|
|
|
1,497,163
|
|
|
|
4,500,000
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5,997,163
|
|
$
|
1.63
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
58,026
|
|
|
|
-
|
|
|
|
58,026
|
|
$
|
1.79
|
|
|
|
-
|
|
|
|
300,000
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
300,000
|
|
|
|
|
|
|
1,497,163
|
|
|
|
4,800,000
|
|
|
|
259,742
|
|
|
|
858,026
|
|
|
|
600,000
|
|
|
|
8,014,931
|
|
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
7.
|
STOCKHOLDERS’ EQUITY
- continued
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
0.97
|
-
|
-
|
-
|
259,742
|
-
|
259,742
|
$
1.10
|
-
|
-
|
-
|
-
|
800,000
|
800,000
|
$
1.57
|
-
|
-
|
5,997,163
|
-
|
-
|
5,997,163
|
$
1.63
|
-
|
-
|
-
|
58,026
|
-
|
58,026
|
$
1.79
|
-
|
-
|
300,000
|
-
|
-
|
300,000
|
|
-
|
-
|
6,297,163
|
317,768
|
800,000
|
7,414,931
|
At
December 31, 2018, the Company 2018 and 2017 had reserved
14,814,586 and 20,882,132 common shares, respectively, for future
exercise of warrants and options.
Warrants
and options granted were valued using the Black-Scholes Option
Pricing Model. The assumptions used in calculating the fair value
of the warrants and options issued were as follows:
2018
|
|
|
Risk-free interest rate
|
2.15% - 2.83%
|
Expected volatility of common stock
|
97% - 119%
|
Dividend yield
|
0.00%
|
Discount due to lack of marketability
|
20%
|
Expected life of option/warrant
|
2.75 to 5 Years
|
|
|
2017
|
|
|
Risk-free interest rate
|
1.47% - 2.06%
|
Expected volatility of common stock
|
106% - 122%
|
Dividend yield
|
0.00%
|
Discount due to lack of marketability
|
20%
|
Expected life of option/warrant
|
2.75 to 5 Years
|
The Company
recorded no income tax provision for 2018 and 2017 because of
losses incurred. The Company has placed a full valuation allowance
against net deferred tax assets because future realization of these
assets is not assured.
The following is a
reconciliation between the federal income tax benefit computed at
statutory federal income tax rates and actual income tax provision
for the years ended December 31, 2018 and 2017:
|
|
|
|
|
|
Federal
income tax benefit at statutory rate
|
(1,221,483
)
|
$
(312,769
)
|
Permanent
Differences
|
505
|
1,640
|
Annual
reconciling adjustment
|
1,449,429
|
719,197
|
Change
in valuation allowance
|
(228,451
)
|
(9,186,334
)
|
Change
in federal tax rate
|
-
|
8,778,266
|
Provision
for income taxes
|
$
-
|
$
-
|
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
8.
|
INCOME TAXES
– continued
|
The tax effects of
temporary differences that gave rise to significant portions of
deferred tax assets and liabilities at December 31, 2018 and
December 31, 2017 are as follows:
|
|
|
Deferred
tax assets:
|
|
|
Net
operating loss carryforward
|
11,968,500
|
$
11,116,332
|
Stock
based compensation
|
4,490,775
|
4,209,307
|
Other
|
371,636
|
302,042
|
Deferred
tax liabilities:
|
|
|
Investment
in oil and gas properties
|
(2,879,086
)
|
(1,447,405
)
|
Net
deferred tax assets and liabilities
|
13,951,825
|
14,180,276
|
Less
valuation allowance
|
(13,951,825
)
|
(14,180,276
)
|
Total
deferred tax assets and liabilities
|
$
-
|
$
-
|
The Company had a
net deferred tax asset related to federal net operating loss
carryforwards of $56,992,857 and $52.934.915 at December 31, 2018
and December 31, 2017, respectively. The federal net operating loss
carryforward will begin to expire in 2033. Realization of the
deferred tax asset is dependent, in part, on generating sufficient
taxable income prior to expiration of the loss carryforwards. The
Company has placed a 100% valuation allowance against the net
deferred tax asset because future realization of these assets is
not assured.
On December 22,
2017, the U.S. government enacted comprehensive legislation titled
the Tax Cuts and Jobs Act. Generally, effective for years 2018 and
beyond, it makes broad and complex changes to the Internal Revenue
Code, including, but not limited to, reducing the federal corporate
income tax rate from 35% to 21%. As of December 31, 2017 we made a
reasonable estimate of the effects on our deferred tax assets and
liabilities of the change in the corporate tax rate to be effective
in 2018. The estimated amount is included our computation of net
deferred tax assets and liabilities and the related valuation
allowance.
On April 10, 2017,
we sold to investors in a private transaction two 12% unsecured
promissory notes with a total of $8,000,000 in principal amount.
Interest only is due and payable on the notes each month at the
rate of 12% per annum, with a balloon payment of the outstanding
principal due and payable at maturity on April 10, 2020. The
holders of the notes will also receive annual payments of common
stock at the rate of 2.5% of principal amount outstanding, based on
a volume-weighted average price. Both notes were sold at an
original issue discount of 94.25% and accordingly, we received
total proceeds of $7,540,000 from the investors. We used the
proceeds for working capital and general corporate purposes, which
includes, without limitation, drilling capital, lease acquisition
capital and repayment of prior debt.
These 12%
promissory notes allow for early redemption. The notes also contain
certain covenants under which we have agreed that, except for
financing arrangements with established commercial banking or
financial institutions and other debts and liabilities incurred in
the normal course of business, we will not issue any other notes or
debt offerings which have a maturity date prior to the payment in
full of the 12% notes, unless consented to by the
holders.
The effective
interest rate is 16.15%.
On April 24, 2017,
we used $2,509,500 of the proceeds from this financing to redeem
and repay a portion of the outstanding 12% Series B Convertible
Unsecured Promissory Notes. Separately, $1,000,000 of the principal
amount of the Series B Notes plus accrued interest was converted
into 1,007,890 shares of common stock and $64,297 was rolled into
the new debt financing.
On February 6,
2018, we sold to an investor in a private transaction a 12%
unsecured promissory note with a principal amount of $4,500,000.
Interest only is due and payable on the note each month at the rate
of 12% per annum, with a balloon payment of the outstanding
principal due and payable at maturity on April 10, 2020. The holder
of the note will also receive annual payments of common stock at
the rate of 2.5% of principal amount outstanding, based on a
volume-weighted average price. We sold the note at an original
issue discount of 96.27% and accordingly, we received total
proceeds of $4,332,150 from the investor. We used the proceeds for
working capital and general corporate purposes, which includes,
without limitation, drilling capital, lease acquisition capital and
repayment of prior debt.
This 12% promissory
note allows for early redemption, provided that if we redeem before
February 6, 2019, we must pay the holder all unpaid interest and
common stock payments on the portion of the note redeemed that
would have been earned through February 6, 2019. The note also
contains certain covenants under which we have agreed that, except
for financing arrangements with established commercial banking or
financial institutions and other debts and liabilities incurred in
the normal course of business, we will not issue any other notes or
debt offerings which have a maturity date prior to the payment in
full of the 12% note, unless consented to by the
holder.
The effective
interest rate is 15.88%.
TORCHLIGHT ENERGY RESOURCES,
INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
9.
|
PROMISSORY NOTES
(CONTINUED)
|
On April 12, 2018,
the holders of the notes described above received 172,342 shares of
common stock as a payment in kind representing the annual payments
of common stock due at the rate of 2.5% of principal amount
outstanding as of April 10, 2018 based on a volume-weighted average
price calculation.
Promissory note
transactions for the year ended December 31, 2018 and 2017 are
summarized as follows:
Unsecured
promissory note balance - December 31, 2016
|
$
-
|
|
|
New
borrowing
|
8,000,000
|
Original
issue discount
|
(460,000
)
|
Proceeds
from borrowing
|
7,540,000
|
|
|
New
note debt issuance costs
|
(279,754
)
|
Accretion
of discount and amortization of debt issuance costs
|
9,035
|
|
|
Unsecured
promissory note balance - December 31, 2017
|
$
7,269,281
|
|
|
New
borrowing
|
4,500,000
|
Original
issue discount
|
(167,850
)
|
Proceeds
from borrowing
|
4,332,150
|
|
|
New
note debt issuance costs
|
(225,000
)
|
Accretion
of discount and amortization of debt issuance costs
|
485,649
|
|
|
|
|
Unsecured
promissory note balance - December 31, 2018
|
$
11,862,080
|
In connection with
the transaction for the acquisition of Warwink Properties effective
December 5, 2017, the Company borrowed $3.25 million from its
Chairman, Greg McCabe on a three-year interest only promissory note
bearing interest at 5% per annum. The Company paid $250,000 as a
principal payment on June 20, 2018 and paid the remaining principal
balance of $3,000,000 on October 19, 2018.
On October 17, 2018, we sold to certain investors in a private
transaction 16% Series C Unsecured Convertible Promissory Notes
with a total principal amount of $6,000,000. Interest and principal
are due and payable on the notes in one balloon payment at maturity
on April 17, 2020. The notes are convertible, at the election of
the holders, into an aggregate 6% working interest in certain oil
and gas leases in Hudspeth County, Texas, known as our
“Orogrande Project.” After an analysis of the
transaction and a
review of applicable accounting
pronouncements
, m
anagement
concluded that the notes issued on October 17, 2018 which contain a
conversion right for holders to convert into a working interest in
the Orogrande Project of the Company, meet a specific scope
exception to the provisions requiring derivative
accounting.
The
notes allow us to redeem them early only upon the event of a
fundamental transaction, such as a merger or sale of substantially
all our assets. The notes provide that the noteholders may
accelerate and declare any and all of the obligations under the
notes to be immediately due and payable in the event of default,
such as nonpayment, failure to perform required conversions,
failure to perform any covenant or agreement under the notes, an
insolvency event, or certain defaults or judgments. As part of the
sale of the of the notes, the noteholders required that McCabe
Petroleum Corporation, a Texas corporation owned by our Chairman
Gregory McCabe (“MPC”), provide them a put option
whereby they have the right to have MPC purchase from them any
unpaid principal amount due on the notes. Additionally, if there is
a fundamental transaction, Mr. McCabe will be required to pay a fee
to each noteholder that elects not to convert or require MPC to
purchase the principal amount under the note, which fee will be
equal to such noteholder’s pro-rata share of a total fee
amount of $1,500,000.
We received total
proceeds of $6,000,000 from the sale of the notes, of which
$3,000,000 was used to pay back the promissory note issued to MPC
on December 1, 2017, which note was due on December 31, 2020. We
used the remaining proceeds for working capital and general
corporate purposes, which includes, without limitation, drilling
and lease acquisition capital.
Prior to entering
into the above transactions, our Board of Directors formed a
special committee composed of independent directors to analyze and
authorize the transactions on behalf of Torchlight Energy
Resources, Inc. and determine whether the transactions are fair to
the company. In this role, the special committee engaged an
independent financial consulting firm which rendered a fairness
opinion deeming that the transactions were fair to the company,
from a financial point of view, and contained terms no less
favorable to the company than those that could be obtained in
arm’s length transactions.
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
10.
|
ASSET RETIREMENT
OBLIGATIONS
|
The following is a
reconciliation of the asset retirement obligation liability for the
year ended December 31, 2018 and 2017:
Asset
retirement obligation – December 31, 2016
|
$
7,051
|
|
|
Accretion
expense
|
216
|
Estimated
liabilities recorded
|
2,007
|
|
|
Asset
retirement obligation – December 31, 2017
|
$
9,274
|
|
|
Accretion
expense
|
390
|
Estimated
liabilities recorded
|
4,689
|
|
|
Asset
retirement obligation – December 31, 2018
|
$
14,353
|
In February and
March, 2019 the Company raised a total of $2,000,000 from investors
through the sale of 14% Series D Unsecured Convertible Promissory
Notes. Principal is payable in a lump sum at maturity on May 11,
2020 with payments of interest payable monthly at the rate of 14%
per annum. Holders of the notes have the right to convert principal
and interest at any time into common stock at a conversion price of
$1.08 per share. The Company has the right to redeem the notes at
any time, provided that the redemption amount must include all
interest that would have been earned through maturity.
Additionally, the
Company received $1,214,078 from the sale of common stock at $.80
per share during February and March, 2019. The offering included
provisions for the cancellation of warrants to purchase common
stock issued to the participants in the agreements in prior
periods.
TORCHLIGHT ENERGY RESOURCES,
INC.
SUPPLEMENTAL INFORMATION ON OIL AND GAS
EXPLORATION
AND PRODUCTION ACTIVITIES
(Unaudited)
The unaudited
supplemental information on oil and gas exploration and production
activities has been presented in accordance with Financial
Accounting Standards Board Accounting Standards Codification Topic
932,
Extractive
Activities—Oil and Gas
and the SEC’s final rule,
Modernization of Oil and Gas
Reporting
.
Investment in oil
and gas properties during the years ended December 31, 2018 and
2017 is detailed as follows:
|
|
2018
|
|
|
2017
|
|
Property acquisition
costs
|
|
$
|
1,072,047
|
|
|
$
|
7,227,362
|
|
Development
costs
|
|
$
|
9,191,041
|
|
|
$
|
8,034,962
|
|
Exploratory
costs
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
$
|
10,263,088
|
|
|
$
|
15,262,324
|
|
Property
acquisition costs presented above exclude interest capitalized into
the full cost pool of $2,020,019 in 2018 and $1,010,868 in
2017.
Property
acquisition cost relates to the Company’s acquisition of
additional working interests in the Orogrande Project in west Texas
and the acquisition of the Warwink Project, also in west Texas. The
development costs include work in the Orogrande, Hazel, and Warwink
projects in west Texas. No development costs were incurred for
Oklahoma properties in 2018.
Oil and Natural Gas
Reserves
Reserve Estimates
SEC Case.
The following tables sets
forth, as of December 31, 2018, our estimated net proved oil and
natural gas reserves, the estimated present value (discounted at an
annual rate of 10%) of estimated future net revenues before future
income taxes (PV-10) and after future income taxes (Standardized
Measure) of our proved reserves and our estimated net probable oil
and natural gas reserves, each prepared using standard geological
and engineering methods generally accepted by the petroleum
industry and in accordance with assumptions prescribed by the
Securities and Exchange Commission (“SEC”). All of our
reserves are located in the United States.
The PV-10 value is
a widely used measure of value of oil and natural gas assets and
represents a pre-tax present value of estimated cash flows
discounted at ten percent. PV-10 is considered a non-GAAP financial
measure as defined by the SEC. We believe that our PV-10
presentation is relevant and useful to our investors because it
presents the estimated discounted future net cash flows
attributable to our proved reserves before taking into account the
related future income taxes, as such taxes may differ among various
companies. We believe investors and creditors use PV-10 as a basis
for comparison of the relative size and value of our proved
reserves to the reserve estimates of other companies. PV-10 is not
a measure of financial or operating performance under GAAP and
neither it nor the Standardized Measure is intended to represent
the current market value of our estimated oil and natural gas
reserves. PV-10 should not be considered in isolation or as a
substitute for the standardized measure of discounted future net
cash flows as defined under GAAP.
The estimates of
our proved reserves and the PV-10 set forth herein reflect
estimated future gross revenue to be generated from the production
of proved reserves, net of estimated production and future
development costs, using prices and costs under existing economic
conditions at December 31, 2018. For purposes of determining
prices, we used the average of prices received for each month
within the 12-month period ended December 31, 2018, adjusted for
quality and location differences, which was $62.04 per barrel of
oil and $3.10 per MCF of gas. This average historical price is not
a prediction of future prices. The amounts shown do not give effect
to non-property related expenses, such as corporate general
administrative expenses and debt service, future income taxes or to
depreciation, depletion and amortization.
|
|
|
|
|
|
|
|
|
|
|
|
Category
|
|
|
|
|
|
|
|
|
|
|
|
Proved
Producing
|
177,300
|
51,100
|
185,817
|
$
4,027
|
$
2,029
|
Proved
Undeveloped
|
797,500
|
105,800
|
815,133
|
$
15,313
|
$
2,895
|
Total
Proved
|
974,800
|
156,900
|
1,000,950
|
$
19,340
|
$
4,924
|
|
|
|
|
|
|
Standardized Measure of Future Net Cash Flows Related to Proved Oil
and Gas Properties
|
$
5,341
|
|
|
|
|
|
|
Probable
Undeveloped
|
0
|
0
|
0
|
$
-
|
$
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Category
|
|
|
|
|
|
|
|
|
|
|
|
Proved
Producing
|
2,300
|
43,800
|
9,600
|
$
132
|
$
96
|
Proved
Nonproducing
|
0
|
0
|
0
|
$
-
|
$
-
|
Total
Proved
|
2,300
|
43,800
|
9,600
|
$
132
|
$
96
|
|
|
|
|
|
|
Standardized Measure of Future Net Cash Flows Related to Proved Oil
and Gas Properties
|
$
123
|
|
|
|
|
|
|
Probable
Undeveloped
|
0
|
0
|
0
|
$
-
|
$
-
|
The upward
revisions of previous estimates from 2017 to 2018 of proved
reserves of 972,500 BBLS and 113,100 MCF results primarily from
2018 reserve report calculations for the Company’s properties
which includes reserves from producing properties in the Hazel and
Warwink Projects for the first time.
Reserve values as
of December 31, 2018 are related to a single producing well in
Oklahoma, one in the Hazel Project, and one in the Warwink
Project.
BOE equivalents are
determined by combining barrels of oil with MCF of gas divided by
six.
Standardized
Measure of Oil & Gas Quantities - Volume
Rollforward
|
Year
Ended December 31, 2018
|
|
|
|
|
The
following table sets forth the Company’s net proved reserves,
including the changes therein, and proved developed
reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
PROVED RESERVES:
|
|
|
|
Beginning
of period
|
2,300
|
43,800
|
9,600
|
Revisions
of previous estimates
|
21,257
|
(7,709
)
|
19,972
|
Extensions,
discoveries and other additions
|
974,110
|
138,670
|
997,222
|
Divestiture
of Reserves
|
-
|
-
|
-
|
Acquisition
of Reserves
|
-
|
-
|
-
|
Production
|
(22,887
)
|
(17,821
)
|
(25,857
)
|
End
of period
|
974,780
|
156,940
|
1,000,937
|
Standardized
Measure of Oil & Gas Quantities - Volume
Rollforward
|
Year
Ended December 31, 2017
|
|
|
|
|
The
following table sets forth the Company’s net proved reserves,
including the changes therein, and proved developed
reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL
PROVED RESERVES:
|
|
|
|
Beginning
of period
|
48,200
|
490,900
|
130,017
|
Revisions
of previous estimates
|
(35,509
)
|
(437,841
)
|
(108,483
)
|
Extensions,
discoveries and other additions
|
-
|
-
|
-
|
Divestiture
of Reserves
|
-
|
-
|
-
|
Acquisition
of Reserves
|
-
|
-
|
-
|
Production
|
(10,391
)
|
(9,259
)
|
(11,934
)
|
End
of period
|
2,300
|
43,800
|
9,600
|
Standardized Measure
of Oil & Gas Quantities
|
Year Ended December
31, 2018 & 2017
|
The standardized
measure of discounted future net cash flows relating to proved oil
and natural gas reserves is as follows :
|
|
|
|
|
|
|
Future cash
inflows
|
$
46,335,070
|
$
240,370
|
Future production
costs
|
(15,042,900
)
|
(108,000
)
|
Future development
costs
|
(11,740,000
)
|
-
|
Future income tax
expense
|
-
|
-
|
Future net cash
flows
|
19,552,170
|
132,370
|
10% annual discount for
estimated timing of cash flows
|
(14,210,840
)
|
(9,102
)
|
Standardized measure of
discounted future net cash flows related to proved
reserves
|
$
5,341,330
|
$
123,268
|
A summary of the changes in the standardized
measure of discounted future net cash flows applicable to proved
oil and natural gas reserves is as follows
:
|
|
|
|
Balance,
beginning of period
|
$
123,268
|
$
340,916
|
Net
change in sales and transfer prices and in production (lifting)
costs related to future production
|
40,762
|
207,241
|
Changes
in estimated future development costs
|
(8,718,999
)
|
116,934
|
Net
change due to revisions in quantity estimates
|
289,740
|
(129,565
)
|
Accretion
of discount
|
1,036
|
28,604
|
Other
|
(385,278
)
|
(43,372
)
|
|
|
|
Net
change due to extensions and discoveries
|
14,467,005
|
-
|
Net
change due to sales of minerals in place
|
-
|
-
|
Sales
and transfers of oil and gas produced during the
period
|
(476,204
)
|
(397,490
)
|
Previously
estimated development costs incurred during the period
|
-
|
-
|
Net
change in income taxes
|
-
|
-
|
Balance,
end of period
|
$
5,341,330
|
$
123,268
|
Due to the inherent
uncertainties and the limited nature of reservoir data, both proved
and probable reserves are subject to change as additional
information becomes available. The estimates of reserves, future
cash flows, and present value are based on various assumptions,
including those prescribed by the SEC, and are inherently
imprecise. Although we believe these estimates are reasonable,
actual future production, cash flows, taxes, development
expenditures, operating expenses, and quantities of recoverable oil
and natural gas reserves may vary substantially from these
estimates.
In estimating
probable reserves, it should be noted that those reserve estimates
inherently involve greater risk and uncertainty than estimates of
proved reserves. While analysis of geoscience and engineering data
provides reasonable certainty that proved reserves can be
economically producible from known formations under existing
conditions and within a reasonable time, probable reserves involve
less certainty than reserves with a higher classification due to
less data to support their ultimate recovery. Probable reserves
have not been discounted for the additional risk associated with
future recovery. Prospective investors should be aware that as the
categories of reserves decrease with certainty, the risk of
recovering reserves at the PV-10 calculation increases. The
reserves and net present worth discounted at 10% relating to the
different categories of proved and probable have not been adjusted
for risk due to their uncertainty of recovery and thus are not
comparable and should not be summed into total
amounts.
Reserve Estimation Process, Controls and
Technologies
The reserve
estimates, including PV-10 estimates, set forth above were prepared
by PeTech Enterprises, Inc. for the Company’s Properties in
Oklahoma. A copy of their full reports with regard to our reserves
is attached as Exhibit 99.1 to this annual report on Form 10-K.
These calculations were prepared using standard geological and
engineering methods generally accepted by the petroleum industry
and in accordance with SEC financial accounting and reporting
standards.
Results of Operations for Oil and Gas
Producing Activities
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
2018
|
|
Total
|
|
|
Texas
|
|
|
Oklahoma
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas
revenue
|
|
$
|
1,282,362
|
|
|
$
|
1,248,004
|
|
|
$
|
34,358
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs
|
|
$
|
806,158
|
|
|
$
|
787,681
|
|
|
$
|
18,477
|
|
Depreciation, depletion, and
amortization
|
|
$
|
1,173,752
|
|
|
$
|
464,318
|
|
|
$
|
709,434
|
|
Exploration
expenses
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
|
1,979,910
|
|
|
$
|
1,251,999
|
|
|
$
|
727,911
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax
expense
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of Operations
(excluding corporate overhead and interest costs)
|
|
$
|
(697,548
|
)
|
|
$
|
(3,995
|
)
|
|
$
|
(693,553
|
)
|