Notes to the Consolidated Financial Statements
(Unaudited)
Petro River Oil Corp. (the “Company”, “we”, “us” or “our”) is an independent energy company focused
on the development of conventional oil and gas assets with low
discovery and development costs, utilizing modern technology. The
Company is currently focused on moving forward with drilling wells
on several of its properties owned directly and indirectly through
its interest in Horizon Energy Partners, LLC
(“Horizon
Energy”), as well as
exploring additional opportunities with Horizon Energy and other
industry-leading partners. We are also exploring various options to
continue as a going concern, including asset sales, mergers, and
other options that would substantially reduce our operating and
other costs, including public company costs. See
Going Concern and
Management’s Plan in Note
2 below.
The Company’s core holdings are in the Mid-Continent Region
in Oklahoma, including in Osage County and Kay County, Oklahoma.
Following the acquisition of Horizon I Investments, LLC
(“Horizon
Investments”) in December
2015, the Company has additional exposure to a portfolio of
domestic and international oil and gas assets consisting of
conventional plays diversified across project type, geographic
location and risk profile, as well as access to a broad network of
industry leaders from Horizon Investment’s interest in
Horizon Energy. Horizon Energy is an oil and gas exploration
and development company owned and managed by former senior oil and
gas executives. It has a portfolio of domestic and
international assets. Each of the assets in the Horizon Energy
portfolio is characterized by low initial capital expenditure
requirements and strong risk reward
characteristics.
The Company’s prospects in Oklahoma are owned directly by the
Company and indirectly through Spyglass Energy Group, LLC
(“Spyglass”), a wholly owned subsidiary of Bandolier
Energy, LLC (“Bandolier”). As of January 31, 2018, Bandolier became
wholly-owned by the Company. Bandolier has a 75% working interest
in an 87,754-acre concession in Osage County, Oklahoma. The
remaining 25% working interest is held by the operator, Performance
Energy, LLC.
Effective September 24, 2018, the Company acquired a 66.67%
membership interest in LBE Partners, LLC, a Delaware limited
liability company (“LBE
Partners”), from ICO
Liquidating Trust, LLC, in exchange for 300,000 restricted shares
of the Company’s common stock, par value $0.00001 per
share. LBE Partners has varying
working interests in multiple oil and gas producing wells located
in Texas.
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2.
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Going Concern and Management’s Plan
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The
accompanying consolidated financial statements have been prepared
on a going concern basis, which contemplates the realization of
assets and the satisfaction of liabilities in the normal course of
business. The Company has incurred significant operating losses
since its inception. As of October 31, 2019, the Company had an
accumulated deficit of approximately $53.8 million, had a working
capital deficit of approximately $276,600, and had cash and cash
equivalents of approximately $754,000. As a result of the
utilization of cash in its operating activities, and the
development of its assets, the Company has incurred losses since it
commenced operations. The Company’s primary source of
operating funds since inception has been debt and equity
financings. In addition, the Company has a limited operating
history prior to its acquisition of Bandolier. These
matters raise substantial doubt about the Company’s
ability to continue as a going concern for the twelve months
following the issuance of these financial statements.
The
consolidated financial statements do not include any adjustments
relating to the recoverability and classification of asset amounts
or the classification of liabilities that might be necessary should
the Company be unable to continue as a going concern.
Management
is currently focused on limiting operating expenses, deferring
certain development activity, and exploring farm-in and joint
venture opportunities for the Company’s oil and gas assets.
In addition, management is currently exploring various options to
substantially reduce operating expenses and maximize the value of
its assets, including its interest in Bandolier and Horizon Energy.
Such options include, but are not limited to, asset sales, mergers,
voluntarily terminating
and/or suspending our statutory reporting obligations under
the Securities Exchange Act of 1934, as amended, and other
options that would allow the Company to continue as a going
concern. No assurances can be given that management will be
successful. In addition, Management may raise additional capital
through debt and equity instruments in order to execute its
business, operating and development plans. Management can provide
no assurances that the Company will be successful in its capital
raising or other efforts to continue as a going
concern.
The
accompanying unaudited interim consolidated financial statements
are prepared in accordance with generally accepted accounting
principles in the United States (“U.S. GAAP”) and include the
accounts of the Company and its wholly owned subsidiaries. All
material intercompany balances and transactions have been
eliminated in consolidation. Non–controlling interest
represents the minority equity investment in the Company’s
subsidiaries, plus the minority investors’ share of the net
operating results and other components of equity relating to the
non–controlling interest.
These
unaudited consolidated financial statements include the Company and
the following subsidiaries:
Bandolier
Energy, LLC; Horizon I Investments, LLC; and MegaWest Energy USA
Corp. and MegaWest Energy USA Corp.’s wholly owned
subsidiaries:
MegaWest
Energy Texas Corp.
MegaWest
Energy Kentucky Corp.
MegaWest
Energy Missouri Corp.
As a
result of the acquisition of membership interest in the Osage
County Concession in November 2017, Bandolier is now a wholly-owned
subsidiary of the Company and the Company consolidates 100% of the
financial information of Bandolier. Bandolier operates the
Company’s Oklahoma oil and gas properties.
As a
result of the acquisition of a 66.67% membership interest in LBE
Partners effective on September 24, 2018, LBE Partners is now a
subsidiary of the Company, and the Company consolidates the
financial information of LBE Partners with a non-controlling
interest in the remaining 33.33% membership interest. LBE Partners
has varying working interest in multiple oil fields located in
Texas.
The
unaudited consolidated financial information furnished herein
reflects all adjustments, consisting solely of normal recurring
items, which in the opinion of management are necessary to fairly
state the financial position of the Company and the results of its
operations for the periods presented. This report should be read in
conjunction with the Company’s consolidated financial
statements and notes thereto included in the Company’s Annual
Report on Form 10-K for the year ended April 30, 2019, filed with
the Securities and Exchange Commission (the “SEC”) on August 13, 2019, as
amended on August 14, 2019. The Company assumes that the users of
the interim financial information herein have read or have access
to the audited financial statements for the preceding fiscal year
and that the adequacy of additional disclosure needed for a fair
presentation may be determined in that context. Accordingly,
footnote disclosure, which would substantially duplicate the
disclosure contained in the Company’s Annual Report on Form
10-K, as amended, for the year ended April 30, 2019, has been
omitted. The results of operations for the interim periods
presented are not necessarily indicative of results for the entire
year ending April 30, 2020.
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4.
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Significant Accounting Policies
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The
preparation of financial statements in conformity with U.S. GAAP
requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenue and expense during
the reporting period. Actual results could differ from those
estimates.
The
Company’s financial statements are based on a number of
significant estimates, including oil and natural gas reserve
quantities, which are the basis for the calculation of
depreciation, depletion and impairment of oil and natural gas
properties, and timing and costs associated with its asset
retirement obligations, as well as those related to the fair value
of stock options, stock warrants and stock issued for services.
Although management believes that its estimates and assumptions
used in preparation of the financial statements are appropriate,
actual results could differ from those
estimates.
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(b)
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Cash
and Cash Equivalents:
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Cash
and cash equivalents include all highly liquid monetary instruments
with original maturities of three months or less when purchased.
These investments are carried at cost, which approximates fair
value. Financial instruments that potentially subject the Company
to concentrations of credit risk consist primarily of cash
deposits. The Company maintains its cash in institutions insured by
the Federal Deposit Insurance Corporation (“FDIC”). At times, the
Company’s cash and cash equivalent balances may be uninsured
or in amounts that exceed the FDIC insurance limits. The Company
has not experienced any loses on such accounts.
As of
October 31, 2019, approximately $252,000 of cash and cash
equivalents exceed the FDIC insurance limits.
Receivables
that management has the intent and ability to hold for the
foreseeable future are reported in the balance sheet at outstanding
principal adjusted for any charge-offs and the allowance for
doubtful accounts. Losses from uncollectible receivables are
accrued when both of the following conditions are met: (a)
information available before the financial statements are issued or
are available to be issued indicates that it is probable that an
asset has been impaired at the date of the financial statements,
and (b) the amount of the loss can be reasonably estimated. These
conditions may be considered in relation to individual receivables
or in relation to groups of similar types of receivables. If the
conditions are met, an accrual shall be made even though the
particular receivables that are uncollectible may not be
identifiable. The Company reviews each receivable individually for
collectability and performs on-going credit evaluations of its
customers and adjusts credit limits based upon payment history and
the customer’s current credit worthiness, as determined by
the review of their current credit information, and determines the
allowance for doubtful accounts based on historical write-off
experience, customer specific facts and general economic conditions
that may affect a client’s ability to pay. Bad debt expense
is included in general and administrative expenses, if
any.
Credit
losses for receivables (uncollectible receivables), which may be
for all or part of a particular receivable, shall be deducted from
the allowance. The related receivable balance shall be charged off
in the period in which the receivables are deemed uncollectible.
Recoveries of receivables previously charged off shall be recorded
when received. The Company charges off its account receivables
against the allowance after all means of collection have been
exhausted and the potential for recovery is considered
remote.
The
allowance for doubtful accounts at October 31, 2019 and April 30,
2019 was $0.
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(d)
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Oil and
Gas Operations:
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Oil and Gas Properties: The Company uses the full-cost
method of accounting for its exploration and development
activities. Under this method of accounting, the costs of both
successful and unsuccessful exploration and development activities
are capitalized as oil and gas property and equipment. Proceeds
from the sale or disposition of oil and gas properties are
accounted for as a reduction to capitalized costs unless the gain
or loss would significantly alter the relationship between
capitalized costs and proved reserves of oil and natural gas
attributable to a country, in which case a gain or loss would be
recognized in the consolidated statements of operations. All of the
Company’s oil and gas properties are located within the
continental United States, its sole cost center.
Oil and
gas properties may include costs that are excluded from costs being
depleted. Oil and gas costs excluded represent investments in
unproved properties and major development projects in which the
Company owns a direct interest. These unproved property costs
include non-producing leasehold, geological and geophysical costs
associated with leasehold or drilling interests and in process
exploration drilling costs. All costs excluded are reviewed at
least annually to determine if impairment has
occurred.
Long-lived
assets are reviewed for impairment whenever events or changes in
circumstances indicate that the historical cost carrying value of
an asset may no longer be appropriate. The Company recorded no
impairment in the consolidated statements of operations for the six
months ended October 31, 2019 and 2018, respectively.
Proved Oil and Gas Reserves: Proved oil and gas reserves are
the estimated quantities of crude oil, natural gas and natural gas
liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. All of
the Company’s oil and gas properties with proved reserves
were impaired to the salvage value prior to the Company’s
acquisition of its interest in Bandolier. The price used to
establish economic viability is the average price during the
12-month period preceding the end of the entity’s fiscal year
and calculated as the un-weighted arithmetic average of the
first-day-of-the-month price for each month within such 12-month
period.
Depletion, Depreciation and Amortization: Depletion,
depreciation and amortization is provided using the
unit-of-production method based upon estimates of proved oil and
gas reserves with oil and gas production being converted to a
common unit of measure based upon their relative energy content.
Investments in unproved properties and major development projects
are not amortized until proved reserves associated with the
projects can be determined or until impairment occurs. If the
results of an assessment indicate that the properties are impaired,
the amount of the impairment is deducted from the capitalized costs
to be amortized. Once the assessment of unproved properties is
complete and when major development projects are evaluated, the
costs previously excluded from amortization are transferred to the
full cost pool and amortization begins. The amortizable base
includes estimated future development costs and, where significant,
dismantlement, restoration and abandonment costs, net of estimated
salvage value.
In
arriving at rates under the unit-of-production method, the
quantities of recoverable oil and natural gas reserves are
established based on estimates made by the Company’s
geologists and engineers, which require significant judgment, as
does the projection of future production volumes and levels of
future costs, including future development costs. In addition,
considerable judgment is necessary in determining when unproved
properties become impaired and in determining the existence of
proved reserves once a well has been drilled. All of these
judgments may have significant impact on the calculation of
depletion expenses. There have been no material changes in the
methodology used by the Company in calculating depletion,
depreciation and amortization of oil and gas properties under the
full cost method during the six months ended October 31, 2019 and
2018.
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(e)
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Fair
Value of Financial Instruments:
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The
Company follows paragraph 825-10-50-10 of the FASB Accounting
Standards Codification for disclosures about fair value of its
financial instruments and paragraph 820-10-35-37 of the FASB
Accounting Standards Codification (“Paragraph 820-10-35-37”) to
measure the fair value of its financial instruments. Paragraph
820-10-35-37 establishes a framework for measuring fair value in
U.S. GAAP and expands disclosures about fair value measurements. To
increase consistency and comparability in fair value measurements
and related disclosures, Paragraph 820-10-35-37 establishes a fair
value hierarchy that prioritizes the inputs to valuation techniques
used to measure fair value into three (3) broad levels. The fair
value hierarchy gives the highest priority to quoted prices
(unadjusted) in active markets for identical assets or liabilities
and the lowest priority to unobservable inputs. The three (3)
levels of fair value hierarchy defined by Paragraph 820-10-35-37
are described below:
Level 1
Quoted market prices available in active
markets for identical assets or liabilities as of the reporting
date.
Level
2 Pricing inputs other than quoted
prices in active markets included in Level 1, which are either
directly or indirectly observable as of the reporting
date.
Level 3
Pricing inputs that are generally observable
inputs and not corroborated by market data.
Financial
assets are considered Level 3 when their fair values are determined
using pricing models, discounted cash flow methodologies or similar
techniques and at least one significant model assumption or input
is unobservable.
The
fair value hierarchy gives the highest priority to quoted prices
(unadjusted) in active markets for identical assets or liabilities
and the lowest priority to unobservable inputs. If the inputs used
to measure the financial assets and liabilities fall within more
than one level described above, the categorization is based on the
lowest level input that is significant to the fair value
measurement of the instrument.
The
carrying amount of the Company’s financial assets and
liabilities, such as cash, prepaid expenses, and accounts payable
and accrued liabilities approximate their fair value because of the
short maturity of those instruments.
Transactions
involving related parties cannot be presumed to be carried out on
an arm’s-length basis, as the requisite conditions of
competitive, free-market dealings may not exist. Representations
about transactions with related parties, if made, shall not imply
that the related party transactions were consummated on terms
equivalent to those that prevail in arm’s-length transactions
unless such representations can be substantiated.
The
Company applies the accounting standards for distinguishing
liabilities from equity under U.S. GAAP when determining the
classification and measurement of its preferred stock. Preferred
shares subject to mandatory redemption are classified as liability
instruments and are measured at fair value. Conditionally
redeemable preferred shares (including preferred shares that
feature redemption rights that are either within the control of the
holder or subject to redemption upon the occurrence of uncertain
events not solely within the Company’s control) are
classified as temporary equity. At all other times, preferred
shares are classified as permanent equity.
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(g)
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Derivative
Liabilities:
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The
Company evaluates its options, warrants, convertible notes, or
other contracts, if any, to determine if those contracts or
embedded components of those contracts qualify as derivatives to be
separately accounted for in accordance with paragraph 815-10-05-4
and Section 815-40-25 of the FASB Accounting Standards
Codification. The result of this accounting treatment is that the
fair value of the embedded derivative is marked-to-market each
balance sheet date and recorded as either an asset or a liability.
The change in fair value is recorded in the consolidated statement
of operations as other income or expense. Upon conversion, exercise
or cancellation of a derivative instrument, the instrument is
marked to fair value at the date of conversion, exercise or
cancellation and then the related fair value is reclassified to
equity.
In
circumstances where the embedded conversion option in a convertible
instrument is required to be bifurcated and there are also other
embedded derivative instruments in the convertible instrument that
are required to be bifurcated, the bifurcated derivative
instruments are accounted for as a single, compound derivative
instrument.
The
classification of derivative instruments, including whether such
instruments should be recorded as liabilities or as equity, is
re-assessed at the end of each reporting period. Equity instruments
that are initially classified as equity that become subject to
reclassification are reclassified to liability at the fair value of
the instrument on the reclassification date. Derivative instrument
liabilities will be classified in the balance sheet as current or
non-current based on whether or not net-cash settlement of the
derivative instrument is expected within 12 months of the balance
sheet date.
The
Company adopted Section 815-40-15 of the FASB Accounting Standards
Codification (“Section
815-40-15”) to determine whether an
instrument (or an embedded feature) is indexed to the
Company’s own stock. Section 815-40-15 provides
that an entity should use a two-step approach to evaluate whether
an equity-linked financial instrument (or embedded feature) is
indexed to its own stock, including evaluating the
instrument’s contingent exercise and settlement
provisions.
The
Company utilizes a binomial option pricing model to compute the
fair value of the derivative liability and to mark to market the
fair value of the derivative at each balance sheet date. The
Company records the change in the fair value of the derivative as
other income or expense in the consolidated statements of
operations.
The
Company had derivative liabilities of $1,283,600 and $4,191,754 as
of October 31, 2019 and April 30, 2019, respectively.
Income Tax Provision
The
Company utilizes the asset and liability method in accounting for
income taxes. Under this method, deferred tax assets and
liabilities are recognized for operating loss and tax credit
carry-forwards and for the future tax consequences attributable to
differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases.
Deferred tax assets and liabilities are measured using enacted tax
rates expected to apply to taxable income in the year 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 the results of operations in
the period that includes the enactment date. A valuation allowance
is recorded to reduce the carrying amounts of deferred tax assets
unless it is more likely than not that the value of such assets
will be realized.
The
Company may recognize the tax benefit from an uncertain tax
position only if it is more likely than not that the tax position
will be sustained on examination by the taxing authorities, based
on the technical merits of the position. The tax benefits
recognized in the financial statements from such a position should
be measured based on the largest benefit that has a greater than
fifty percent (50%) likelihood of being realized upon ultimate
settlement.
Management
makes judgments as to the interpretation of the tax laws that might
be challenged upon an audit and cause changes to previous estimates
of tax liability. In addition, the Company operates within multiple
taxing jurisdictions and is subject to audit in these
jurisdictions. In management’s opinion, adequate provisions
for income taxes have been made for all years. If actual taxable
income by tax jurisdiction varies from estimates, additional
allowances or reversals of reserves may be necessary.
Uncertain Tax Positions
The
Company evaluates uncertain tax positions to recognize a tax
benefit from an uncertain tax position only if it is more likely
than not that the tax position will be sustained on examination by
the taxing authorities based on the technical merits of the
position. Those tax positions failing to qualify for initial
recognition are recognized in the first interim period in which
they meet the more likely than not standard or are resolved through
negotiation or litigation with the taxing authority, or upon
expiration of the statute of limitations. De-recognition of a tax
position that was previously recognized occurs when an entity
subsequently determines that a tax position no longer meets the
more likely than not threshold of being sustained. At October 31,
2019 and April 30, 2019, the Company had $0 and $0, respectively,
of liabilities for uncertain tax positions.
The
Company is subject to ongoing tax exposures, examinations and
assessments in various jurisdictions. Accordingly, the Company may
incur additional tax expense based upon the outcomes of such
matters. In addition, when applicable, the Company will adjust tax
expense to reflect the Company’s ongoing assessments of such
matters, which require judgment and can materially increase or
decrease its effective rate as well as impact operating
results.
The
number of years with open tax audits varies depending on the tax
jurisdiction. The Company’s major taxing jurisdictions
include the United States (including applicable
states).
ASU
2014-09, “Revenue from
Contracts with Customers (Topic 606),” supersedes the
revenue recognition requirements and industry-specific guidance
under Revenue Recognition (Topic
605). Topic 606 requires an entity to recognize revenue when
it transfers promised goods or services to customers in an amount
that reflects the consideration the entity expects to be entitled
to in exchange for those goods or services. The Company adopted
Topic 606 on May 1, 2018, using the modified retrospective method
applied to contracts that were not completed as of May 1,
2018. Under the modified retrospective method, prior period
financial positions and results will not be adjusted. The
cumulative effect adjustment recognized in the opening balances
included no significant changes as a result of this adoption. Refer
to Note 11 – Revenue from
Contracts with Customers for additional
information.
The
Company’s revenue is comprised of revenue from exploration
and production activities as well as royalty revenue related to a
royalty interest agreement executed in February 2018. The
Company’s oil is sold primarily to marketers, gatherers, and
refiners. Natural gas is sold primarily to interstate and
intrastate natural-gas pipelines, direct end-users, industrial
users, local distribution companies, and natural-gas marketers.
NGLs are sold primarily to direct end-users, refiners, and
marketers. Payment is generally received from the customer in the
month following delivery.
Contracts
with customers have varying terms, including spot sales or
month-to-month contracts, contracts with a finite term, and
life-of-field contracts where all production from a well or group
of wells is sold to one or more customers. The Company recognizes
sales revenue 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.
Revenue
is recognized for the sale of the Company’s net share of
production volumes. Sales on behalf of other working interest
owners and royalty interest owners are not recognized as
revenue.
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(j)
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Stock-Based
Compensation:
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Generally,
all forms of stock-based compensation, including stock option
grants, warrants, and restricted stock grants are measured at their
fair value utilizing an option pricing model on the award’s
grant date, based on the estimated number of awards that are
ultimately expected to vest.
Under
fair value recognition provisions, the Company recognizes
equity–based compensation net of an estimated forfeiture rate
and recognizes compensation cost only for those shares expected to
vest over the requisite service period of the award.
The
fair value of an option award is estimated on the date of grant
using the Black–Scholes option valuation model. The
Black–Scholes option valuation model requires the development
of assumptions that are input into the model. These assumptions are
the expected stock volatility, the risk–free interest rate,
the option’s expected life, the dividend yield on the
underlying stock and the expected forfeiture rate. Expected
volatility is calculated based on the historical volatility of the
Company’s common stock over the expected option life and
other appropriate factors. Risk–free interest rates are
calculated based on continuously compounded risk–free rates
for the appropriate term. The dividend yield is assumed to be zero,
as the Company has never paid or declared any cash dividends on its
common stock and does not intend to pay dividends on the common
stock in the foreseeable future. The expected forfeiture rate is
estimated based on historical experience.
Determining
the appropriate fair value model and calculating the fair value of
equity–based payment awards requires the input of the
subjective assumptions described above. The assumptions used in
calculating the fair value of equity–based payment awards
represent management’s best estimates, which involve inherent
uncertainties and the application of management’s judgment.
As a result, if factors change and the Company uses different
assumptions, the equity–based compensation expense could be
materially different in the future. In addition, the Company is
required to estimate the expected forfeiture rate and recognize
expense only for those shares expected to vest. If the actual
forfeiture rate is materially different from the Company’s
estimate, the equity–based compensation expense could be
significantly different from what the Company has recorded in the
current period.
The
Company determines the fair value of the stock–based payments
to non-employees as either the fair value of the consideration
received or the fair value of the equity instruments issued,
whichever is more reliably measurable. If the fair value of
the equity instruments issued is used, it is measured using the
stock price and other measurement assumptions as of the earlier of
either (1) the date at which a commitment for performance by the
counterparty to earn the equity instruments is reached, or (2) the
date at which the counterparty’s performance is
complete.
The
expense resulting from stock-based compensation is recorded as
general and administrative expenses in the consolidated statement
of operations, depending on the nature of the services
provided.
Basic
earnings (loss) per share (“EPS”) is computed by dividing net
income (loss) available to common stockholders (numerator) by the
weighted average number of shares outstanding (denominator) during
the period. Diluted EPS gives effect to all dilutive potential
common stock outstanding during the period using the treasury stock
method and convertible preferred stock using the if converted
method. In computing diluted EPS, the average stock price for the
period is used to determine the number of shares assumed to be
purchased from the exercise of stock options and/or warrants.
Diluted EPS excluded all dilutive potential shares if their effect
is anti-dilutive. For the six months ended October 31, 2019, the
dilutive potential common stock outstanding during the period
included only the portion of potentially issuable shares of common
stock related to options and warrants that were not
anti-dilutive.
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(n)
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Recent
Accounting Pronouncements:
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In
February 2016, the Financial Accounting Standards Board
(“FASB”) issued
ASU No. 2016-02, “Leases
(Topic 842)”. The new lease guidance supersedes Topic 840. The core
principle of the guidance is that entities should recognize the
assets and liabilities that arise from leases. Topic 840 does not
apply to leases to
explore for or use minerals, oil, natural gas and similar
non-regenerative resources, including the intangible right to
explore for those natural resources and rights to use the land in
which those natural resources are contained. In July 2018, the FASB
issued ASU No. 2018-11, “Leases (Topic 842): Targeted
Improvements”, which provides entities with an
alternative modified transition method to elect not to recast the
comparative periods presented when adopting Topic 842. The Company adopted
Topic 842 as of May 1, 2019, using the alternative modified
transition method, for which, comparative periods, including
the disclosures
related to those periods, are not restated.
In
addition, the Company elected practical expedients provided by the
new standard whereby, the Company has elected to not reassess its
prior conclusions about lease identification, lease classification,
and initial direct costs and to retain off-balance sheet treatment
of short-term leases (i.e., 12 months or less and does not contain
a purchase option that the Company is reasonably certain to
exercise). As a result of the short-term expedient election, the
Company has no leases that require the recording of a net lease
asset and lease liability on the Company’s consolidated
balance sheet or have a material impact on consolidated earnings or
cash flows as of October 31, 2019. Moving forward, the Company will
evaluate any new lease commitments for application of Topic
842.
In September
2016, the FASB issued
ASU 2016-13, Financial
Instruments – Credit Losses. ASU 2016-13 was
issued to provide more decision-useful information about the
expected credit losses on financial instruments and changes the
loss impairment methodology. ASU 2016-13 is effective for
reporting periods beginning after December 15, 2019 using
a modified retrospective adoption method. A prospective transition
approach is required for debt securities for which an
other-than-temporary impairment had been recognized before the
effective date. The Company is currently assessing the impact this
accounting standard will have on its financial statements and
related disclosures.
In June
2018, the FASB issued Accounting Standards Update (ASU) No.
2018-07, Compensation –
Stock Compensation (Topic 718): Improvements to Nonemployee
Share-Based Payment Accounting. Under the new standard,
companies will no longer be required to value non-employee awards
differently from employee awards. Companies will value all equity
classified awards at their grant-date under ASC 718 and forgo
revaluing the award after the grant date. ASU 2018-07 is effective
for annual reporting periods beginning after December 15, 2018,
including interim reporting periods within that reporting period.
Early adoption is permitted, but no earlier than the
Company’s adoption date of Topic 606, Revenue from Contracts with Customers
(as described above under Revenue Recognition). The Company adopted
the standard during the quarter ended July 31, 3019 and the
adoption did not have an impact on the Company’s consolidated
financial statements.
In
August 2018, the FASB issued ASU 2018-13, “Fair Value Measurement (Topic 820):
Disclosure Framework —Changes to the Disclosure Requirements
for Fair Value Measurement”. This update is to improve
the effectiveness of disclosures in the notes to the financial
statements by facilitating clear communication of the information
required by U.S. GAAP that is most important to users of each
entity’s financial statements. The amendments in this update
apply to all entities that are required, under existing U.S. GAAP,
to make disclosures about recurring or nonrecurring fair value
measurements. The amendments in this update are effective for all
entities for fiscal years beginning after December 15, 2019, and
interim periods within those fiscal years. The Company is currently
evaluating this guidance and the impact of this update on its
consolidated financial statements.
The
Company does not expect the adoption of any recently issued
accounting pronouncements to have a significant impact on its
financial position, results of operations, or cash
flows.
The
Company has evaluated all transactions through the date the
consolidated financial statements were issued for subsequent event
disclosure consideration.
|
5.
|
Acquisition of Membership Interest in LBE Partners,
LLC
|
On October 2, 2018, the Company, ICO Liquidating Trust, LLC
(“ICO”)
and LBE Partners, which owns various working interests in several
oil and gas wells located in the Hardin oil field in Liberty,
Texas, entered into a Membership Interest Purchase Agreement (the
“LBE Purchase
Agreement”),
effective September 24, 2018, pursuant to which the Company
purchased a 66.67% membership interest in LBE Partners from ICO in
exchange for 300,000 shares of the Company’s common stock
valued at $333,000 based on the market value of the stock on the
grant date. Both ICO and LBE Partners are managed by Scot Cohen,
the Company’s Executive Chairman.
The
Company recorded the purchase of LBE Partners using the acquisition
method of accounting as specified in ASC 805 “Business Combinations.” This
method of accounting requires the acquirer to record the net assets
and liabilities acquired at the historical cost of LBE Partners
because the Company determined that this acquisition was a related
party transaction.
The
following table summarizes, on an unaudited pro forma basis, the
results of operations of the Company as though the acquisition had
occurred as of May 1, 2018 (the beginning of the prior fiscal
year). The pro-forma amounts presented are not necessarily
indicative of either the actual operation results had the
acquisition transaction occurred as of May 1, 2018.
|
|
For
the Three Months Ended
October
31, 2018
|
|
|
|
|
|
|
Revenue
|
$410,432
|
$77,712
|
$488,144
|
|
Net
loss
|
(575,477)
|
(23,724)
|
(599,201)
|
|
Loss per share of
common share – basic and diluted
|
$(0.03)
|
|
$(0.03)
|
|
Weighted average
number of common shares outstanding – basic and
diluted
|
17,712,126
|
300,000
|
18,012,126
|
|
|
For
the Six Months Ended
October
31, 2018
|
|
|
|
|
|
|
Revenue
|
$984,497
|
$229,715
|
$1,214,212
|
|
Net income
(loss)
|
(995,708)
|
11,781
|
(983,927)
|
|
Loss per share of
common share – basic and diluted
|
$(0.06)
|
|
$(0.05)
|
|
Weighted average
number of common shares outstanding – basic and
diluted
|
17,607,863
|
300,000
|
17,907,863
|
For the
six months ended October 31, 2019, the changes in
non–controlling interest in LBE were as follows:
|
Non–controlling
interest at April 30, 2019
|
$651,162
|
|
Non–controlling
share of net loss
|
(34,906)
|
|
Non–controlling
interest at October 31, 2019
|
$616,256
|
The
following table summarizes the activity in oil and gas assets by
project:
|
Cost
|
|
|
|
|
|
Balance, May 1,
2019
|
$4,706,261
|
$1,162,671
|
$100,000
|
$5,968,932
|
|
Additions
|
139,523
|
-
|
-
|
139,523
|
|
Change in
estimates
|
(32,093)
|
(6,975)
|
-
|
(39,068)
|
|
Depreciation,
depletion and amortization
|
(133,155)
|
(59,597)
|
-
|
(192,752)
|
|
Impairment of oil
and gas assets
|
-
|
-
|
-
|
-
|
|
Balance, October
31, 2019
|
$4,680,536
|
$1,096,099
|
$100,000
|
$5,876,635
|
|
(1)
|
Other property consists primarily of four, used steam generators
and related equipment that will be assigned to future projects. As
of October 31, 2019 and April 30, 2019, management concluded that
impairment was not necessary as all other assets were carried at
salvage value.
|
Kern and Kay County Projects. On February 14, 2018, the
Company entered into a Purchase and Exchange Agreement with Red
Fork Resources (“Red
Fork”), pursuant to which (i) the Company agreed to
convey to Mountain View Resources, LLC, an affiliate of Red Fork,
100% of its 13.7% working interest in and to an area of mutual
interest (“AMI”) in the Mountain View
Project in Kern County, California, and (ii) Red Fork agreed to
convey to the Company 64.7% of its 85% working interest in and to
an AMI situated in Kay County, Oklahoma (the “Red Fork Exchange”). The fair value of the
assets acquired was $108,333 as of the effective date of the
agreement. Following the Red Fork Exchange, the Company and Red
Fork each retained a 2% overriding royalty interest in the projects
that they respectively conveyed. Under the terms of the Purchase
and Exchange Agreement, all revenue and costs, expense, obligations
and liabilities earned or incurred prior to January 1, 2018 (the
“Effective
Date”) shall be borne by the original owners of such
working interests, and all of such revenue and costs, expense,
obligations and liabilities that occur subsequent to the effective
date shall be borne by the new owners of such working
interests.
The
acquisition of the additional concessions in Kay County, Oklahoma
added additional prospect locations adjacent to the Company’s
106,000-acre concession in Osage County, Oklahoma. The similarity
of the prospects in Kay and Kern County allows for the leverage of
assets, infrastructure and technical expertise.
Oklahoma Properties. During the six months ended October 31,
2019, the Company recorded additions related to development costs
incurred of approximately $139,500 for proven oil and gas
assets.
Texas Properties. Effective on September 24, 2018, the
Company acquired a 66.67% membership interest in LBE Partners from
ICO in exchange for 300,000 restricted shares of the
Company’s common stock. LBE Partners has varying working
interest in multiple oil and gas producing wells located in Texas.
The Company recorded additions of approximately $2,430,000 for oil
and gas assets related to this acquisition.
Impairment of Oil & Gas Properties. As of October 31, 2019,
the Company assessed its oil and gas assets for impairment and
recognized a charge of $0 related to its oil and
gas properties. As of October 31, 2018, the Company assessed its
oil and gas assets for impairment and recognized a charge of
$0 related to its Oklahoma
and Larne Basin oil and gas properties.
|
7.
|
Asset Retirement Obligations
|
The
total future asset retirement obligations were estimated based on
the Company’s ownership interest in all wells and facilities,
the estimated legal obligations required to retire, dismantle,
abandon and reclaim the wells and facilities and the estimated
timing of such payments. The Company estimated the present value of
its asset retirement obligations at both October 31, 2019 and April
30, 2019 based on a future undiscounted liability of $1,078,469 and
$1,118,249, respectively. These costs are expected to be incurred
within 1 to 42 years. A credit-adjusted risk-free discount rate of
10% and an inflation rate range of 1.5% to 2.66% were used to
calculate the present value.
Changes
to the asset retirement obligations were as follows:
|
|
Six
Months Ended
October 31,
2019
|
Six
Months Ended
October 31,
2018
|
|
Balance, beginning
of period
|
$1,049,191
|
$660,139
|
|
Additions
|
-
|
359,950
|
|
Change in
estimates
|
(39,068)
|
16,213
|
|
Accretion
|
2,662
|
11,107
|
|
|
1,012,785
|
1,047,409
|
|
Less:
Current portion for cash flows expected to be incurred within one
year
|
(719,940)
|
(719,393)
|
|
Long-term
portion, end of period
|
$292,845
|
$328,016
|
Expected
timing of asset retirement obligations:
|
Year Ending April
30,
|
|
|
2020
|
$719,940
|
|
2021
|
-
|
|
2022
|
-
|
|
2023
|
-
|
|
2024
|
-
|
|
Thereafter
|
358,529
|
|
Subtotal
|
1,078,469
|
|
Effect of
discount
|
(65,684)
|
|
Total
|
$1,012,785
|
|
8.
|
Related Party Transactions
|
Acquisition of Membership Interest in LBE Partners
On October 2, 2018, the Company, ICO and LBE Partners entered into
the LBE Assignment Agreement and the LBE Purchase Agreement,
pursuant to which, effective September 24, 2018, the Company
purchased a 66.67% membership interest in LBE Partners from ICO in
exchange for 300,000 restricted shares of the Company’s
common stock to ICO. Both ICO and LBE Partners are managed by Mr.
Cohen. For more information regarding this transaction,
see Note 5.
Series A Financing
On
January 31, 2019, the Company consummated the Series A Financing
(“Series A
Financing”), pursuant to which the Company sold and
issued an aggregate of 178,101 Units, for an aggregate purchase
price of $3,562,015, to certain accredited investors pursuant to a
Securities Purchase Agreement (“SPA”) and to certain
debtholders pursuant to debt conversion agreements, (the
“Debt Holder
Agreement”) resulting in net cash proceeds to the
Company of approximately $2.7 million and the termination of the
Cohen Loan Agreement and debt owed to Fortis Oil & Gas. In
addition, on January 31, 2019, the Company entered into the Secured
Debt Conversion Agreements, pursuant to which Petro Exploration
Funding, LLC and Petro Exploration Funding II, LLC converted all
outstanding senior secured debt (including interest and unpaid
interest), amounting to an aggregate of approximately $5.1 million,
into shares, par value $0.00001 per share (“Series A Preferred
Stock”).
In June
and November 2017, the Company consummated Secured Note financings
for an aggregate of $4.5 million, which Secured Notes accrued
interest at a rate of 10% per annum and were scheduled to mature on
June 13, 2020. On May 17, 2018, the parties executed an extension
of the due date of the first interest payment due pursuant to each
of the Secured Notes from June 1, 2018 to December 31, 2018.
As consideration for the interest payment extension, the Company
agreed to pay the holders an additional 10% of the interest due on
June 1, 2018 on December 31, 2018. On December 17, 2018, the
parties executed a second extension of the due date of the first
interest payment due pursuant to each of the Secured Notes from
December 31, 2018 to March 31, 2019. As a result of the Series A
Financing discussed above, the outstanding balances of the Secured
Notes were converted into shares of Series A Preferred
Stock.
Related Party Loan
On June
18, 2018, the Company entered into a Loan Agreement with Scot Cohen
(the “Cohen Loan
Agreement”), the Company’s Executive Chairman,
pursuant to which Mr. Cohen loaned the Company $300,000 at a 10%
annual interest rate due September 30, 2018. On December 17, 2018,
the maturity date of the Cohen Loan Agreement was extended to March
31, 2019. The Cohen Loan Agreement was terminated on January 31,
2019 in exchange for the issuance of units, consisting of 15,000
shares of Series A Preferred and warrants to purchase 750,000
shares of the Company’s common stock sold and issued in the
Series A Financing.
|
9.
|
Derivative Liabilities
|
As
noted above in Note 8, on January 31, 2019, the Company sold and
issued an aggregate of 178,101 units, for an aggregate purchase
price of $3,562,015, to certain accredited investors and to certain
debtholders. The units sold and issued in the Series A Financing
included five-year warrants to purchase 8,905,037 shares of the
Company’s common stock, at an exercise price of $0.50 per
share.
The
Company identified certain features embedded in the warrants
requiring the Company to classify the warrants as a derivative
liability; specifically, the warrants contain a fundamental
transaction provision that permits their settlement in cash at fair
value of the remaining unexercised portion of this warrant at the
option of the holder upon the occurrence of a change in
control.
The
fair value of the derivative feature of the warrants on the date of
issuance and balance sheet date were calculated using a binomial
lattice model valued with the following weighted-average
assumptions:
|
|
|
|
|
Exercise
price
|
$1.50
|
$1.30 - 1.50
|
|
Risk-free interest
rate
|
1.69 – 2.02%
|
2.08 – 2.96%
|
|
Expected life of
grants
|
|
|
|
Expected volatility
of underlying stock
|
149.64 –
151.62%
|
155.97 –
158.73%
|
|
Dividends
|
0%
|
0%
|
As of
October 31, 2019 and April 30, 2019, the derivative liability of
the warrants was $1,283,600 and $4,191,754, respectively. During
the six months ended October 31, 2019, the Company also recorded
$2,908,154 as the change in the value of the derivative
liabilities.
During
the six months ended October 31, 2019, two holders of Preferred
Series A converted 5,000 Preferred A shares to 250,000 shares of
common stock.
During
the six months ended October 31, 2019, the Company recorded $27,084
in stock-based compensation for vesting amortization of restricted
shares granted to employees and consultants in the prior year.
Stock Options
During the six months ended October 31, 2019 and 2018, the Company
computed the fair value of stock options utilizing a Black-Scholes
option-pricing model using the following assumptions:
|
|
|
|
|
Risk-free interest
rate
|
1.69 – 2.02%
|
1.30 – 1.50%
|
|
Expected life of
grants
|
|
|
|
Expected volatility
of underlying stock
|
149.64 –
151.40%
|
155.97 –
158.73%
|
|
Dividends
|
0%
|
0%
|
The
expected stock price volatility for the Company’s stock
options was estimated using the historical volatilities of the
Company’s common stock. Risk free interest rates were
obtained from U.S. Treasury rates for the applicable
periods.
The
following table summarizes the option activity for the period from
April 30, 2019 to October 31, 2019, and options outstanding and
exercisable at October 31, 2019:
|
|
|
Weighted
Average
Exercise
Prices
|
|
|
|
|
|
Outstanding
– April 30, 2019
|
2,607,385
|
$2.13
|
|
Granted
|
-
|
-
|
|
Exercised
|
-
|
-
|
|
Forfeited/Cancelled
|
(26,500)
|
-
|
|
Outstanding
– October 31, 2019
|
2,580,885
|
$2.10
|
|
Exercisable
– October 31, 2019
|
2,568,885
|
$2.10
|
The
following table summarizes information about the options
outstanding and exercisable at October 31, 2019:
|
|
|
|
|
|
|
|
|
Weighted Avg. Life
Remaining
(years)
|
|
Weighted Average Exercise Price
|
|
|
$1.38
|
1,791,458
|
6.83
|
1,791,458
|
$0.96
|
|
|
$1.40
|
25,703
|
8.14
|
25,703
|
$0.01
|
|
|
$1.50
|
40,000
|
8.75
|
28,000
|
$0.01
|
|
|
$1.98
|
5,000
|
6.76
|
5,000
|
$0.00
|
|
|
$2.00
|
457,402
|
5.66
|
457,402
|
$0.35
|
|
|
$2.87
|
65,334
|
5.30
|
65,334
|
$0.07
|
|
|
$3.00
|
51,001
|
6.16
|
51,001
|
$0.06
|
|
|
$3.39
|
12,000
|
6.39
|
12,000
|
$0.02
|
|
|
$6.00
|
10,000
|
5.23
|
10,000
|
$0.02
|
|
|
$12.00
|
122,987
|
4.01
|
122,987
|
$0.62
|
|
|
|
2,580,885
|
|
2,568,885
|
|
|
Aggregate Intrinsic
Value
|
$-
|
|
$-
|
|
|
During
the six months ended October 31, 2019 and 2018, the Company
expensed an aggregate $1,900 and $199,400 to general and
administrative expenses for stock-based compensation pursuant to
employment and consulting agreements.
As of
October 31, 2019, the Company has $37,617 in unrecognized
stock-based compensation expense which will be amortized over a
weighted average exercise period of 6.48 years.
Warrants
As
discussed above, on January 31, 2019, the Company sold and issued
an aggregate of 178,101 units to certain accredited investors and
to certain debtholders. The units sold and issued in the Offering
included five-year warrants to purchase 8,905,037 shares of the
Company’s common stock, at an exercise price of $0.50 per
share. The relative fair value of the warrants were estimated to be
$4,209,148 using the binomial lattice model.
In
connection with the issuance of the Secured Note financings in June
and November 2017 (as discussed in Note 8), the Company issued
warrants to purchase 2.1 million shares of the Company’s
common stock (the “Secured
Note Warrants”). Upon issuance of the Secured Notes,
the Company valued the Secured Note Warrants using the
Black-Scholes Option Pricing model and accounted for it using the
relative fair value of $2,003,227 as debt discount on the
consolidated balance sheet.
The
following table summarizes the warrant activity for the six months
ended October 31, 2019:
|
|
|
Weighted Average
Exercise
Price
|
Weighted Average Life Remaining
|
|
Outstanding
and exercisable – April 30, 2019
|
11,128,706
|
$1.09
|
4.71
|
|
Forfeited
|
-
|
-
|
-
|
|
Granted/Expired
|
-
|
-
|
-
|
|
Outstanding
and exercisable – October 31, 2019
|
11,128,706
|
$1.09
|
4.21
|
The
aggregate intrinsic value of the outstanding warrants was
$0.
The
following tables provide a reconciliation of the numerator and
denominator used in computing basic and diluted net income (loss)
attributable to common stockholders per common share.
|
|
For
the Three Months Ended
|
|
|
|
|
|
Numerator:
|
|
|
|
Net income (loss)
attributable to common stockholders
|
$761,509
|
$(569,259)
|
|
Effect of dilutive
securities:
|
-
|
-
|
|
|
|
|
|
Diluted net income
(loss)
|
$761,509
|
$(569,259)
|
|
|
|
|
|
Denominator:
|
|
|
|
Weighted average
common Stock outstanding - basic
|
18,067,616
|
17,712,126
|
|
Dilutive securities
(a):
|
|
|
|
Series A
Preferred
|
-
|
-
|
|
Options
|
-
|
-
|
|
Warrants
|
-
|
-
|
|
|
|
|
|
Weighted average
common stock outstanding and assumed conversion –
diluted
|
18,067,616
|
17,712,126
|
|
|
|
|
|
Basic net income
(loss) per common share
|
$0.04
|
$(0.03)
|
|
|
|
|
|
Diluted net income
(loss) per common share
|
$0.04
|
$(0.03)
|
|
|
|
|
|
(a) - Anti-dilutive
securities excluded:
|
35,229,744
|
4,651,257
|
|
|
|
|
|
|
|
|
Numerator:
|
|
|
|
Net income (loss)
attributable to common stockholders
|
$2,316,476
|
$(989,490)
|
|
Effect of dilutive
securities:
|
-
|
-
|
|
|
|
|
|
Diluted net income
(loss)
|
$2,316,476
|
$(989,490)
|
|
|
|
|
|
Denominator:
|
|
|
|
Weighted average
common Stock outstanding - basic
|
18,003,078
|
17,607,863
|
|
Dilutive securities
(a):
|
|
|
|
Series A
Preferred
|
-
|
-
|
|
Options
|
-
|
-
|
|
Warrants
|
-
|
-
|
|
|
|
|
|
Weighted average
common stock outstanding and assumed conversion –
diluted
|
18,003, 078
|
17,607,863
|
|
|
|
|
|
Basic net income
(loss) per common share
|
$0.13
|
$(0.06)
|
|
|
|
|
|
Diluted net income
(loss) per common share
|
$0.13
|
$(0.06)
|
|
|
|
|
|
(a) - Anti-dilutive
securities excluded:
|
35,229,744
|
4,651,257
|
For the
three and six months ended October 31, 2019 and 2018, potentially
dilutive securities were not included in the calculation of diluted
net loss per share because to do so would be anti-dilutive. The
Company had the following common stock equivalents at October 31,
2019 and 2018 were excluded from the computation of diluted net
income (loss) per share as the inclusion of such shares would be
anti-dilutive:
|
|
For
the Three and Six Months Ended
|
|
|
|
|
|
Series A Preferred
Stock
|
21,520,153
|
-
|
|
Stock
options
|
2,580,885
|
2,607,385
|
|
Stock purchase
warrants
|
11,128,706
|
2,223,669
|
|
Total
|
35,229,744
|
4,831,054
|
|
11.
|
Revenue from Contracts with Customers
|
Disaggregation of Revenue from Contracts with Customers. The
following tables disaggregate revenue by significant product type
for the three and six months ended October 31, 2019 and
2018:
|
|
For the Three Months Ended
|
|
|
|
|
|
Oil
sales
|
$259,847
|
$397,090
|
|
Natural gas
sales
|
5,884
|
13,342
|
|
Royalty
revenue
|
5,161
|
-
|
|
Total revenue from
customers
|
$270,892
|
$410,432
|
|
|
|
|
|
|
|
|
Oil
sales
|
$571,796
|
$969,791
|
|
Natural gas
sales
|
13,156
|
14,706
|
|
Royalty
revenue
|
8,399
|
-
|
|
Total revenue from
customers
|
$593,351
|
$984,497
|
There
were no significant contract liabilities or transaction price
allocations to any remaining performance obligations as of October
31, 2019.
|
12.
|
Contingency and Contractual Obligations
|
Office Lease
Change in Accounting Policy. The Company adopted ASU No.
2016-02, “Leases (Topic
842)” and ASU No. 2018-11, “Leases (Topic 842): Targeted
Improvements”, on May 1, 2019, using the alternative
modified transition method, for which, comparative periods,
including the disclosures related to those periods, are not
restated as of May 1, 2019. Refer to Note 4 – Significant
Accounting Policies above for additional information.
In May
2019, the Company entered into a lease agreement for office space
located at 55 5th Avenue, Suite 1702, New York, NY 10003. The lease
is for a term of one year and set to expire on May 31, 2020 and has
fixed annual rent of $119,151. Upon execution of the lease, the
Company paid a security deposit of $19,859. On the effective date
of the new lease, the Company applied the new lease Topic 842 and
does not expect the lease to have a significant impact on its
consolidated balance sheet or statements of operations or cash
flows.
For the
six months ended October 31, 2019 and 2018, the Company incurred
lease expense of $21,603 and $48,512, respectively, for the
combined leases.
Ongoing and Pending Litigation
(a) In January 2010, the Company experienced a flood in its Calgary
office premises as a result of a broken water pipe. There was
significant damage to the premises, rendering them unusable until
the landlord had completed remediation. Pursuant to the lease
contract, the Company asserted that rent should be abated during
the remediation process and accordingly, the Company did not pay
any rent after December 2009. During the remediation process, the
Company engaged an independent environmental testing company to
test for air quality and for the existence of other potentially
hazardous conditions. The testing revealed the existence of
potentially hazardous mold and the consultant provided specific
written instructions for the effective remediation of the premises.
During the remediation process, the landlord did not follow the
consultant’s instructions and correct the potentially
hazardous mold situation, and subsequently in June 2010 gave notice
and declared the premises to be ready for occupancy. The Company
re-engaged the consultant to re-test the premises and the testing
results again revealed the presence of potentially hazardous mold.
The Company determined that the premises were not fit for
re-occupancy and considered the landlord to be in default of the
lease. The Landlord subsequently terminated the lease.
On January 30, 2014, the landlord filed a Statement of Claim
against the Company for rental arrears in the amount aggregating
CAD $759,000 (approximately USD $578,400 as of October 31, 2019).
The Company filed a defense and on October 20, 2014, it filed a
summary judgment application stating that the landlord’s
claim is barred, as it was commenced outside the 2-year statute of
limitation period under the Alberta Limitations Act. The landlord
subsequently filed a cross-application to amend its Statement of
Claim to add a claim for loss of prospective rent in an amount of
CAD $665,000 (approximately USD $506,800 as of October 31, 2019).
The applications were heard on June 25, 2015 and the court
allowed both the Company’s summary judgment application and
the landlord’s amendment application. Both of these orders
were appealed though two levels of the Alberta courts and the
appeals were dismissed at both levels. The net effect is that the
landlord's claim for loss of prospective rent is to proceed.
On October
4, 2018, the Company and the landlord entered into a settlement
agreement under which all actions by the landlord and the Company
were dismissed for a payment by the Company to the landlord of
68,807 shares of common stock.
(b) In September 2013, the Company was notified by the Railroad
Commission of Texas (the “Railroad
Commission”) that the
Company was not in compliance with regulations promulgated by the
Railroad Commission. The Company was therefore deemed to have lost
its corporate privileges within the State of Texas and as a result,
all wells within the state would have to be plugged. The Railroad
Commission therefore collected $25,000 from the Company, which was
originally deposited with the Railroad Commission, to cover a
portion of the estimated costs of $88,960 to plug the wells. In
addition to the above, the Railroad Commission also reserved its
right to separately seek any remedies against the Company resulting
from its noncompliance.
(c) On August 11, 2014, Martha Donelson and John Friend amended
their complaint in an existing lawsuit by filing a class action
complaint styled: Martha Donelson and John
Friend, et al. v. United States of America, Department of the
Interior, Bureau of Indian Affairs and Devon Energy Production, LP,
et al., Case No.
14-CV-316-JHP-TLW, United States District Court for the Northern
District of Oklahoma (the “Proceeding”). The plaintiffs added as defendants
twenty-seven (27) specifically named operators, including
Spyglass, as well as all Osage County lessees and operators
who have obtained a concession agreement, lease or drilling permit
approved by the Bureau of Indian Affairs
(“BIA”) in
Osage County allegedly in violation of National Environmental
Policy Act (“NEPA”). Plaintiffs seek a declaratory
judgment that the BIA improperly approved oil and gas leases,
concession agreements and drilling permits prior to August 12,
2014, without satisfying the BIA’s obligations under federal
regulations or NEPA, and seek a determination that such oil and gas
leases, concession agreements and drilling permits are
void ab initio. Plaintiffs are seeking damages against the
defendants for alleged nuisance, trespass, negligence and unjust
enrichment. The potential consequences of such complaint could
jeopardize the corresponding
leases.
On October 7, 2014, Spyglass, along with other defendants, filed a
Motion to Dismiss the August 11, 2014 Amended Complaint on various
procedural and legal grounds. Following the significant briefing,
the Court, on March 31, 2016, granted the Motion to Dismiss as to
all defendants and entered a judgment in favor of the defendants
against the plaintiffs. On April 14, 2016, Spyglass with the other
defendants, filed a Motion seeking its attorneys’ fees and
costs. The motion remains pending. On April 28, 2016, the
Plaintiffs filed three motions: a Motion to Amend or Alter the
Judgment; a Motion to Amend the Complaint; and a Motion to Vacate
Order. On November 23, 2016, the Court denied all three of
Plaintiffs’ motions. On December 6, 2016, the Plaintiffs
filed a Notice of Appeal to the Tenth Circuit Court of
Appeals. That appeal is pending
as of the filing date of these financial statements. There is
no specific timeline by which the Court of Appeals must render a
ruling. Spyglass intends to continue to vigorously defend its
interest in this matter.
The
Company is from time to time involved in legal proceedings in the
ordinary course of business. It does not believe that any of these
claims and proceedings against it is likely to have, individually
or in the aggregate, a material adverse effect on its financial
condition or results of operations.
On November 6, 2019, the Company, LBE Partners, LLC ("LBE"), ICO
Liquidating Trust, LLC ("ICO") and MJR Holdings, Inc.
("MJR") reached a settlement agreement relating to
ICO sale of LBE membership interest to the Company. In
connection, with the Settlement, the Company issued 10,409 shares
of common stock and a cash payment of $7,748 to
MJR.