N
otes to the Consolidated Financial
Statements
(Unaudited)
Petro River Oil Corp. (the “
Company
”) is an independent energy company focused
on the exploration and 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
entering highly prospective plays with Horizon Energy and other
industry-leading partners. Diversification over a number of
projects, each with low initial capital expenditures and strong
risk reward characteristics, reduces risk and provides
cross-functional exposure to a number of attractive risk adjusted
opportunities.
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
”), the
Company has additional exposure to a portfolio of domestic and
international oil and gas assets consisting of highly prospective
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 the 87,754-acre concession in Osage County, Oklahoma. The
remaining 25% working interest is held by the operator, Performance
Energy, LLC.
The execution of the Company’s business plan is dependent on
obtaining necessary working capital. While no assurances can
be given, in the event management is able to obtain additional
working capital, the Company plans to continue drilling additional
wells on its existing concessions, and to acquire additional
high-quality oil and gas properties, primarily proved producing,
and proved undeveloped reserves. The Company also intends to
explore low-risk development drilling and work-over
opportunities. Management is also exploring farm-in and joint
venture opportunities for the Company’s oil and gas
assets.
Recent Developments
Recent Oil Discoveries
.
On July 24, 2018, the Company announced the successful drilling of
the Arsaga 25-2 exploration well, located on its concession in
Osage County, Oklahoma.
On May 22, 2018, the Company announced the discovery of a new oil
field, the N. Blackland Field, in its concession in Osage County,
Oklahoma, upon successfully testing of the 2-34 exploration
well.
In May 2017, Bandolier discovered two new oil fields with the
successful drilling of the W. Blackland 1-3 and S. Blackland 2-11
exploration wells. On December 15, 2017, the Company received
permits from the Bureau of Indian Affairs to drill eight additional
wells in the W. Blackland Field, which were successfully completed
in April 2018. The Company has received additional permits, and is
currently in the process of drilling an additional two wells. The
Company’s W. Blackland concessions are currently producing,
and, with the drilling of additional wells, the Company anticipates
substantially increasing revenue throughout the remainder of the
current fiscal year.
In addition to the Company’s current development plans,
within its current 3-D seismic data, additional structures in Osage
County have been identified. The Company plans to drill 13
additional wells in calendar year 2018: nine in the N. Blackland
Field, three in the Arsaga structure and one in the Section 13
structure. The Company anticipates drilling these wells out of
cash flows from current production of its existing
wells.
Cohen Loan Agreement
On June 18, 2018, Bandolier entered into a loan agreement with Scot
Cohen, the Executive Chairman of the Company (the
“
Cohen Loan
Agreement
”), pursuant to
which Scot Cohen loaned the Company $300,000 at a 10% annual
interest rate, due on September 30, 2018. The Cohen Loan Agreement
was to provide the Company with short-term financing in connection
with the Company’s drilling program in Osage County,
Oklahoma.
2.
Going Concern and Management’s Plan
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. As of July 31, 2018, the Company
had an accumulated deficit of $51.5 million. The Company has
incurred significant losses since its inception. 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.
At
July 31, 2018, the Company had working deficit of approximately
$1.9 million. 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. In
addition, the Company has a limited operating history prior to
its acquisition of Bandolier. At July 31, 2018, the Company
had cash and cash equivalents of approximately $5,000. The
Company’s primary source of operating funds since inception
has been debt and equity financings.
Management is focusing on specific target acquisitions and
investments, limiting operating expenses, and exploring farm-in and
joint venture opportunities for the Company’s oil and gas
assets. No assurances can be given that management will be
successful. In addition, Management intends to 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 efforts. In order to conserve capital, from time to time,
management may defer certain development
activity.
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:
Petro Spring, LLC; PO1, LLC; Petro River UK Limited; 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.
Also contained in the unaudited consolidated financial statements
for the periods ending July 31, 2017 and April 30, 2018 is the
financial information of MegaWest, which, prior to January 31,
2018, was 58.51% owned by the Company. The unaudited consolidated
financial statements for the three months ended July 31, 2017
include the results of operations of MegaWest; however, the assets
and liabilities were written off in the year ended April 30,
2018.
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 Form
10-K for the year ended April 30, 2018, filed with the Securities
and Exchange Commission (the “
SEC
”) on July 30, 2018. 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 Form 10-K for the year ended April 30, 2018, 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, 2019.
4.
Significant Accounting Policies
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 revenues and
expenses 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. While management believe
that its estimates and assumptions used in preparation of the
financial statements are appropriate, actual results could differ
from those estimates.
(b)
|
Cash
and Cash Equivalents:
|
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.
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 individually each
receivable 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 July 31, 2018 and April 30,
2018 was $0.
(d)
|
Oil
and Gas Operations:
|
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.
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 proven 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 three months ended July 31, 2018 and
2017.
(e)
|
Fair
Value of Financial Instruments:
|
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 which 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.
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 January 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. While the Company
does not expect 2018 net earnings to be materially impacted by
revenue recognition timing changes, Topic 606 requires certain
changes to the presentation of revenues and related expenses
beginning May 1, 2018. Refer to Note 9 – Revenue from
Contracts with Customers for additional
information.
The
Company’s revenue is comprised entirely of revenue from
exploration and production activities. The Company’s oil is
sold primarily to marketers, gatherers, and refiners. Natural gas
is sold primarily to interstate and intrastate natural-gas
pipelines, direct end-users, industrial users, local distribution
companies, and natural-gas marketers. NGLs are sold primarily to
direct end-users, refiners, and marketers. Payment is generally
received from the customer in the month following
delivery.
Contracts
with customers have varying terms, including spot sales or
month-to-month contracts, contracts with a finite term, and
life-of-field contracts where all production from a well or group
of wells is sold to one or more customers. The Company recognizes
sales revenues for oil, natural gas, and NGLs based on the amount
of each product sold to a customer when control transfers to the
customer. Generally, control transfers at the time of delivery to
the customer at a pipeline interconnect, the tailgate of a
processing facility, or as a tanker lifting is completed. Revenue
is measured based on the contract price, which may be index-based
or fixed, and may include adjustments for market differentials and
downstream costs incurred by the customer, including gathering,
transportation, and fuel costs.
Revenues
are recognized for the sale of the Company’s net share of
production volumes. Sales on behalf of other working interest
owners and royalty interest owners are not recognized as
revenues.
(g)
|
Stock-Based
Compensation:
|
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 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 expenses resulting from stock-based compensation are recorded
as general and administrative expenses in the consolidated
statement of operations, depending on the nature of the services
provided.
Income Tax Provision
On
December 22, 2017, the Tax Cuts and Jobs Act
(“
Tax Act
”) was
signed into law. ASC 740,
Accounting for Income Taxes,
requires
companies to recognize the effects of changes in tax laws and rates
on deferred tax assets and liabilities and the retroactive effects
of changes in tax laws in the period in which the new legislation
is enacted. The Company’s gross deferred tax assets were
revalued based on the reduction in the federal statutory tax rate
from 35% to 21%. A corresponding offset has been made to the
valuation allowance, and any potential other taxes arising due to
the Tax Act will result in reductions to the Company’s net
operating loss carryforward and valuation allowance. The Company
will continue to analyze the Tax Act to assess its full effects on
the Company’s financial results, including disclosures, for
the Company’s fiscal year ending April 30, 2019, but the
Company does not expect the Tax Act to have a material impact on
the Company’s consolidated financial statements.
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.
Interpretation of taxation rules relating to net operating loss
utilization in real estate transactions give rise to uncertain
positions. In connection with the uncertain tax position, there
were no interest or penalties recorded as the position is expected
but the tax returns are not yet due.
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).
Basic net income (loss) per common share is computed by dividing
net loss attributable to stockholders by the weighted-average
number of shares of common stock outstanding during the period.
Diluted net income (loss) per common share is determined using the
weighted-average number of common shares outstanding during the
period, adjusted for the dilutive effect of common stock
equivalents. For the three months ended July 31, 2018 and
2017, 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 July 31,
2018 and 2017:
|
|
|
Stock
Options
|
2,607,385
|
2,574,682
|
Stock
Purchase Warrants
|
2,223,669
|
973,669
|
Total
|
4,831,054
|
3,548,351
|
(j)
|
Recent
Accounting Pronouncements:
|
In February 2016
,
the
FASB issued ASU 2016-02,
Leases
,
which aims to make leasing activities more transparent and
comparable and requires substantially all leases be recognized by
lessees on their balance sheet as a right-of-use asset and
corresponding lease liability, including leases currently accounted
for as operating leases. This ASU is effective for all interim and
annual reporting periods beginning after December 15,
2019, with early adoption permitted. The Company expects to
adopt ASU 2016-02 beginning May 1,
2019
and
is in the process of assessing the impact that this new guidance is
expected to have on the Company’s financial statements and
related disclosures.
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 a 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.
The Company does not expect the adoption of any other 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.
The following table summarizes the activity of the oil and gas
assets by project for the three months ended July 31,
2018:
|
|
|
|
Balance
May 1, 2018
|
$
3,779,414
|
$
100,000
|
$
3,879,414
|
Additions
|
459,634
|
-
|
459,634
|
Depreciation,
depletion and amortization
|
(86,934
)
|
-
|
(86,934
)
|
Balance
July 31, 2018
|
$
4,152,114
|
$
100,000
|
$
4,252,114
|
(1)
|
Other property consists primarily of four used steam generators and
related equipment that will be assigned to future projects. As of
July 31, 2018, and April 30, 2018, 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 Agreement, all revenues and costs, expenses,
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 costs, expenses, 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 three
months ended July 31, 2018, the Company recorded additions related
to development costs incurred of approximately $460,000 for proven
oil and gas assets.
6.
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 July 31, 2018 and April
30, 2018 based on a future undiscounted liability of $740,452 and
$728,091, respectively. These costs are expected to be incurred
within 1 to 24 years. A credit-adjusted risk-free discount rate of
10% and an inflation rate of 2% were used to calculate the present
value.
Changes to the asset retirement obligations were as
follows:
|
Three Months Ended
July 31,
2018
|
Three Months Ended
July 31,
2017
|
Balance,
beginning of period
|
$
660,139
|
$
558,696
|
Additions
|
4,150
|
7,500
|
Change
in estimate
|
(1,088
)
|
-
|
Disposals
|
-
|
-
|
Accretion
|
3,423
|
2,971
|
|
666,624
|
569,167
|
Less:
Current portion for cash flows expected to be incurred within one
year
|
(406,403
)
|
(406,403
)
|
Long-term
portion, end of period
|
$
260,221
|
$
162,764
|
During
the three months ended July 31, 2018 and 2017, the Company recorded
accretion expense of $3,423 and $2,971,
respectively.
Expected timing of asset retirement obligations:
Year Ending April
30,
|
|
2019
|
$
406,403
|
2020
|
-
|
2021
|
-
|
2022
|
-
|
2023
|
-
|
Thereafter
|
334,049
|
Subtotal
|
740,452
|
Effect of
discount
|
(73,828
)
|
Total
|
$
666,624
|
7.
Related Party Transactions
Related Party Loan
On June 18, 2018, Bandolier entered into a loan agreement with Scot
Cohen, the Executive Chairman of the Company, pursuant to which Mr.
Cohen loaned the Company $300,000 at a 10% annual interest rate,
due on September 30, 2018. The Cohen Loan Agreement was to provide
the Company with short-term financing in connection with the
Company’s drilling program in Osage County, Oklahoma. As
of July 31, 2018, the accrued interest was
$3,583.
June 2017 $2.0 Million Secured Note Financing
Scot Cohen owns or controls 31.25% of Funding Corp. I, the holder
of the senior secured promissory note in the principal amount of
$2.0 million (the “
June 2017 Secured
Note
”) issued by the
Company on June 13, 2017. The June 2017 Secured Note accrues
interest at a rate of 10% per annum and matures on June 30, 2020.
The June 2017 Secured Note is presented as “Note payable
– related party, net of debt discount” on the
consolidated balance sheets.
On May 17, 2018, the parties executed an extension of the due date
of the first interest payment from June 1, 2018 to December
31, 2018. As consideration for the interest payment extension, the
Company agreed to pay Funding Corp. I an additional 10% of the
interest due on June 1, 2018 on December 31, 2018. The Company
accrued an additional $19,160 of interest expenses related to this
extension.
In connection with the issuance of the
June 2017 Secured Note, the Company issued to Funding Corp. I
warrants to purchase 840,336 shares of the Company’s common
stock (the “
June 2017
Warrant
”). Upon issuance
of the June 2017 Secured Note, the Company valued the June 2017
Warrant using the Black-Scholes Option Pricing model and accounted
for it using the relative fair value of $952,056 as debt discount
on the consolidated balance sheet.
As additional consideration for the purchase of the June 2017
Secured Note, the Company issued to Funding Corp. I an overriding
royalty interest equal to 2% in all production from the
Company’s interest in the Company’s concessions located
in Osage County, Oklahoma, originally held by Spyglass, valued at
$250,000, which was recorded as contributed capital and debt
discount on the consolidated balance sheet.
The debt discount is amortized over the earlier of (i) the term of
the debt or (ii) conversion of the debt, using the effective
interest method. The amortization of debt discount is included as a
component of interest expense in the consolidated statements of
operations. There was unamortized debt discount of $923,364 as of
July 31, 2018. During the three months ended July 31, 2018 and
2017, the Company recorded amortization of debt discount totaling
$70,824 and $37,378, respectively.
As
of July 31, 2018 and April 30, 2018, the outstanding balance, net
of debt discount, was $1,076,636 and $1,005,811, respectively, and
accrued interest on the June 2017 Secured Note due to related party
was $243,636 and $174,065,
respectively.
November 2017 $2.5 Million Secured Note Financing
Scot Cohen owns or controls 41.20% of Funding Corp. II, the holder
of the November 2017 Secured Note issued by the Company in
connection with the November 2017 Note Financing in the principal
amount of $2.5 million. The November 2017 Secured Note accrues
interest at a rate of 10% per annum and matures on June 30, 2020.
The November 2017 Secured Note is presented as “Note payable
– related party, net of debt discount” on the
consolidated balance sheets.
On May 17, 2018, the parties executed an extension of the due date
of the first interest payment from June 1, 2018 to December
31, 2018. As consideration for the interest payment extension, the
Company agreed to pay Funding Corp. II an additional 10% of the
interest due on June 1, 2018 on December 31, 2018. The Company
accrued an additional $14,247 of interest expenses related to this
extension.
Pursuant
to the financing agreement, the Company issued the November 2017
Warrant to Funding Corp. II to purchase 1.25 million shares of the
Company’s common stock. Upon issuance of the November 2017
Note, the Company valued the November 2017 Warrant using the
Black-Scholes Option Pricing model and accounted for it using the
relative fair value of $1,051,171 as debt discount on the
consolidated balance sheet. In relation to the financing, Scot
Cohen paid $250,000 for an overriding royalty interest from Funding
Corp. I (as discussed below), which was recorded as additional debt
discount on the consolidated balance
sheet.
As additional consideration for the purchase of the November 2017
Secured Note, the Company issued to Funding Corp. II an overriding
royalty interest equal to 2% in all production from the
Company’s interest in the Company’s concessions located
in Osage County, Oklahoma, originally held by Spyglass (the
“
Existing
Osage County
Override
”) then
transferred to Funding Corp. I as inducement for the June 2017
Secured Note. The Existing Osage County Override was then acquired
by the Company from Scot Cohen. As noted above, the override was
accounted for as a debt discount and amortized over the term of the
debt.
The debt discount is amortized over the earlier of (i) the term of
the debt or (ii) conversion of the debt, using the effective
interest method. The amortization of debt discount is included as a
component of interest expense in the consolidated statements of
operations. There was unamortized debt discount of $1,059,687 as of
July 31, 2018. During the three months ended July 31, 2018 and
2017, the Company recorded amortization of debt discount totaling
$85,375 and $0, respectively.
As
of July 31, 2018 and April 30, 2018, the outstanding balance, net
of debt discount, were $1,440,313 and $1,354,938, respectively, and
accrued interest on the November 2017 Secured Note due to related
party were $197,809 and $120,548,
respectively.
As of July 31, 2018 and April 30, 2018, the Company had 5,000,000
shares of preferred stock, par value $0.00001 per share,
authorized. As of July 31, 2018, and April 30, 2018, the Company
had 29,500 shares of Series B Preferred Stock, par value $0.00001
per share (“
Series B
Preferred
”), authorized.
No Series B Preferred shares are currently issued or outstanding,
and no other series of preferred stock has been
designated.
As of July 31, 2018 and April 30, 2018, the Company had 150,000,000
shares of common stock authorized.
In May
2018, the Company granted a total of 260,000 shares of restricted
common stock to Scot Cohen and Steven Brunner in exchange for a
reduction in cash compensation with a fair value of approximately
$325,000, based on the market price of the Company’s common
stock on the grant date. The shares vest monthly in equal
installments over a 12-month period. During the three months ended
July 31, 2018, the Company recorded stock-based compensation of
$54,166 related to these grants.
There were 17,569,733 and
17,309,733
shares of common stock issued and outstanding as
of July 31, 2018 and April 30, 2018,
respectively.
Stock Options
The assumptions used for the options granted during the three
months ended July 31, 2018 were as follows:
|
|
July 31,
2018
|
|
Exercise price
|
|
$
|
1.30 – 1.50
|
|
Expected dividends
|
|
|
0%
|
|
Expected volatility
|
|
|
155.97 – 158.73%
|
|
Risk free interest rate
|
|
|
2.08 – 2.96%
|
|
Expected life of grants
|
|
|
1
–
10 years
|
|
The following table summarizes information about the changes of
options for the period from April 30, 2018 to July 31, 2018,
and options outstanding and exercisable at July 31,
2018:
|
|
Weighted
Average
Exercise
Prices
|
|
|
|
Outstanding April 30, 2018
|
2,555,385
|
$
2.14
|
Granted
|
52,000
|
1.45
|
Exercised
|
-
|
-
|
Forfeited/Cancelled
|
-
|
-
|
Outstanding – July 31, 2018
|
2,607,385
|
$
2.13
|
Exercisable – July 31, 2018
|
2,427,588
|
$
2.17
|
|
|
|
Outstanding – Aggregate Intrinsic Value
|
|
$
220,485
|
Exercisable – Aggregate Intrinsic Value
|
|
$
206,924
|
The following table summarizes information about the options
outstanding and exercisable at July 31, 2018:
|
|
|
|
|
Weighted Avg.
Life
Remaining
(years)
|
|
$
1.30
|
12,000
|
0.50
|
12,000
|
$
1.38
|
1,795,958
|
8.09
|
1,682,947
|
$
1.40
|
25,703
|
9.39
|
25,703
|
$
1.50
|
40,000
|
10.00
|
8,000
|
$
1.98
|
5,000
|
8.01
|
5,000
|
$
2.00
|
457,402
|
6.92
|
431,895
|
$
2.87
|
65,334
|
6.55
|
64,611
|
$
3.00
|
51,001
|
7.41
|
42,445
|
$
3.39
|
12,000
|
7.64
|
12,000
|
$
6.00
|
10,000
|
6.49
|
10,000
|
|
132,987
|
5.27
|
132,987
|
|
2,607,385
|
|
2,427,588
|
During the three months ended July 31, 2018 and 2017, the Company
expensed $191,818 and $529,332, respectively, related to the
vesting of outstanding options to general and administrative
expense for stock-based compensation pursuant to employment and
consulting agreements.
As
of July 31, 2018, the Company has approximately $199,168 in
unrecognized stock-based compensation expense related to unvested
options, which will be amortized over a weighted average exercise
period of approximately three years.
Warrants
The fair values of the 840,336 June 2017 Warrants granted in
conjunction with the June 2017 Note Financing and the 1.25 million
November 2017 Warrants granted in connection with the November 2017
Note Financing (as discussed in Note 7) were estimated on the date
of grant using the Black-Scholes option-pricing model.
The following is a summary of the Company’s warrant
activity:
|
|
Weighted
Average
Exercise Price
|
Weighted
Average Life
Remaining (Years)
|
Outstanding and exercisable – April 30, 2018
|
2,223,669
|
5.02
|
2.57
|
Forfeited
|
-
|
-
|
-
|
Granted
|
-
|
-
|
-
|
Outstanding and exercisable – July 31, 2018
|
2,223,669
|
5.02
|
2.08
|
The aggregate intrinsic value of the outstanding warrants was
$0.
9.
Revenue from Contracts with Customers
Change in Accounting Policy.
The Company adopted ASU 2014-09, “
Revenue from Contracts with Customers (Topic
606)
,” on May 1, 2018, using the modified
retrospective method applied to contracts that were not completed
as of May 1, 2018. Refer to Note 4 –Significant Accounting
Policies for additional information.
Exploration and Production.
There were no significant
changes to the timing or valuation of revenue recognized for sales
of production from exploration and production
activities.
Disaggregation of Revenue from Contracts with Customers.
The
following table disaggregates revenue by significant product type
for the three months ended July 31, 2018:
Oil
sales
|
$
1,364
|
Natural gas
sales
|
572,701
|
Total revenue from
customers
|
$
574,065
|
There
were no significant contract liabilities or transaction price
allocations to any remaining performance obligations as of April
30, 2018 or July 31, 2018.
10.
Contingency and Contractual Obligations
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 $582,000
as of July 31, 2018). 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 $510,000 as of July
31, 2018). 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 Company is in the
process of negotiating a settlement agreement with the
landlord.
(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.
(d) MegaWest Energy Missouri Corp. (“
MegaWest
Missouri
”), a wholly
owned subsidiary of the Company, is involved in two cases related
to oil leases in West Central, Missouri. The first case
(
James Long
and Jodeane Long v. MegaWest Energy Missouri and Petro River Oil
Corp.
, case number
13B4-CV00019)
is a case for unlawful
detainer, pursuant to which the plaintiffs contend that MegaWest
Missouri oil and gas lease has expired and MegaWest Missouri is
unlawfully possessing the plaintiffs’ real property by
asserting that the leases remain in effect. The case was
originally filed in Vernon County, Missouri on September 20,
2013. MegaWest Missouri filed an Answer and Counterclaims on
November 26, 2013 and the plaintiffs filed a motion to dismiss the
counterclaims. MegaWest Missouri filed a motion for Change of Judge
and Change of Venue and the case was transferred to Barton County.
The court granted the motion to dismiss the counterclaims on
February 3, 2014.
As to
the other allegations in the complaint, the matter is still
pending.
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.