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. 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
taking advantage of the relative depressed market in oil prices to
enter 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 and in Kern County, California. Following
the acquisition of Horizon I Investments, LLC
(“
Horizon
Investments
”), the
Company now has exposure to a portfolio of several 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 20% 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, including two assets located in
the United Kingdom, adjacent to the giant Wytch Farm oil field, the
largest onshore oil field in Western Europe. Other
projects include the proposed redevelopment of a large oil field in
Kern County, California and the development of an additional recent
discovery in Kern County. Each of the assets in the
Horizon Energy portfolio is characterized by low initial capital
expenditure requirements and strong risk reward
characteristics.
In light of the challenging oil price environment and capital
markets, 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.
The accompanying unaudited interim consolidated financial
statements are prepared in accordance with 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.
MegaWest Energy Montana Corp.
Also contained in the unaudited consolidated financial statements
is the financial information of the Company’s 58.51% owned
subsidiary, MegaWest Energy Kansas Corporation
(“MegaWest”), which resulted from a transaction with
Fortis Property Group, LLC, a Delaware limited liability company
(“
Fortis
”) consummated on October 15, 2015 (the
“
MegaWest
Transaction
”). The
Megawest Transaction includes the Company’s contribution of
its 50% interest in Bandolier Energy LLC.
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, 2016 filed with the Securities
and Exchange Commission (the “
SEC
”) on July 29, 2016. 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, 2016 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, 2017.
|
3.
|
Significant Accounting Policies
|
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America 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 we believe that our
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.
As of January 31, 2017 and April 30, 2016, restricted cash
consisted of a certificate of deposit in the amount of $0 and
$80,803, respectively, which had an annual interest rate of 0.5%
and maturity date of March 13, 2017.
Pursuant to FASB ASC paragraph 310-10-35-47, receivables that
management has the intent and ability to hold for the foreseeable
future shall be reported in the balance sheet at outstanding
principal adjusted for any charge-offs and the allowance for
doubtful accounts. The Company follows FASB ASC paragraphs
310-10-35-7 through 310-10-35-10 to estimate the allowance for
doubtful accounts. Pursuant to FASB ASC paragraph 310-10-35-9,
losses from uncollectible receivables shall be accrued when both of
the following conditions are met: (a) Information available before
the financial statements are issued or are available to be issued
(as discussed in Section 855-10-25) 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.
Pursuant to FASB ASC paragraph 310-10-35-41, 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 January 31, 2017 and April
30, 2016 was $0.
|
(d)
|
Interest in Real Estate Rights:
|
I
nterest in real estate
rights contributed by Fortis related to real properties that Fortis
plans to sell within one year. Since these properties are
contributed by Fortis, a related party, the rights are stated on
balance sheet at the cost basis of Fortis.
|
(e)
|
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.
The Company accounts for its unproven long-lived assets in
accordance with Accounting Standards Codification
(“
ASC
”) Topic 360-10-05,
“
Accounting for the Impairment
or Disposal of Long-Lived Assets
.” ASC Topic 360-10-05 requires that
long-lived assets be reviewed for impairment whenever events or
changes in circumstances indicate that the historical cost carrying
value of an asset may no longer be appropriate. For the nine months
ended January 31, 2017, the Company evaluated and recorded no
impairment on these properties.
Proved Oil and Gas Reserves
: In
accordance with Rule 4-10 of SEC Regulation S-X, 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
Bandolier transaction. The price used to establish economic
producibility 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. For the nine
months ended January 31, 2017, the Company recorded an impairment
of $20,942 on its proved oil and gas
properties.
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 nine months ended January 31, 2017 and
2016.
|
(f)
|
Investments – Cost Method and Equity Method:
|
Investments held in stock of entities other than subsidiaries,
namely corporate joint ventures and other non-controlled entities
usually are accounted for by one of three methods: (i) the fair
value method (addressed in Topic 320), (ii) the equity method
(addressed in Topic 323), or (iii) the cost method (addressed in
Subtopic 325-20). Pursuant to Paragraph 323-10-05-5, the equity
method tends to be most appropriate if an investment enables the
investor to influence the operating or financial policies of the
investee. The cost basis is utilized for investments that are less
than 20% owned, and the Company does not exercise significant
influence over the operating and financial policies of the
investee. Under the cost method, investments are held at historical
cost.
|
(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 our 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
Deferred income tax assets and liabilities are determined based
upon differences between the financial reporting and tax bases of
assets and liabilities and are measured using the enacted tax rates
and laws that will be in effect when the differences are expected
to reverse. Deferred tax assets are reduced by a valuation
allowance to the extent management concludes it is more likely than
not that the assets will not be realized. Deferred tax assets and
liabilities are measured using enacted tax rates expected to apply
to taxable income in the years in which those temporary differences
are expected to be recovered or settled. The effect on deferred tax
assets and liabilities of a change in tax rates is recognized in
the statements of operations in the period that includes the
enactment date.
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.
The estimated future tax effects of temporary differences between
the tax basis of assets and liabilities are reported in the
accompanying consolidated balance sheets, as well as tax credit
carry-backs and carry-forwards. The Company periodically reviews
the recoverability of deferred tax assets recorded on its
consolidated balance sheets and provides valuation allowances as
management deems necessary.
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 did not take any uncertain tax positions and had no
adjustments to its income tax liabilities or benefits for the
reporting periods ended January 31, 2017 and 2016.
Basic net income (loss) per common share is computed by dividing
net loss attributable to common stockholders by the
weighted-average number of common shares 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 and nine months ended January 31,
2017 and 2016, 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 January
31, 2017 and 2016:
|
|
|
|
|
Stock
Options
|
2,495,182
|
710,019
|
|
Stock Purchase
Warrants
|
133,333
|
336,458
|
|
Total
|
2,628,515
|
1,046,477
|
|
(j)
|
Recent Accounting Pronouncements:
|
In May 2014, the FASB issued a comprehensive new revenue
recognition standard that will supersede nearly all existing
revenue recognition guidance under U.S. GAAP. The standard’s
core principle (issued as ASU 2014-09 by the FASB), is that a
company will recognize revenue when it transfers promised goods or
services to customers in an amount that reflects the consideration
to which the company expects to be entitled in exchange for those
goods or services. These may include identifying performance
obligations in the contract, estimating the amount of variable
consideration to include in the transaction price and allocating
the transaction price to each separate performance obligation. The
new guidance must be adopted using either a full retrospective
approach for all periods presented in the period of adoption or a
modified retrospective approach. In August 2015, the FASB issued
ASU No. 2015-14, which defers the effective date of ASU 2014-09 by
one year, and would allow entities the option to early adopt the
new revenue standard as of the original effective date. This ASU is
effective for public reporting companies for interim and annual
periods beginning after December 15, 2017. The Company is currently
evaluating its adoption method and the impact of the standard on
its consolidated financial statements and has not yet determined
the method by which the Company will adopt the standard in
2017.
In April 2016, the FASB issued ASU No. 2016-10,
“
Revenue from Contracts with
Customers: Identifying Performance Obligations and
Licensing
” (topic 606).
In March 2016, the FASB issued ASU No. 2016-08, “Revenue from
Contracts with Customers: Principal versus Agent Considerations
(Reporting Revenue Gross verses Net)” (topic 606). These
amendments provide additional clarification and implementation
guidance on the previously issued ASU 2014-09, “Revenue from
Contracts with Customers”. The amendments in ASU 2016-10
provide clarifying guidance on materiality of performance
obligations; evaluating distinct performance obligations; treatment
of shipping and handling costs; and determining whether an entity's
promise to grant a license provides a customer with either a right
to use an entity's intellectual property or a right to access an
entity's intellectual property. The amendments in ASU 2016-08
clarify how an entity should identify the specified good or service
for the principal versus agent evaluation and how it should apply
the control principle to certain types of arrangements. The
adoption of ASU 2016-10 and ASU 2016-08 is to coincide with an
entity's adoption of ASU 2014-09, which we intend to adopt for
interim and annual reporting periods beginning after December 15,
2017. The Company is currently evaluating the impact of the new
standard.
In April 2016, the FASB issued ASU No. 2016-09,
“
Compensation – Stock
Compensation
” (topic
718). The FASB issued this update to improve the accounting for
employee share-based payments and affect all organizations that
issue share-based payment awards to their employees. Several
aspects of the accounting for share-based payment award
transactions are simplified, including: (a) income tax
consequences; (b) classification of awards as either equity or
liabilities; and (c) classification on the statement of cash flows.
The updated guidance is effective for annual periods beginning
after December 15, 2016, including interim periods within those
fiscal years. Early adoption of the update is permitted. The
Company is currently evaluating the impact of the new
standard.
In
August 2016, the FASB issued ASU 2016-15,
“Statement of Cash Flows (Topic 230):
Classification of Certain Cash Receipts and Cash
Payments”
(“ASU 2016-15”). ASU 2016-15
will make eight targeted changes to how cash receipts and cash
payments are presented and classified in the statement of cash
flows. ASU 2016-15 is effective for fiscal years beginning after
December 15, 2017. The new standard will require adoption on a
retrospective basis unless it is impracticable to apply, in which
case it would be required to apply the amendments prospectively as
of the earliest date practicable. The Company is currently in the
process of evaluating the impact of ASU 2016-15 on its consolidated
financial statements.
In November 2016, the FASB issued
ASU 2016-18,
“Statement of
Cash Flows (Topic 230)”
, requiring that the statement
of cash flows explain the change in the total cash, cash
equivalents, and amounts generally described as restricted cash or
restricted cash equivalents. This guidance is effective for fiscal
years, and interim reporting periods therein, beginning after
December 15, 2017 with early adoption permitted. The provisions of
this guidance are to be applied using a retrospective approach
which requires application of the guidance for all periods
presented. The Company is currently evaluating the impact of the
new standard.
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.
On May 3, 2016 (the “
Closing
Date
”), the Company
consummated the acquisition of Horizon Investments (the
“
Horizon
Acquisition
”). As a result of the
acquisition, the Company acquired: (i) a 20% membership interest in
Horizon Energy; (ii) three promissory notes issued by the Company
to Horizon Investments in the principal amount of $1.6 million (the
“
Horizon
Notes
”); (iii) a
restricted certificate of deposit; and (iv) certain bank,
investment and other accounts maintained by Horizon
Investments. The Horizon Acquisition was completed in
accordance with the term and conditions of the Conditional Purchase
Agreement first entered into by the Company and Horizon Investments
on December 1, 2015 (the “
Purchase
Agreement
”). Also on the
Closing Date, the Company and Horizon Investments entered into an
amended and restated Purchase Agreement, pursuant to which the
Company agreed to provide for additional advances by Horizon
Investments to the Company.
As consideration for the Horizon Acquisition, and in accordance
with the Purchase Agreement, as amended, the Company issued
11,564,250 shares of its common stock on the Closing Date, which
amount included 1,395,916 additional shares of common stock in
consideration for the additional cash, receivables and other assets
reflected on Horizon Investment's balance sheet on the Closing
Date.
The following table summarizes the allocation of the purchase price
to the net assets acquired:
|
Purchase price allocation
|
|
|
Cash
and cash equivalents
|
$
3,364,817
|
|
Cost
method investment – Horizon Energy Partners, LLC
|
688,000
|
|
Notes
receivable – related party
|
1,600,000
|
|
Net assets acquired
|
$
5,652,817
|
|
|
|
|
Consideration for net assets acquired
|
|
|
Fair
value of common stock issued
|
$
5,652,817
|
|
5.
|
Accounts Receivable – Related Party
|
On October 15, 2015, the Company entered into a contribution
agreement (the “
Contribution
Agreement
”) with MegaWest
and Fortis pursuant to which the Company and Fortis each agreed to
contribute certain assets to MegaWest in exchange for shares of
MegaWest common stock (“
MegaWest
Shares
”) (the
“
MegaWest
Transaction
”).
Upon execution of the Contribution Agreement, Fortis transferred
its interest in 30 condominium units and the right to any profits
and proceeds therefrom. For the three months ended January 31, 2017
and 2016, Fortis sold 0 and 6 condominium units, respectively, and
MegaWest recorded a net (loss) gain on interest in real estate
rights of $(7,208) and $2,377,761, respectively. For the nine
months ended January 31, 2017 and 2016, Fortis sold 2 and 24
condominium units, respectively, and MegaWest recorded a net gain
on interest in real estate rights of $686,096 and $10,238,499,
respectively. As of January 31, 2017, the Company had an accounts
receivable – related party in the amount of $2,738,807
related to interest in real estate rights of condominium units
sold.
The account receivable and the Company’s interest in real
estate reflected on the Company’s balance sheet are assets
held by MegaWest, and are controlled by MegaWest’s board of
directors, consisting of two members appointed by Fortis, and one
by the Company. The relative composition of the board of
directors of MegaWest shall continue as long as Fortis has an
equity interest in MegaWest.
|
6.
|
Notes Receivable – Related Party
|
During 2015 and 2016, the Company entered into eight promissory
note agreements with Fortis with aggregate principal amounts of
$21,590,803. The notes receivable bear interest at an annual rate
of 3% and mature on December 31, 2017. As of January 31, 2017 and
April 30, 2016, the outstanding balance of the notes receivable was
$21,590,803 and $17,848,000, respectively.
|
7.
|
Interest in Real Estate Rights
|
As discussed in Note 5, MegaWest received an interest in real
estate rights of 30 condominium units from Fortis pursuant to the
Megawest Transaction. For the nine months ended January 31,
2017, the Company recognized a net gain of $686,096 related to the
sale of two condominium units by Fortis.
The following table summarizes the activity for interest in real
estate rights:
|
|
Nine Months Ended January 31,
2017
|
|
Balance
at April 30, 2016
|
$
2,820,402
|
|
Cost
of sales - two condominium units
|
937,217
|
|
Balance at January 31, 2017
|
$
1,883,185
|
The following table summarizes the activity of the oil and gas
assets by project for the nine months ended January 31,
2017:
|
|
|
|
|
|
|
Balance
May 1, 2016
|
$
778,226
|
$
-
|
$
100,000
|
$
878,226
|
|
Additions
|
304,297
|
761,444
|
-
|
1,065,741
|
|
Disposals
|
-
|
-
|
-
|
-
|
|
Depreciation,
depletion and amortization
|
(3,440
)
|
-
|
-
|
(3,440
)
|
|
Impairment
of oil and gas assets
|
(20,942
)
|
-
|
-
|
(20,942
)
|
|
|
|
|
|
|
|
Balance
January 31, 2017
|
$
1,058,141
|
$
761,444
|
$
100,000
|
$
1,919,585
|
(1) Other property consists primarily of four used steam generators
and related equipment that will be assigned to future projects. As
of January 31, 2017, management concluded that impairment was not
necessary as all other assets were carried at salvage
value.
Kern County Project.
On March 4, 2016, the
Company executed an Asset Purchase and Sale and Exploration
Agreement (the "
Agreement
")
to acquire a 13.75% working interest in certain oil and gas leases
located in southern Kern County, California (the
"
Project
").
Horizon Energy also purchased a 27.5% working interest in the
Project.
Under the terms of the Agreement, the Company paid $108,333 to
the sellers on the closing date, and is obligated to pay certain
other costs and expenses after the closing date related to existing
and new leases as more particularly set forth in the Agreement.
Costs incurred to date for this property have aggregated to
$646,680 as
of January 31, 2017
and are recorded as prepaid oil and gas development costs on the
consolidated balance sheet.
In addition, the
sellers are entitled to an overriding royalty interest in certain
existing and new leases acquired after the closing date, and the
Company is required to make certain other payments, each in amounts
set forth in the Agreement.
Acquisition of Interest in Larne
Basin.
On January
19, 2016, Petro River UK Limited, ("
Petro UK
"), a wholly owned subsidiary of the Company,
entered into a Farmout Agreement to acquire a 9% interest in
Petroleum License PL 1/10 and P2123 (the “
Larne
Licenses
”) located in the
Larne Basin in Northern Ireland (the "
Larne
Transaction
"). The
two Larne Licenses, one onshore and one offshore, together
encompass approximately 130,000 acres covering the large majority
of the prospective Larne Basin. The other parties to the
Farmout Agreement are Southwestern Resources Ltd, a wholly owned
subsidiary of Horizon Energy, which will acquire a 16% interest,
and Brigantes Energy Limited, which will retain a 10%
interest. Third parties will own the remaining 65%
interest.
Under the terms of the Farmout Agreement, Petro UK deposited
approximately $735,000 into an escrow agreement
("
Escrow
Agreement
"), which amount
represented Petro UK's obligation to fund the total projected cost
to drill the first well under the terms of the Farmout Agreement.
The total deposited amount to fund the cost to drill the first well
is approximately $6,159,452, based on an exchange rate of one
British Pound for 1.44 U.S. Dollars. Petro UK was and will continue
to be responsible for its pro-rata costs of additional wells
drilled under the Farmout Agreement. Drilling of the first well was
completed in June 2016 and was unsuccessful. The initial costs
incurred by the Company were reclassified from prepaid oil and gas
development costs to oil and gas assets not being amortized on the
consolidated balance sheets.
Spyglass Drilling Program.
On August 19, 2016, Spyglass Energy Group, LLC
(“
Spyglass
”), a wholly owned subsidiary of Bandolier
Energy, LLC (“
Bandolier
”), entered into a Joint Exploration and
Development Agreement (the “
Exploration
Agreement
”) between
Spyglass, Phoenix 2016, LLC (“
Phoenix
”) and Mackey Consulting & Leasing, LLC
(“
Mackey
”). Pursuant to the Exploration
Agreement, Phoenix and Mackey shall operate and provide certain
services, including obtaining permits and providing technical
services, at cost, in connection with a Phase I Development Program
as agreed to by the parties (the “
Phase I
Program
”). Phoenix and Mackey shall earn
a 25% working interest on all wells drilled in the Phase I
Program. Following success and completion of the Phase I
Program, Phoenix and Mackey shall earn a 25% working interest in
the Osage County, Oklahoma Concession held by Spyglass. Under the
Exploration Agreement, Bandolier has agreed commit up to $2.1
million towards costs of the Phase I Program, at their sole
discretion.
Divestiture of Missouri Properties.
During the quarter
ended July 31, 2016, the Company
assigned its leaseholds covering approximately 320
acres in Missouri to a third party in furtherance of the
Company’s corporate strategy to divest its legacy assets. In
conjunction with the assignment, the Company recorded a gain of
$216,850.
Divestiture of Oklahoma Properties.
During the three months ended July 31, 2015, the
Company disposed of some of its interests in its Oklahoma oil and
gas assets and received proceeds totaling $279,013. The proceeds
were offset against the full cost pool, therefore no gain or loss
was recognized.
Impairment of Oil & Gas Properties.
As of January 31, 2017,
the Company assessed its oil and gas assets for impairment and
recognized a charge of $20,942 related to the Oklahoma oil and gas
property. As of January 31, 2016, the Company assessed its oil and
gas assets for impairment and recognized a charge of $6,870,613
related to the Oklahoma and Missouri oil and gas
properties.
The Company recorded amortization expense of $0 and $30,113,
respectively, for the three months ended January 31, 2017 and 2016,
respectively,
and recorded
amortization expense of $0 and $90,339, respectively, for the nine
months ended January 31, 2017 and 2016, respectively,
related to certain intangible assets
which were acquired during 2015, but for which are no longer
recorded by the Company as they were fully impaired during fiscal
year 2016.
|
10.
|
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 January
31, 2017 and April 30, 2016, based on a future undiscounted
liability of $638,330 and $956,612, respectively. These costs are
expected to be incurred within one 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:
|
|
Nine Months Ended
January 31,
2017
|
Nine Months Ended
January 31,
2016
|
|
Balance,
beginning of period
|
$
763,062
|
$
918,430
|
|
Disposals
|
(216,580
)
|
(207,827
)
|
|
Accretion
|
10,780
|
48,320
|
|
|
557,262
|
758,923
|
|
Less:
Current portion for cash flows expected to be incurred within one
year
|
(406,403
)
|
(541,959
)
|
|
Long-term
portion, end of period
|
$
150,859
|
$
216,964
|
Expected timing of asset retirement obligations:
|
|
|
|
2017 (remainder of year)
|
$
406,403
|
|
2018
|
-
|
|
2019
|
-
|
|
2020
|
-
|
|
2021
|
-
|
|
Thereafter
|
231,927
|
|
Subtotal
|
638,330
|
|
Effect
of discount
|
(81,068
)
|
|
Total
|
$
557,262
|
|
11.
|
Related Party Transactions
|
Employment Agreements
On October 30, 2015, Mr. Stephen Brunner joined the Company as
President. Mr. Brunner has been tasked with making oil
and gas related decisions and executing the Company’s growth
strategy. Under the terms of the contract, Mr. Brunner receives a
base salary of $10,000 per month. Mr. Brunner was also granted
53,244 stock options. He also has the right to purchase an
additional 1.75% of the Company’s common stock subject to
shareholder approval on the increase of the current stock option
plan and achieving pre-defined target objectives.
The Company computed the fair value of the grant as of the date of
grant utilizing a Black-Scholes option-pricing model using the
following assumptions: common share value based on the fair value
of the Company’s common stock as quoted on the Over the
Counter Bulletin Board, $1.78; exercise price of $2.00; expected
volatility of 171%; and a discount rate of 2.16%. The grant date
fair value of the award was $89,525.
For the three months
ended January 31, 2017 and 2016, the Company expensed $6,101
and $6,101, respectively, to general and administrative
expenses. For the nine months ended January 31, 2017 and 2016, the
Company expensed $18,303 and $24,006 respectively, to general
and administrative expenses.
MegaWest Transaction
On October 15, 2015, the Company entered into the Contribution
Agreement with MegaWest and Fortis, pursuant to which the Company
and Fortis each agreed to contribute certain assets to MegaWest in
exchange for shares of MegaWest common stock. See Note 5
above.
Accounts Receivable - Related Party
As discussed in Note 5 above, on October 15, 2015, the Company
entered into the Contribution Agreement with MegaWest and Fortis
pursuant to which the Company and Fortis each agreed to assign
certain assets to MegaWest in exchange for the MegaWest
Shares.
Upon execution of the Contribution Agreement, Fortis transferred
certain indirect interests held in 30 condominium units and the
rights to any profits and proceeds therefrom, with its basis of
$15,544,382, to MegaWest. As of January 31, 2017 and April 30,
2016, the Company had an accounts receivable – related party
in the amount of $2,738,807 and $4,829,693, respectively, which was
due from Fortis for the profits belonging to MegaWest. See Note 5
above.
Notes Receivable – Related Party
As discussed in Note 6, the Company entered into eight promissory
note agreements with Fortis, with total principal amount of
$21,590,803 as of January 31, 2016. The notes receivable bear
interest at an annual interest rate of 3% and mature on December
31, 2017. For the three and nine months ended January 31, 2017, the
Company recorded $163,479 and $462,245 of interest income on the
notes receivable. As of January 31, 2017 and April 30, 2016, the
outstanding balance of the notes receivable was $21,590,803 and
$17,848,000, respectively.
Notes Payable – Related Party
On December 1, 2015, the Company issued a non-recourse promissory
note, in the principal amount of $750,000 to Horizon Investments
(
“Note
A”
), the proceeds of
which were to be used for working capital purposes. Interest on
Note A was due upon the earlier to occur of closing of the Horizon
Transaction, or December 31, 2016. Amounts due under the terms of
Note A accrued interest at an annual rate equal to one half of one
percent.
On December 7, 2015, the Company entered into the Horizon
Transaction, pursuant to which the Company executed a purchase
agreement to acquire Horizon Investments in an all-stock deal. See
Note 4. Mr. Scot Cohen, the Company’s Executive Chairman, is
the sole Manager of Horizon Investments. In addition, Mr. Cohen
owns a 9.2% membership interest in Horizon Investments. Horizon
Investments owns a 20% interest in Horizon Energy
Partners. Mr. Cohen owns a 2.8% membership interest in
Horizon Energy Partners.
On January 13, 2016, the Company issued a second non-recourse
promissory note in the principal amount of $750,000
("
Note
B
") to Horizon Investments. All
of the proceeds from Note B were used to fund Petro UK's
obligations under the terms of the Farmout Agreement, and were
deposited into the Escrow Agreement. The principal and all accrued
and unpaid interest on Note B was due upon the earlier to occur of
closing of the transactions contemplated under the terms of the
Purchase Agreement. Amounts due under the terms of Note B accrued
interest at an annual rate equal to one half of one
percent.
On April 7, 2016, the Company issued a third non-recourse
promissory note in the principal amount of $100,000
("
Note
C
") to Horizon Investments. All
of the proceeds from Note C were used to fund working capital
requirements. The principal and all accrued and unpaid interest on
Note C was due upon the earlier to occur of closing of the
transactions contemplated under the terms of the Purchase
Agreement. Amounts due under the terms of Note C accrued interest
at an annual rate equal to one half of one
percent.
Upon consummation of the Horizon Transaction on May 3, 2016, each
of Note A, Note B and Note C were paid off in full.
As of January 31, 2017 and April 30, 2016, the Company had
5,000,000 shares of preferred stock, par value $0.00001 per share,
were authorized. As of January 31, 2017 and April 30, 2016, the
Company had 29,500 shares of Series B Preferred Stock, par value
$0.00001 per share (“
Series B
Preferred
”), were
authorized. No Series B Preferred shares are currently issued or
outstanding, and no other series of preferred stock have been
designated.
As of January 31, 2017 and April 30, 2016, the Company had
150,000,000 shares of common stock, par value $0.00001 per share,
were authorized. During the nine months ended January 31, 2017, the
Company issued 11,564,250 shares of common stock related to the
Horizon Acquisition as discussed in Note 4 above. There were
15,827,998 and 4,263,748 shares of common stock issued and
outstanding as of January 31, 2017 and April 30, 2016,
respectively.
The following table summarizes information about the options
changes of options for the period from April 30, 2016 to January
31, 2017 and options outstanding and exercisable at January 31,
2017:
|
|
Options
|
Weighted
Average
Exercise
Prices
|
|
|
|
|
|
Outstanding April 30, 2016
|
743,050
|
$
4.00
|
|
Exercisable – April 30, 2016
|
421,460
|
$
3.41
|
|
Granted
|
1,766,458
|
1.38
|
|
Exercised
|
-
|
-
|
|
Forfeited/Cancelled
|
(14,326
)
|
-
|
|
Outstanding – January 31, 2017
|
2,495,182
|
$
2.51
|
|
Exercisable – January 31, 2017
|
1,652,626
|
$
2.10
|
|
|
|
|
|
Outstanding – Aggregate Intrinsic Value
|
$
-
|
$
-
|
|
Exercisable – Aggregate Intrinsic Value
|
$
-
|
$
-
|
During the nine months ended January 31, 2017, the Company issued
1,766,458 options to employees and consultants. The fair
value of the grant was computed as of the date of grant utilizing a
Black-Scholes option-pricing model using the following assumptions:
common share value based on the fair value of the Company’s
common stock as quoted on the Over the Counter Bulletin Board,
range of $1.30 to $1.90; exercise price range of $1.38 to
$3.39; expected volatility range of 170% to 187%; and a discount
rate range of 1.43% to 1.84%.
The following table summarizes information about the options
outstanding and exercisable at January 31, 2017:
|
|
|
|
|
|
|
Exercise
Price
|
Options
|
Weighted Avg.
Life Remaining
|
Options
|
|
|
$
1.38
|
1,761,458
|
9.45
years
|
1,069,860
|
|
|
$
1.98
|
5,000
|
9.51
years
|
2,500
|
|
|
$
2.00
|
457,402
|
8.50
years
|
383,972
|
|
|
$
2.87
|
65,334
|
8.50
years
|
61,611
|
|
|
$
3.00
|
51,001
|
9.16
years
|
42,445
|
|
|
$
3.39
|
12,000
|
9.14
years
|
8,000
|
|
|
$
6.00
|
10,000
|
8.25
years
|
10,000
|
|
|
$
12.00
|
132,987
|
6.98
years
|
74,238
|
|
|
|
2,495,182
|
|
1,652,626
|
|
Aggregate
Intrinsic Value
|
$
-
|
|
$
-
|
|
During the three months ended January 31, 2017 and 2016, the
Company expensed $335,462 and $311,993, respectively, to general
and administrative expense for stock-based compensation pursuant to
employment and consulting agreements. During the nine months ended
January 31, 2017 and 2015, the Company expensed $1,850,462 and
$1,485,993, respectively, to general and administrative expense for
stock-based compensation pursuant to employment and consulting
agreements.
As of January 31, 2017, the Company has approximately $882,600 in
unrecognized stock-based compensation expense, which will be
amortized over a weighted average exercise period of approximately
3.25 years.
Warrants:
|
|
|
Weighted
Average
Exercise Price
|
Weighted
Average Life
Remaining
|
|
Outstanding and exercisable – April 30, 2016
|
133,333
|
$
50.00
|
3.08
|
|
Forfeited
|
-
|
-
|
-
|
|
Granted
|
-
|
-
|
-
|
|
Outstanding and exercisable – January 31, 2017
|
133,333
|
50.00
|
3.08
|
There were no changes to the Company’s warrants during the
nine months ended January 31, 2017. The aggregate intrinsic value
of the outstanding warrants was $0.
|
14.
|
Non-Controlling Interest
|
For the nine months ended January 31, 2017, the changes in the
Company’s non–controlling interest were as
follows:
|
|
|
|
|
|
Non–controlling
interest at April 30, 2016
|
$
(731,060
)
|
$
12,782,378
|
$
12,051,318
|
|
Contribution
of cash by non-controlling interest holders
|
176,000
|
-
|
176,000
|
|
Non–controlling
interest share of income (losses)
|
(116,752
)
|
248,613
|
131,861
|
|
Non–controlling interest at January 31, 2017
|
$
(671,812
)
|
$
13,030,991
|
$
12,359,179
|
During the nine months ended January 31, 2017, Bandolier received
cash contributions totaling $659,163 resulting from a mandatory
capital call to its members. On August 8, 2016, Bandolier’s
Board of Managers approved a capital call of $1,250,000 due per
extension to April 30, 2017 to fund certain re-completions and test
wells to be drilled in Osage County. MegaWest Kansas' portion of
the capital call is $625,000, of which it has funded $483,163 and
$141,837 is due on or prior to April 30, 2017. Pearsonia West's
portion of the capital call is $550,000, of which it has funded
$176,000 and $374,000 is due on or prior to April 30, 2017. Ranger
Station has elected not to fund its capital call amount of $75,000.
As a result, Ranger Station has forfeited its 6% interest in
Bandolier and such interest has been allocated pro rata between
MegaWest Kansas and Pearsonia West as of January 31,
2017.
|
15.
|
Contingency and Contractual Obligations
|
(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 $566,000 as of March 8, 2017). 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 $496,000 as of March 8, 2017). 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.
(b) In September 2013, the Company was notified by the Railroad
Commission of Texas (the “
Commission
”) that the Company was not in compliance
with regulations promulgated by the 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 Commission therefore collected $25,000 from
the Company, which was originally deposited with the Commission, to
cover a portion of the estimated costs of $88,960 to plug the
wells. In addition to the above, the 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, Plaintiffs
filed a Notice of Appeal to the Tenth Circuit Court of
Appeals. That appeal is pending as of the effective date of
this response. 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.
MegaWest Missouri filed a second case on October 14, 2014
(
MegaWest
Energy Missouri Corp. v. James Long, Jodeane Long, and Arrow Mines
LLC
, case number
14VE-CV00599). This case is pending in Vernon County,
Missouri. Although the two cases are separate, they are
interrelated. In the Vernon County case, MegaWest Missouri
has made claims for: (1) replevin for personal property; (2)
conversion of personal property; (3) breach of the covenant of
quiet enjoyment regarding the lease; (4) constructive eviction of
the lease; (5) breach of fiduciary obligation against James Long;
(6) declaratory judgment that the oil and gas lease did not
terminate; and (7) injunctive relief to enjoin the action pending
in Barton County, Missouri. The plaintiffs filed a motion to
dismiss on November 4, 2014, and Arrow Mines, LLC filed a motion to
dismiss on November 13, 2014. Both motions remain pending,
and MegaWest Missouri will file an opposition to the motions in the
near future.
(e) 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.