Attached files
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended July 31, 2017
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______ to ______.
Commission file number: 000-49760
PETRO RIVER OIL CORP.
(Exact Name of Registrant as Specified in Its Charter)
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Delaware
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98-0611188
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(State or Other Jurisdiction of
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(I.R.S. Employer
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Incorporation or Organization)
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Identification No.)
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55 5th Avenue, Suite 1702, New York, NY
10003
(Address of Principal Executive Offices, Zip Code)
(469) 828-3900
(Registrant’s Telephone Number, Including Area
Code)
Indicate by check mark whether the registrant: (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements
for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any, every
Interactive Data File required to be submitted and posted pursuant
to Rule 405 of Regulation S-T (Sec.232.405 of this chapter) during
the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes [X] No
[ ]
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated filer, a
smaller reporting company or an emerging growth company. See the
definitions of “large accelerated filer,”
“accelerated filer,” “smaller reporting
company” and “emerging growth company” in Rule
12b-2 of the Exchange Act.
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Large accelerated filer [ ]
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Accelerated filer [ ]
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Non-accelerated filer [ ]
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Smaller reporting company [X]
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Emerging growth company [ ]
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If an
emerging growth company, indicate by check mark if the registrant
has elected not to use the extended transition period for complying
with any new or revised financial accounting standards provided to
Section 7(a)(2)(B) of the Securities Act. [ ]
Indicate by check mark whether the registrant is a shell company
(as defined in Rule 12b-2 of the Exchange Act). Yes [ ]
No [X]
Indicate the number of shares outstanding of each of the
issuer’s classes of common stock, as of the latest
practicable date.
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Class
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Outstanding at September 14, 2017
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Common Stock, $0.00001 par value per share
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15,843,142 shares
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TABLE OF CONTENTS
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Page
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PART I - FINANCIAL INFORMATION
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Item
1.
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1
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1
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2
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3
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4
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Item
2.
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19
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Item
3.
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26
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Item
4.
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26
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PART II - OTHER INFORMATION
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Item
1.
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26
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Item
1A.
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27
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Item
2.
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28
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Item
3.
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28
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Item
4.
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28
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Item
5.
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28
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Item
6.
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28
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29
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ITEM
1. FINANCIAL
STATEMENTS.
Petro
River Oil Corp. and Subsidiaries
Consolidated Balance
Sheets
(Unaudited)
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As
of
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July
31, 2017
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April
30, 2017
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Assets
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Current
Assets:
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Cash and cash
equivalents
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$1,167,124
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$631,232
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Accounts receivable
- oil and gas
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8,669
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8,423
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Accounts receivable
- real estate - related party
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1,146,673
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2,123,175
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Accrued interest on
notes receivable - related party
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992,309
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797,710
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Interest in real
estate rights
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-
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309,860
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Prepaid expenses
and other current assets
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32,367
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207,831
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Prepaid oil and gas
asset development costs
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894,879
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613,480
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Notes receivable -
related party, current portion
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26,344,883
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24,786,382
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Total
Current Assets
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30,586,904
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29,478,093
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Oil and gas assets,
full cost method
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Costs subject to
amortization, net
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1,973,313
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1,234,806
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Costs not being
amortized, net
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858,828
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858,830
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Property,
plant and equipment, net of accumulated depreciation of
$184,330 and $184,140, respectively
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1,392
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1,582
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Investment in
Horizon Energy Partners
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1,592,418
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1,213,000
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Other
assets
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17,133
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17,133
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Total
Long-term Assets
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4,443,084
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3,325,351
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Total
Assets
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$35,029,988
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$32,803,444
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Liabilities
and Equity
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Current
Liabilities:
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Accounts payable
and accrued expenses
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$376,597
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$120,233
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Deferred tax
liability
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3,640,928
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3,442,724
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Asset retirement
obligations, current portion
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406,403
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406,403
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Total
Current Liabilities
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4,423,928
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3,969,360
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Long-term
Liabilities:
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Asset retirement
obligations, net of current portion
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162,764
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152,293
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Note payable, net
of debt discount of $914,678 and $0, respectively
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1,085,322
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-
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Total
Long-term Liabilities
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1,248,086
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152,293
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Total
Liabilities
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5,672,014
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4,121,653
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Commitments
and contingencies
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Equity:
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Preferred shares -
5,000,000 authorized; par value $0.00001; 0 shares issued and
outstanding
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-
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Preferred B shares
- 29,500 authorized; par value $0.00001; 0 shares issued and
outstanding
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-
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Common shares -
100,000,000 authorized; par value $0.00001; 15,840,143 and
15,827,921 issued and outstanding, respectively
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158
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158
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Additional paid-in
capital
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48,162,461
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46,681,073
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Accumulated
deficit
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(31,489,686)
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(30,609,910)
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Total
Petro River Oil Corp. Equity
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16,672,933
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16,071,321
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Non-controlling
interests
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12,685,041
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12,610,470
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Total
Equity
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29,357,974
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28,681,791
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Total
Liabilities and Equity
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$35,029,988
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$32,803,444
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The accompanying notes are an integral part of these consolidated
financial statements.
Petro River Oil Corp. and Subsidiaries
Consolidated Statements of Operations
(Unaudited)
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For the Three Months
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Ended
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Operations
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July 31, 2017
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July 31, 2016
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Revenues
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Oil and natural gas sales
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$8,803
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$-
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Total Revenues
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8,803
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-
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Operating Expenses
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Lease operating expenses
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18,362
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23,759
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Depreciation, depletion and accretion
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9,120
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4,396
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Gain on sale of oil and gas assets
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(216,580)
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General and administrative
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992,557
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1,708,141
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Total Operating Expenses
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1,020,039
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1,519,716
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Operating Loss
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(1,011,236)
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(1,519,716)
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Other Income (Expense)
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Interest income (expense) - net
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132,745
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141,259
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Net gain on real estate rights
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271,490
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300,639
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Other Income
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404,235
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441,898
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Net Loss Before Income Tax Provision
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(607,001)
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(1,077,818)
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Income Tax Provision
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198,204
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187,917
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Net Loss
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(805,205)
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(1,265,735)
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Net Income Attributable to Non-controlling Interest
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74,571
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47,675
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Net Loss Attributable to Petro River Oil Corp.
Shareholders
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$(879,776)
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$(1,313,410)
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Basic and Diluted Net Loss Per Common Share
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$(0.06)
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$(0.09)
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Weighted Average Number of Common Shares Outstanding - Basic and
Diluted
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15,835,095
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15,450,826
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The accompanying notes are an integral part of these consolidated
financial statements.
Petro River Oil Corp. and Subsidiaries
Consolidated Statements of Cash Flows
(Unaudited)
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For the Three Months
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Ended
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July 31, 2017
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July 31, 2016
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CASH FLOWS FROM OPERATING ACTIVITIES:
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Net
loss
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$(805,205)
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$(1,265,735)
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Adjustments to reconcile net loss to net cash (used in) provided by
operating activities:
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Stock-based
compensation
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529,332
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1,150,197
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Depreciation,
depletion and accretion
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9,120
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4,396
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Amortization
of debt discount
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37,378
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-
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Gain
on sale of oil and gas assets
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(216,580)
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Net
gain on interest in real estate rights
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(271,490)
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(300,639)
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Deferred
income tax expense
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198,204
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187,917
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Changes
in operating assets and liabilities:
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Accounts
receivable – oil and gas
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(246)
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903
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Accrued
interest on notes receivable – related party
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(194,599)
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(141,259)
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Prepaid
expenses and other assets
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175,464
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(66,867)
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Accounts
payable and accrued expenses
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256,364
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(39,806)
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Net Cash Used in Operating Activities
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(65,678)
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(687,473)
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Cash Flows From Investing Activities:
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Proceeds
from the sale of interest in real estate rights
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1,557,852
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2,915,332
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Prepaid
oil and gas assets
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(281,399)
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(65,947)
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Issuance
of notes receivable – related party
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(1,558,501)
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(2,947,129)
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Capitalized
expenditures on oil and gas assets
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(736,964)
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(6,790)
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Cash
received from acquisition of Horizon Investments
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3,364,817
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Cash
paid for cost method investment
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(379,418)
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(525,000)
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Net Cash
(Used in) Provided by Investing Activities
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(1,398,430)
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2,735,283
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CASH FLOW FROM FINANCING ACTIVITIES:
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Proceeds
from notes payable – related party
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2,000,000
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Net Cash Provided by Financing Activities
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2,000,000
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-
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Change
in cash and cash equivalents
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535,892
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2,047,810
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Cash
and cash equivalents, beginning of period
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631,232
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774,751
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Cash
and cash equivalents, end of period
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$1,167,124
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$2,822,561
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SUPPLEMENTARY
CASH FLOW INFORMATION:
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Cash
paid during the period for:
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Income
taxes
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$34,052
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$3,789
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Interest
paid
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$-
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$-
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NON-CASH
INVESTING AND FINANCING ACTIVITIES:
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Reclassification
from prepaid oil and gas development costs to oil and gas assets
not being amortized
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$-
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$761,444
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Asset
retirement obligation from drilling activities
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$7,500
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-
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Warrants
issued with notes payable
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$952,056
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$-
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The accompanying notes are an integral part of these consolidated
financial statements.
PETRO RIVER OIL CORP.
Notes to the Consolidated Financial
Statements
(Unaudited)
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1.
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Organization
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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 Osage County, 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.
Recent Developments
Kern County Drilling Program: On July 18, 2017, the Company
announced a new oil field discovery upon successful drilling of the
Cattani-Rennie 47X-15 exploration well (“CR 47X”) in its Sunset Boulevard
prospect in Kern County, California. The Company is currently
conducting well tests on multiple zones. Results are expected in
October 2017. The Company owns a 19.25% interest in the Sunset
Boulevard prospect in Kern County field based on a 13.75% direct
working interest, and a 5.5% indirect working interest through its
20% equity investment in Horizon Energy.
On
August 15, 2017, the Company announced a second oil field discovery
upon successful drilling of the Chardonnay 47X-35 exploration well
(the “Chardonnay
47X”) at its Grapevine project in Kern County,
California. The Company is currently conducting well tests, and
expects to announce production results in October 2017. The Company
owns an 8% indirect interest in the Grapevine project through its
20% equity investment in Horizon Energy.
Osage County Drilling Program: On May 8, 2017,
the Company announced the discovery of a new oil field on the
Company's 106,500-acre concession in Osage County, Oklahoma (the
“Osage
Concession”). The Company’s Chat #2-11,
now known as the S. Blackland #2-11, successfully tested a
seismically-delineated structure on the Company’s concession.
The 30-day oil flow test indicates initial production rates of up
to 35 BOE per day.
On May
30, 2017, the Company announced a second oil discovery on its Osage
Concession. The 30-day oil flow test of the Red Fork 1-3
well, now known as the W. Blackland #1-3, indicates initial
production rates of up to 71 BOE per day.
The
Company recently identified 1,730 acres of structural closures
highlighted in its existing 3D seismic, and confirmed as a result
of the successful drilling of W. Blackland #1-3 and S. Blackland
#2-11. The Company does not expect to have any meaningful
production until early 2018 following completion of its 2017
drilling program. Currently, both the W. Blackland #1-3 and
S. Blackland #2-11 wells are shut-in until late 2017 in order to
build production facilities.
$2.0 Million Secured Note Financing. On June 13, 2017, the
Company entered into a Securities Purchase Agreement
(“Purchase
Agreement”) with Petro Exploration Funding, LLC
(“Funding
Corp.”), pursuant to which the Company issued to
Funding Corp. a senior secured promissory note to finance the
Company’s working capital requirements, in the principal
amount of $2.0 million (“Secured Note”). As additional
consideration for the note financing, the Company issued to Funding
Corp. (i) a warrant to purchase 840,336 shares of the
Company’s common stock, $0.00001 par value, and (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, currently held by Spyglass pursuant to
an Assignment of Overriding Royalty Interests (the
“2017
Override”).
The
Secured Note accrues interest at a rate of 10% per annum, and
matures on June 30, 2020. To secure the repayment of all amounts
due under the terms of the Secured Note, the Company entered into a
Security Agreement, pursuant to which the Company granted to
Funding Corp. a security interest in all assets of the Company. The
first interest payment will be due on June 1, 2018, and each
six-month anniversary thereafter until the outstanding principal
balance of the Secured Note is paid in full.
The
warrant is exercisable immediately upon issuance, for an exercise
price per share equal to $2.38 per share, and shall terminate, if
not previously exercised, five years from the date of issuance.
Scot Cohen, a member of the Company’s Board of Directors and
a substantial stockholder of the Company, owns or controls 31.25%
of Funding Corp.
Purchase of 2% Overriding Royalty Interest. On August 14, 2017, following
a review of the Company’s capital requirements necessary to
fund its 2017 development program, the Company’s independent
directors consented to Scot Cohen’s purchase from various
third parties who collectively held a 2% overriding royalty
interest that originally burdened the Osage County, Oklahoma
concession for $250,000 (the “Original Override”). Mr. Cohen
agreed to sell the Original Override to the Company at the same
price paid by him (plus market interest on his capital) upon a
determination by the Company to finance the Osage County
development plan on terms similar to the June 13, 2017 secured note
financing.
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2.
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Basis of Preparation
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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.
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, 2017 filed with the Securities
and Exchange Commission (the “SEC”) on July 31, 2017. 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, 2017 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, 2018.
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3.
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Significant Accounting Policies
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(a)
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Use of Estimates:
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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.
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(b)
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Cash and Cash Equivalents:
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Cash and cash equivalents include all highly liquid monetary
instruments with original maturities of three months or less when
purchased. These investments are carried at cost, which
approximates fair value. Financial instruments that potentially
subject the Company to concentrations of credit risk consist
primarily of cash deposits. The Company maintains its cash in
institutions insured by the Federal Deposit Insurance Corporation
(“FDIC”). At times, the Company’s cash and
cash equivalent balances may be uninsured or in amounts that exceed
the FDIC insurance limits. At
July 31, 2017, approximately $788,831 of the Company’s cash
balances were uninsured. The Company has not experienced any loses
on such accounts.
|
(c)
|
Receivables:
|
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, 2017 and April 30,
2017 was $0.
|
(d)
|
Interest in Real Estate Rights:
|
Interest 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.
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. For the three
months ended July 31, 2017, the Company evaluated and recorded
no impairment on these properties.
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 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 three months ended July 31, 2017, the Company did
not record an impairment charge 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 three months ended July 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, (ii) the equity method, or (iii) the cost method. 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)
|
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.
|
(h)
|
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.
|
(i)
|
Income Taxes:
|
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 evaluates uncertain tax positions to recognize a tax
benefit from an uncertain tax position only if it is more likely
than not that the tax position will be sustained on examination by
the taxing authorities based on the technical merits of the
position. Those tax positions failing to qualify for initial
recognition are recognized in the first interim period in which
they meet the more likely than not standard, or are resolved
through negotiation or litigation with the taxing authority, or
upon expiration of the statute of limitations. De-recognition of a
tax position that was previously recognized occurs when an entity
subsequently determines that a tax position no longer meets the
more likely than not threshold of being sustained.
At July 31, 2017 and April 30, 2017, the Company had approximately
$3,640,928 and $3,442,724, respectively, of liabilities for
uncertain tax positions. 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).
|
(j)
|
Per Share Amounts:
|
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 months ended July 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 July 31,
2017 and 2016:
|
|
July 31,
2017
|
July 31,
2016
|
|
Stock
Options
|
2,574,682
|
2,502,182
|
|
Stock Purchase
Warrants
|
973,669
|
133,333
|
|
Total
|
3,548,351
|
2,635,515
|
|
(k)
|
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.
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.
|
(k)
|
Subsequent Events:
|
The Company has evaluated all transactions through the date the
consolidated financial statements were issued for subsequent event
disclosure consideration.
|
4.
|
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 each of the three months ended July 31,
2017 and 2016, Fortis sold 1 condominium unit, and MegaWest
recorded a net gain on interest in real estate rights of $271,490
and $300,639, respectively. As of July 31, 2017, the Company had an
accounts receivable – related party in the amount of
$1,146,673 related to interest in real estate rights of condominium
units sold.
The accounts 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.
Proceeds from the amounts receivable from Fortis will not be
available until such time as the Company has completed its
evaluation of the Bandolier prospects. In this regard, the
Contribution Agreement provided for a redetermination of the fair
market value of the Bandolier Interest at any time following the
six month anniversary after the execution thereof (the
“Redetermination”), Upon
a Redetermination, which has not occurred as of September 14, 2017,
but is anticipated prior to December 31, 2017, in the event there
is a shortfall from the valuation ascribed to the Bandolier
Interest at the time of the Redetermination, as compared to the
value ascribed to the Bandolier Interest in the Contribution
Agreement, the Company will be required to provide Fortis with a
cash payment in an amount equal to the shortfall. If the
Company is unable to deliver to Fortis the cash payment required
after the Redetermination, if any, the board of directors of
MegaWest shall have the right to exercise certain remedies against
the Company, including a right to foreclose on the Company’s
entire equity in MegaWest, which equity interest has been pledged
to Fortis under the terms of the Contribution Agreement. In
the event of foreclosure, the Bandolier Interest would revert back
to the Company, and the Company would record a loss for the amount
of the notes receivable, interest in real estate rights, accounts
receivable – related party, and any accrued
interest.
|
5.
|
Notes Receivable – Related Party
|
Since
December 2015, the Company has entered into ten promissory note
agreements with Fortis with aggregate principal amounts of
$26,344,883. The notes receivable bear interest at an annual rate
of 3% and mature on December 31, 2017. As of July 31, 2017,
and April 31, 2017, the outstanding balance of the notes receivable
was $26,344,883 and $24,786,382, respectively.
|
6.
|
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 three months ended July 31,
2017, the Company recognized a net gain of $271,490 related to the
sale of one condominium unit by Fortis.
The following table summarizes the activity for interest in real
estate rights:
|
|
Three Months Ended
July 31, 2017
|
|
Balance at April 30, 2017
|
$309,860
|
|
Cost
of sales – one condominium unit
|
(309,860)
|
|
Balance
at July 31, 2017
|
$-
|
|
7.
|
Oil and Gas Assets
|
The following table summarizes the activity of the oil and gas
assets by project for the three months ended July 31,
2017:
|
|
Oklahoma
|
Larne
Basin
|
Other (1)
|
Total
|
|
Balance
May 1, 2017
|
$1,232,192
|
$761,444
|
$100,000
|
$2,093,636
|
|
Additions
|
744,464
|
-
|
-
|
744,464
|
|
Disposals
|
-
|
-
|
-
|
-
|
|
Depreciation,
depletion and amortization
|
(5,959)
|
-
|
-
|
(5,959)
|
|
Impairment
of oil and gas assets
|
-
|
-
|
-
|
-
|
|
Balance
July 31, 2017
|
$1,970,697
|
$761,444
|
$100,000
|
$2,832,141
|
(1) Other property consists primarily of four used steam generators
and related equipment that will be assigned to future projects. As
of July 31, 2017, and April 30, 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 to acquire a
13.75% working interest in certain oil and gas leases located in
southern Kern County, California. 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.
As of April 30, 2016, exploratory activity had not commenced and
the $108,333 was 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. As of July 31, 2016,
development of the first well had not commenced and the escrow
payment was recorded as prepaid oil and gas development costs on
the consolidated balance sheet. 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.
Oklahoma Properties. During the three months ended July 31,
2017, the Company paid approximately $739,500 and $5,000 for proven
and unproven oil and gas assets, respectively.
Divestiture of Kansas Properties. On December 23, 2015, Petro River Oil,
LLC (“Petro
LLC”), a
wholly owned subsidiary of MegaWest, divested various interests in
oil and gas leases, wells, records, data and related personal
property located along the Mississippi Lime play in the state of
Kansas, which assets were acquired by Petro LLC in 2012. In
connection with the divestiture, the assignee and purchaser of the
interests agreed to pay outstanding liabilities, including unpaid
taxes, and assume certain responsibilities to plug any abandoned
wells. No cash consideration was paid for the
interests. The Company recorded a loss of $7,519,460 in
connection with the divestiture of these oil and gas properties,
representing the $7,727,287 oil and gas assets book value,
partially offset by the asset retirement obligation liability.
MegaWest is a 58.51% owned subsidiary of the Company following
consummation of the MegaWest Transaction, defined
above.
Impairment of Oil & Gas Properties. As of July 31, 2017, the Company
assessed its oil and gas assets for impairment and did not
recognized a charge related to its oil and gas property. As of
April 30, 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.
|
8.
|
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,
2017 and April 30, 2017, based on a future undiscounted liability
of $648,848 and $573,069, 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:
|
|
Three Months Ended
July 31,
2017
|
Three Months Ended
July 31,
2016
|
|
Balance,
beginning of period
|
$558,696
|
$763,062
|
|
Additions
|
7,500
|
-
|
|
Disposals
|
-
|
(216,580
|
|
Accretion
|
2,971
|
4,207
|
|
|
569,167
|
550,689
|
|
Less:
Current portion for cash flows expected to be incurred within one
year
|
(406,403)
|
(406,403)
|
|
Long-term
portion, end of period
|
$162,764
|
$144,286
|
Expected timing of asset retirement obligations:
|
Year
Ending April 30,
|
|
|
2018
(remainder of year)
|
$406,403
|
|
2019
|
-
|
|
2020
|
-
|
|
2021
|
-
|
|
2022
|
-
|
|
Thereafter
|
242,445
|
|
Subtotal
|
648,848
|
|
Effect
of discount
|
(79,681)
|
|
Total
|
$569,167
|
|
9.
|
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 July 31, 2017 and 2016, the Company expensed $6,101
and $6,101, 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 July 31, 2017 and April 30, 2017,
the Company had an accounts receivable – related party in the
amount of $1,146,673 and $2,123,175, 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 ten promissory
note agreements with Fortis, with total principal amount of
$26,344,883 as of July 31, 2017. The notes receivable bear interest
at an annual interest rate of 3% and mature on December 31, 2017.
For the three months ended July 31, 2017, the Company recorded
$194,599 of interest income on the notes receivable. As of July 31,
2017, and April 30, 2017, the outstanding balance of the notes
receivable was $26,344,883 and $24,786,382,
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.
$2.0 Million Secured Note Financing
Scot
Cohen, a member of the Company’s Board of Directors and a
substantial stockholder of the Company, owns or controls 31.25% of
Funding Corp., the holder of the Secured Note issued by the Company
in June 2017 in the principal amount of $2.0 million. The Secured
Note accrues interest at a rate of 10% per annum, and matures on
June 30, 2020. (See Note 1). The Secured Note is presented as
“Note payable – related party, net of debt
discount” on the consolidated balance sheets.
Pursuant
to the financing agreement, the Company issued to Funding Corp. a
warrant to purchase 840,336 shares of the Company’s common
stock. Upon issuance of the note, the Company valued the warrants
at the grant date share price of $2.38 and recorded $952,056 to
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 $914,678 as of July 31,
2017. During the three months ended July 31, 2017 and 2016, the
Company recorded amortization of debt discount totaling $37,378 and
$0, respectively. See Note 10 for the assumptions and inputs
utilized to value the warrants granted.
As of July 31, 2017, the outstanding balance, net of debt discount,
and accrued interest on the notes due to the lender was $1,085,322
and $24,476, respectively.
As
additional consideration for the purchase of the Secured Note, the
Company issued to Funding Corp. the 2017 Override, which provided
Funding Corp. with 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,
currently held by Spyglass.
Purchase of 2% Overriding Royalty
On
August 14, 2017, following a review of the Company’s capital
requirements necessary to fund its 2017 development program, the
Company’s independent directors consented to Scot
Cohen’s purchase from various third parties who collectively
held a 2% overriding royalty interest that originally burdened the
Osage County, Oklahoma concession for $250,000 (the
“Original
Override”). Mr. Cohen agreed to sell the Original
Override to the Company at the same price paid by him (plus market
interest on his capital) upon a determination by the Company to
finance the Osage County development plan on terms similar to the
June 13, 2017 secured note financing.
|
10.
|
Equity
|
As of July 31, 2017 and April 30, 2017, the Company had 5,000,000
shares of preferred stock, par value $0.00001 per share,
authorized. As of July 31, 2017 and April 30, 2017, 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 have been
designated.
As of July 31, 2017 and April 30, 2017, the Company had 150,000,000
shares of common stock, par value $0.00001 per share, authorized.
During the three months ended July 31, 2017, the Company issued
12,222 shares of common stock related to a cashless exercise of
25,000 options. There were 15,840,143 and 15,827,921 shares of
common stock issued and outstanding as of July 31, 2017 and April
30, 2017, respectively.
Options
The following table summarizes information about the options
changes of options for the period from April 30, 2017 to July 31,
2017 and options outstanding and exercisable at July 31,
2017:
|
|
Options
|
Weighted
Average
Exercise
Prices
|
|
|
|
|
|
Outstanding April 30, 2017
|
2,599,682
|
$2.13
|
|
Exercisable – April 30, 2017
|
1,954,735
|
2.35
|
|
Granted
|
-
|
|
|
Exercised
|
(25,000)
|
1.38
|
|
Forfeited/Cancelled
|
-
|
|
|
Outstanding – July 31, 2017
|
2,574,682
|
2.14
|
|
Exercisable – July 31, 2017
|
2,169,277
|
$2.25
|
|
|
|
|
|
Outstanding – Aggregate Intrinsic Value
|
|
$1,717,333
|
|
Exercisable – Aggregate Intrinsic Value
|
|
$1,412,799
|
The following table summarizes information about the options
outstanding and exercisable at July 31, 2017:
|
Exercise Price
|
Options
Outstanding
|
Weighted Avg.
Life
Remaining
(years)
|
Options
Exercisable
|
Weighted Average Exercise Price
|
|
$1.38
|
1,840,958
|
9.54
|
1,509,503
|
$1.38
|
|
$1.98
|
5,000
|
9.27
|
4,950
|
$1.98
|
|
$2.00
|
457,402
|
8.25
|
392,781
|
$2.00
|
|
$2.87
|
65,334
|
8.25
|
64,611
|
$2.87
|
|
$3.00
|
51,001
|
9.91
|
42,445
|
$3.00
|
|
$3.39
|
12,000
|
8.89
|
12,000
|
$3.39
|
|
$6.00
|
10,000
|
8.00
|
10,000
|
$6.00
|
|
$12.00
|
132,987
|
6.73
|
132,987
|
$12.00
|
|
|
2,574,682
|
|
2,169,277
|
|
The aggregate intrinsic value of the outstanding options was
$1,717,333.
During the three months ended July 31, 2017 and 2016, the Company
expensed $529,332 and $1,150,197, 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, 2017, the Company has approximately $972,397 in
unrecognized stock-based compensation expense related to unvested
options, which will be amortized over a weighted average exercise
period of approximately 3.00 years.
Warrants
The
fair value of the 840,336 warrants granted in conjunction with the
$2.0 Million Secured Note (as discussed in Note 9) were estimated
on the date of grant using the Black-Scholes option-pricing
model.
The
assumptions used for the warrants granted during the three months
ended July 31, 2017 are as follows:
|
|
June
30,
2017
|
|
Exercise
price
|
$2.38
|
|
Expected
dividends
|
0%
|
|
Expected
volatility
|
169.63%
|
|
Risk free interest
rate
|
1.49%
|
|
Expected
life of warrant
|
3
years
|
The following is a summary of the Company’s warrant
activity:
|
|
Number of
Warrants
|
Weighted
Average
Exercise Price
|
Weighted
Average Life
Remaining
|
|
Outstanding and exercisable – April 30, 2017
|
133,333
|
$50.00
|
2.83
|
|
Forfeited
|
-
|
-
|
-
|
|
Granted
|
840,336
|
2.05
|
2.48
|
|
Outstanding and exercisable – July 31, 2017
|
973,669
|
8.90
|
2.84
|
The aggregate intrinsic value of the outstanding warrants was
$0.
|
11.
|
Non-Controlling Interest
|
For the three months ended July 31, 2017, the changes in the
Company’s non–controlling interest were as
follows:
|
|
Bandolier
|
Fortis
|
Total
|
|
Non–controlling interest at April 30, 2017
|
$(699,873)
|
$13,310,343
|
$12,610,470
|
|
Contribution
of cash by non-controlling interest holders
|
-
|
-
|
-
|
|
Non–controlling
interest share of income (losses)
|
(36,574)
|
111,145
|
74,571
|
|
Non–controlling interest at July 31, 2017
|
$(736,447)
|
$13,421,488
|
$12,685,041
|
|
12.
|
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 $625,000 as of September 13, 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 $548,000 as of September 13, 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.
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.
Redetermination of Bandolier Interest.
In
connection with the Contribution Agreement, entered into by and
between the Company, MegaWest and Fortis (see Note 5), the parties
agreed to the Redetermination of the fair market value of the
Bandolier Interest at any time following the six-month anniversary
after the execution thereof. Upon a Redetermination,
which has not occurred as of September 14, 2017, but is anticipated
prior to December 31, 2017, in the event there is a shortfall from
the valuation ascribed to the Bandolier Interest at the time of the
Redetermination, as compared to the value ascribed to the Bandolier
Interest in the Contribution Agreement, the Company will be
required to provide Fortis with a cash payment in an amount equal
to the shortfall. If the Company is unable to deliver to
Fortis the cash payment required after the Redetermination, if any,
the board of directors of MegaWest shall have the right to exercise
certain remedies against the Company, including a right to
foreclose on the Company’s entire equity in MegaWest, which
equity interest has been pledged to Fortis under the terms of the
Contribution Agreement. In the event of foreclosure, the
Bandolier Interest would revert back to the Company, and the
Company would record a loss for the amount of the notes receivable,
interest in real estate rights, accounts receivable – related
party, and any accrued interest.
|
13.
|
Subsequent Events
|
The Company has evaluated subsequent events through the date the
financial statements were available to be issued. Based on this
evaluation, the Company has identified no reportable subsequent
events other than those disclosed below or elsewhere in these
financials.
In August 2017, the Company
issued 2,923 shares of common stock related to a cashless exercise
of 10,000 options.
ITEM
2. MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS.
Except as otherwise indicated by the context, references in this
Quarterly Report to “we”, “us”,
“our” or the “Company” are to the
consolidated businesses of Petro River Oil Corp. and its
wholly-owned direct and indirect subsidiaries and majority-owned
subsidiaries, except that references to “our common
stock” or “our capital stock” or similar terms
refer to the common stock, par value $0.00001 per share, of Petro
River Oil Corp., a Delaware corporation (the
“Company”).
Management’s Discussion and Analysis of Financial Condition
and Results of Operations (“MD&A”) is designed to provide information that
is supplemental to, and should be read together with, the
Company’s consolidated financial statements and the
accompanying notes contained in this Quarterly Report. Information
in this Item 2 is intended to assist the reader in obtaining an
understanding of the consolidated financial statements, the changes
in certain key items in those financial statements from quarter to
quarter, the primary factors that accounted for those changes, and
any known trends or uncertainties that the Company is aware of that
may have a material effect on the Company’s future
performance, as well as how certain accounting principles affect
the consolidated financial statements. This includes discussion of
(i) Liquidity, (ii) Capital Resources, (iii) Results of Operations,
and (iv) Off-Balance Sheet Arrangements, and any other information
that would be necessary to an understanding of the company’s
financial condition, changes in financial condition and results of
operations.
Forward Looking Statements
The following is management’s discussion and analysis of
certain significant factors which have affected our financial
position and operating results during the periods included in the
accompanying consolidated financial statements, as well as
information relating to the plans of our current management and
should be read in conjunction with the accompanying financial
statements and their related notes included in this Report.
References in this section to “we,” “us,”
“our,” or the “Company” are to the
consolidated business of Petro River Oil Corp. and its wholly owned
and majority owned subsidiaries.
This Report contains forward-looking statements. Generally, the
words “believes,” “anticipates,”
“may,” “will,” “should,”
“expects,” “intends,”
“estimates,” “continues,” and similar
expressions or the negative thereof or comparable terminology are
intended to identify forward-looking statements. Such statements
are subject to certain risks and uncertainties, including the
matters set forth in this Report or other reports or documents we
file with the Securities and Exchange Commission
(“SEC”) from time to time, which could cause
actual results or outcomes to differ materially from those
projected. Undue reliance should not be placed on these
forward-looking statements, which speak only as of the date hereof.
We undertake no obligation to update these forward-looking
statements.
The
following discussion of our financial condition and results of
operations is based upon and should be read in conjunction with our
consolidated financial statements and their related notes included
in this Quarterly Report and our Annual Report on Form 10-K filed
with the SEC on July 31, 2017 for the year ended April 30,
2017.
Business Overview
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.
The execution of our 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, we plan to acquire high-quality oil and gas properties,
primarily proved producing and proved undeveloped reserves. We also
intend to explore low-risk development drilling and work-over
opportunities. Management is also exploring farm
in and joint venture opportunities for our oil and gas
assets.
Recent Developments
Kern County Drilling
Program: On July 18, 2017, the Company announced a new oil
field discovery upon successful drilling of the Cattani-Rennie
47X-15 exploration well (“CR
47X”) in its Sunset Boulevard prospect in Kern County,
California. The Company is currently conducting well tests on
multiple zones. Results are expected in October 2017. The Company
owns a 19.25% interest in the Sunset Boulevard prospect in Kern
County field based on a 13.75% direct working interest, and a 5.5%
indirect working interest through its 20% equity investment in
Horizon Energy.
On
August 15, 2017, the Company announced a second oil field discovery
upon successful drilling of the Chardonnay 47X-35 exploration well
(the “Chardonnay
47X”) at its Grapevine project in Kern County,
California. The Company is currently conducting well tests, and
expects to announce production results in October 2017. The Company
owns an 8% indirect interest in the Grapevine project through its
20% equity investment in Horizon Energy.
Osage County Drilling Program: On May 8, 2017,
the Company announced the discovery of a new oil field on the
Company's 106,500-acre concession in Osage County, Oklahoma (the
“Osage
Concession”). The Company’s Chat #2-11,
now known as the S. Blackland #2-11, successfully tested a
seismically-delineated structure on the Company’s concession.
The estimated ultimate recovery (“EUR”) per well is up to 63,000
barrels of oil equivalent (“BOE”). The 30-day oil flow test
indicates initial production rates of up to 35 BOE per
day.
On May
30, 2017, the Company announced a second oil discovery on its Osage
Concession. The 30-day oil flow test of the Red Fork 1-3, now
known as the W. Blackland #1-3, indicates initial production rates
of up to 71 BOE per day, suggesting an EUR per well of 105,000 BOE.
Given the 250-acre size of this second structure, we
anticipate drilling as many as eight offset wells before the end of
2017, which can produce a total of up to 945,000 BOE over the life
of the field. Each well is highly profitable at current oil
prices with drilling and completion costs of approximately $200,000
and low lease operating expenses.
The
Company expects to announce complete development plans for both of
its S. Blackland and W. Blackland oilfields by October 2017.
In addition, the Company will also announce further exploration
opportunities in its Osage Concession with a potential to prove up
to 4,300,000 BOE (based on 20 acre well spacing) from the recently
identified 1,730 acres of structural closures highlighted in its
existing 3D seismic, and confirmed as a result of the successful
drilling of W. Blackland #1-3 and S. Blackland #2-11. The
Company does not expect to have any meaningful production until
early 2018 following completion of its 2017 drilling program.
Currently, both the W. Blackland #1-3 and S. Blackland #2-11
are shut-in until late 2017 in order to build production
facilities.
The
Company’s Osage County drilling program is the result of a
Joint Exploration and Development Agreement (the
“Exploration
Agreement”), dated August 19, 2016, between Spyglass,
a wholly owned subsidiary of Bandolier, Phoenix 2016, LLC
(“Phoenix”) and
Mackey Consulting & Leasing, LLC (“Mackey”). Pursuant to the
Exploration Agreement, Phoenix and Mackey operates and provides
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 its sole
discretion.
$2.0 Million Secured Note Financing. On June 13, 2017, the
Company entered into a Securities Purchase Agreement
(“Purchase
Agreement”) with Petro Exploration Funding, LLC
(“Funding
Corp.”), pursuant to which the Company issued to
Funding Corp. a senior secured promissory note to finance the
Company’s working capital requirements, in the principal
amount of $2.0 million (“Secured Note”). As additional
consideration for the note financing, the Company issued to Funding
Corp. (i) a warrant to purchase 840,336 shares of the
Company’s common stock, $0.00001 par value, and (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, currently held by Spyglass pursuant to
an Assignment of Overriding Royalty Interests (the
“2017
Override”).
The
Secured Note accrues interest at a rate of 10% per annum, and
matures on June 30, 2020. To secure the repayment of all amounts
due under the terms of the Secured Note, the Company entered into a
Security Agreement, pursuant to which the Company granted to
Funding Corp. a security interest in all assets of the Company. The
first interest payment will be due on June 1, 2018 and each
six-month anniversary thereafter until the outstanding principal
balance of the Secured Note is paid in full.
The
warrant is exercisable immediately upon issuance, for an exercise
price per share equal to $2.38 per share, and shall terminate, if
not previously exercised, five years from the date of
issuance.
Scot
Cohen, a member of the Company’s Board of Directors and a
substantial stockholder of the Company, owns or controls 31.25% of
Funding Corp.
On
August 14, 2017, following a review of the Company’s capital
requirements necessary to fund its 2017 development program, the
Company’s independent directors consented to Scot
Cohen’s purchase from various third parties who collectively
held a 2% overriding royalty interest that originally burdened the
Osage County, Oklahoma concession for $250,000. Mr. Cohen agreed to
sell this 2% overriding royalty to the Company at the same price
paid by him (plus market interest on his capital) upon a
determination by the Company to finance the Osage County
development plan on terms similar to the June 13, 2017 secured note
financing.
Critical Accounting Policies and Estimates
The Company’s significant accounting policies are described
in Note 3 to the annual consolidated financial statements for the
year ended April 30, 2017 and 2015 on Form 10-K filed with the SEC
on July 31, 2017 for the year ended April 30, 2017.
Our discussion and analysis of our financial condition and results
of operations are based upon our consolidated financial statements.
These consolidated financial statements are prepared in accordance
with generally accepted accounting principles in the United States
(“US
GAAP”), which requires us
to make estimates and assumptions that affect the reported amounts
of our assets and liabilities and revenues and expenses, to
disclose contingent assets and liabilities on the date of the
consolidated financial statements, and to disclose the reported
amounts of revenues and expenses incurred during the financial
reporting period. The most significant estimates and assumptions
include the valuation of accounts receivable, and the useful lives
and impairment of property and equipment, goodwill and intangible
assets, the valuation of deferred tax assets and inventories and
the provision for income taxes. We continue to evaluate these
estimates and assumptions that we believe to be reasonable under
the circumstances. We rely on these evaluations as the basis for
making judgments about the carrying values of assets and
liabilities that are not readily apparent from other sources. Since
the use of estimates is an integral component of the financial
reporting process, actual results could differ from those
estimates. Some of our accounting policies require higher degrees
of judgment than others in their application. We believe critical
accounting policies as disclosed in this Form 10-Q reflect the more
significant judgments and estimates used in preparation of our
consolidated financial statements. We believe there have been no
material changes to our critical accounting policies and
estimates.
The following critical accounting policies rely upon assumptions
and estimates and were used in the preparation of our consolidated
financial statements:
Oil and Gas Operations
The Company follows the full cost method of accounting for oil and
gas operations whereby all costs related to exploration and
development of oil and gas reserves are capitalized. Under this
method, the Company capitalizes all acquisition, exploration and
development costs incurred for the purpose of finding oil and
natural gas reserves, including salaries, benefits and other
internal costs directly attributable to these activities. Costs
associated with production and general corporate activities,
however, are expensed in the period incurred. Costs are capitalized
on a country-by-country basis. To date, there has only been one
cost center, the United States.
The present value of estimated future net cash flows is computed by
applying the average first-day-of-the-month prices during the
previous twelve-month period of oil and natural gas to estimated
future production of proved oil and natural gas reserves as of
year-end less estimated future expenditures to be incurred in
developing and producing the proved reserves and assuming
continuation of existing economic conditions. Prior to December 31,
2009, prices and costs used to calculate future net cash flows were
those as of the end of the appropriate quarterly
period.
Following the discovery of reserves and the commencement of
production, the Company will compute depletion of oil and natural
gas properties using the unit-of-production method based upon
production and estimates of proved reserve quantities. Costs
associated with unproved properties are excluded from the depletion
calculation until it is determined whether or not proved reserves
can be assigned to such properties. Unproved properties are
assessed for impairment annually. Significant properties are
assessed individually.
The Company assesses all items classified as unproved property on
an annual basis for possible impairment. The Company assesses
properties on an individual basis or as a group if properties are
individually insignificant. The assessment includes consideration
of the following factors, among others: land relinquishment; intent
to drill; remaining lease term; geological and geophysical
evaluations; drilling results and activity; the assignment of
proved reserves; and the economic viability of development if
proved reserves are assigned. During any period in which these
factors indicate impairment, the related exploration costs incurred
are transferred to the full cost pool and are then subject to
depletion and the ceiling limitations on development oil and
natural gas expenditures.
Proceeds from the sale of oil and gas assets are applied against
capitalized costs, with no gain or loss recognized, unless a sale
would alter the rate of depletion and depreciation by 25 percent or
more.
Significant changes in these factors could reduce our estimates of
future net proceeds and accordingly could result in an impairment
of our oil and gas assets. Management will perform annual
assessments of the carrying amounts of its oil and gas assets as
additional data from ongoing exploration activities becomes
available.
Interest in Real Estate Rights
Interest in real estate rights, previously identified as
“Real estate - held for sale” in our unaudited
consolidated balance sheets are related to real estate currently
held by Fortis, who intends to sell these properties within the
next 12 months. Fortis contributed profit realized from future sale
of these properties to MegaWest, pursuant to the terms and
conditions of the Contribution Agreement, as a part of the MegaWest
Transaction. As we do not know the price at which the real estate
will be sold, the rights are stated on the consolidated balance
sheet as of July 31, 2017 and April 30, 2017 at the cost basis
realized by Fortis.
Income Taxes
The Company uses the asset and liability method in accounting for
income taxes. Under this method, deferred tax assets and
liabilities are determined based on differences between financial
reporting and income tax carrying amounts 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. The Company
reviews deferred tax assets for a valuation allowance based upon
whether it is more likely than not that the deferred tax asset will
be fully realized. A valuation allowance, if necessary, is provided
against deferred tax assets, based upon management’s
assessment as to their realization.
Uncertain Tax Positions
The Company evaluates uncertain tax positions pursuant to ASC Topic
740-10-25 “Accounting for Uncertainty in
Income Taxes,” which
allows companies to recognize a tax benefit from an uncertain tax
position only if it is more likely than not that the tax position
will be sustained on examination by the taxing authorities based on
the technical merits of the position. Those tax positions failing
to qualify for initial recognition are recognized in the first
interim period in which they meet the more likely than not
standard, or are resolved through negotiation or litigation with
the taxing authority, or upon expiration of the statute of
limitations. De-recognition of a tax position that was previously
recognized occurs when an entity subsequently determines that a tax
position no longer meets the more likely than not threshold of
being sustained.
At July 31, 2017 and April 30, 2017, the Company has approximately
$3,640,928 and $3,442,724, respectively, of liabilities for
uncertain tax positions. 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 was 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).
NEW ACCOUNTING STANDARDS
Recently Adopted Accounting Standards
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.
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.
Results of Operations
Results of Operations for the Three Months Ended July 31, 2017
Compared to Three Months Ended July 31, 2016
Oil Sales
During
the three months ended July 31, 2017, the Company recognized $8,803
in oil and gas sales, compared to $0 for the three months ended
July 31, 2016. The overall increase in
sales of $8,803 is primarily due to the Company commencing
production in Osage County, Oklahoma. The Company
anticipates increasing revenue in subsequent quarters based on
additional discoveries in Kern County, as well as from the
Company’s prospects in Osage County, Oklahoma following the
successful drilling of the Company’s W. Blackland #1-3 Well
and S. Blackland #2-11 Well. Given
current oil and gas prices; however, and the Company’s
limited development budget, management does not anticipate deriving
substantial revenue from existing oil and gas assets in the
short-term; provided, however, in the event oil and gas prices rise
from current levels, or in the event current drilling activity and
re-completions results in additional proven reserves that can be
extracted profitably at current oil and gas prices, management
anticipates the addition of material oil and gas sales, although no
assurances can be given.
Lease Operating Expense
During the three months ended July 31, 2017, lease operating
expense was $18,362, as compared to $23,759 for the three months
ended July 31, 2016. The overall decrease in lease operating
expense of $5,397 was primarily attributable to management’s
commitment to substantially reduce operating expenses in light of
the current challenging oil price environment.
Impairment of Oil and Gas Assets
The Company assesses all items classified as unproved property on
an annual basis for possible impairment. The Company assesses
properties on an individual basis or as a group if properties are
individually insignificant. The assessment includes consideration
of the following factors, among others: land relinquishment; intent
to drill; remaining lease term; geological and geophysical
evaluations; drilling results and activity; the assignment of
proved reserves; and the economic viability of development if
proved reserves are assigned. Significant changes in these factors
could reduce our estimates of future net proceeds and accordingly
could result in an impairment of our oil and gas assets. During the
three months ended July 31, 2017, the Company reviewed the oil and
gas assets for impairment and did not recognized an impairment
charge.
General and Administrative Expense
General and administrative expense for the three months ended July
31, 2017 was $992,557, as compared to $1,708,141 for
the three months ended July 31, 2016. The decrease was primarily
attributable to decreases in salaries, professional fees and
benefits and office and administrative expenses. These changes are
outlined below:
|
|
For the Three Months Ended
|
For the Three Months Ended
|
|
|
July 31, 2017
|
July 31, 2016
|
|
Salaries
and benefits
|
$578,423
|
$1,215,197
|
|
Professional
fees
|
266,968
|
292,038
|
|
Office
and administrative
|
147,166
|
200,906
|
|
Total
|
$992,557
|
$1,708,141
|
Salaries and benefits include non-cash stock-based compensation of
$529,332 for three months ended July 31, 2017 compared to
$1,150,197 for the three months ended July 31, 2016. The decrease
in stock-based compensation of $858,467 from the three months ended
July 31, 2017 was due to fewer awards made during the current
period. General and administrative expenses decreased
due to
management’s commitment to substantially reduce expenses in
light of the current challenging oil price
environment.
Interest Income (Expense)
During the three months ended July 31, 2017, the Company recognized
$132,745 in interest income (expense) compared to interest income
of $141,259 for the three months ended July 31, 2016. During the
three months ended July 31, 2017, the Company recorded interest
income $194,599 accrued on the related party notes receivable. The
interest income was offset by $37,378 and $24,476 which were the
accretion of the debt discount and interest expense related to the
$2.0 million secured financing.
Net Gain on Interests in Real Estate Rights
During the three months ended July 31, 2017, the Company recognized
$271,490 net gain on its interest in real estate rights compared to
$300,639 net gain for the three months ended July 31, 2016. The net
gain on interest in real estate rights for the three months ended
July 31, 2017 and 2016 was due to the sale of one condominium unit
in each period by Fortis, and the resulting profits which were
assigned to MegaWest pursuant to the Contribution Agreement, less
the book value recorded by MegaWest.
Liquidity and Capital Resources
At July 31, 2017, the Company had working capital of
approximately $26.2 million, of which approximately $26.3 million,
$1.1 million and $0.9 million of several notes receivable from a
related party, an account receivable from a related party, and
prepaid oil and gas assets, respectively.
Proceeds from the notes receivable from Fortis will not be
available until such time as the Company has completed the
redetermination of the fair market value of the Bandolier Interest,
which has not occurred as of September 14, 2017, but is anticipated
prior to December 31, 2017, In the event there is a shortfall from
the valuation ascribed to the Bandolier Interest at the time of the
Redetermination, as compared to the value ascribed to the Bandolier
Interest in the Contribution Agreement, the Company will be
required to provide Fortis with a cash payment in an amount equal
to the shortfall, and any unfunded shortfall will likely result in
the foreclosure on all or a portion of the Company’s entire
equity interest in MegaWest, which equity interest has been pledged
to Fortis. No assurances can be given that the value of the
Bandolier Interest will equal the valuation set forth in the
Contribution Agreement, or if the value identified after the
Redetermination is below the initial valuation, that we will be
able to fund such shortfall. Any requirement to fund a shortfall
will have a material and adverse effect on our operations and
financial condition.
In the event of a foreclosure of our equity interest in MegaWest
resulting in such equity interest decreasing to less than a
controlling interest in MegaWest, the assets conveyed to MegaWest
under the terms of the Contribution Agreement may no longer be
consolidated with the Company’s assets on the Company’s
financial statements, and the Bandolier Interest may revert back to
the Company. As a result, our financial condition and
results from operations may be adversely affected, and such affect
will be material.
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. At
July 31, 2017, the Company had cash and cash equivalents of
approximately $1.2 million. The Company’s primary source
of operating funds since inception has been equity and note
financings, as well as through the consummation of the Horizon
Acquisition. While management believes that the current level of
working capital is sufficient to maintain current operations as
well as the planned added operations for the next 12 months,
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.
Operating Activities
During the three months ended July 31, 2017, operating activities
used cash of $65,678 compared to $687,473 used in
operating
activities during the three months ended July 31, 2016.
The Company incurred a net loss during
the three months ended July 31, 2017 of $805,205 as compared to a
net loss of $1,265,735 for the
three months ended July 31, 2016. For three months
ended July 31, 2017, the net loss was offset by non-cash items such
as stock-based compensation, depreciation, depletion and accretion
of asset retirement obligation, impairment of oil and gas assets,
and the deferred tax liability. Cash provided by operations was
also influenced by changes in accounts receivable, accrued interest
on notes receivable, prepaid expenses and accounts payable and
accrued expenses. For the three months ended July 31, 2016, the
loss was offset by non-cash items such as stock-based compensation,
depreciation, depletion and amortization, impairment of oil and gas
assets, gain on sale of oil and gas assets and accretion of asset
retirement obligation. Cash used in operations was also influenced
by changes in accounts receivable, prepaid expenses and accounts
payable and accrued expenses.
Investing Activities
Investing activities during the three months ended July 31, 2017
resulted in cash used of $1,398,430, as compared to cash provided
of $2,735,283 during the three months
ended July 31, 2016. During the three months ended July 31, 2017,
the Company invested an additional $379,418 in Horizon Energy
Partners compared to $525,000 in the comparable period in 2016.
During the three months ended July 31, 2017, the Company received
proceeds of $1,557,852 from profits in its real estate rights
compared to $2,915,332 for the three months ended July 31, 2016.
During the three months ended July 31, 2017, the Company incurred
$736,964 of expenditures on oil and gas assets compared to $6,790
for the three months ended July 31, 2016. During the three months
ended July 31, 2017, the Company executed notes receivable
agreements with related parties resulting in the outlay of
$1,558,501 compared to $2,947,129 during the period ended July 31,
2016. During the three months ended July 31, 2016, the Company
received $3,364,817 from the acquisition of Horizon
Investments.
Financing Activities
Financing activities during the three months ended July 31, 2017
resulted in cash provided of $2,000,000, as compared to
$0 during the three months
ended July 31, 2016. The increase was due to the issuance of
a $2.0 million note payable during the current
period.
Capitalization
The number of outstanding shares and the number of shares that
could be issued if all common stock equivalents are converted to
shares is as follows:
|
As
of
|
July 31,
2017
|
July 31,
2016
|
|
Common
shares
|
15,840,143
|
4,263,711
|
|
Stock
options
|
2,574,682
|
2,502,182
|
|
Stock
purchase warrants
|
973,669
|
133,333
|
|
|
19,388,494
|
6,899,226
|
Off-Balance Sheet Arrangements
None.
ITEM
3. QUANTITATIVE AND
QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
Not applicable
ITEM
4. CONTROLS AND
PROCEDURES
A. Material Weaknesses
As discussed in Item 9A of our Annual Report on Form 10-K for the
fiscal year ended April 30, 2017, we identified material weaknesses
in the design and operation of our internal controls. The material
weaknesses are due to the limited number of employees, which
impacts our ability to conduct a thorough internal review, and the
Company’s reliance on external accounting personnel to
prepare financial statements.
To remediate the material weakness, the Company is developing a
plan to design and implement the operation of our internal
controls. Upon the Company obtaining additional capital,
the Company intends to hire additional accounting staff, and
operations and administrative executives in the future to address
its material weaknesses.
We will continue to monitor and assess our remediation initiatives
to ensure that the aforementioned material weaknesses are
remediated.
B. Evaluation of Disclosure Controls and Procedures
The Company maintains disclosure controls and procedures and
internal controls designed to ensure that information required to
be disclosed in the Company’s filings under the Securities
Exchange Act of 1934 is recorded, processed, summarized and
reported within the time periods specified in the Securities and
Exchange Commission’s rules and forms. The Company’s
management, with the participation of its principal executive and
principal financial officers, has evaluated the effectiveness of
the Company’s disclosure controls and procedures as of the
end of the period covered by this Quarterly Report on Form 10-Q.
Based upon that evaluation and solely due to the unremediated
material weaknesses described above, the Company’s principal
executive and financial officers have concluded that such
disclosure controls and procedures were not effective for the
purpose for which they were designed as of the end of such period.
As a result of this conclusion, the financial statements for the
period covered by this report were prepared with particular
attention to the unremediated material weaknesses previously
disclosed. Accordingly, management believes that the consolidated
financial statements included in this report fairly present, in all
material respects, the Company’s financial condition, results
of operations and cash flows as of and for the periods presented,
in accordance with US GAAP, notwithstanding the unremediated
weaknesses.
C. Changes in Internal Control over Financial
Reporting
There was no change in the Company’s internal control over
financial reporting that was identified in connection with such
evaluation that occurred during the period covered by this
Quarterly Report on Form 10-Q that has materially affected, or is
reasonably likely to materially affect, the Company’s
internal control over financial reporting.
PART II - OTHER INFORMATION
ITEM
1. LEGAL
PROCEEDINGS.
(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 $625,000 as of September 13, 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 $548,000 as of September 13, 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.
ITEM 1A. RISK
FACTORS
Our results of operations and financial condition are subject to
numerous risks and uncertainties described in our Annual Report on
Form 10-K for our fiscal year ended April 30, 2017, filed on July
31, 2017. You should carefully consider these risk factors in
conjunction with the other information contained in this Quarterly
Report. Should any of these risks materialize, our business,
financial condition and future prospects could be negatively
impacted. As of July 31, 2017, there have been no material changes
to the disclosures made in the above-referenced Form
10-K.
ITEM
2. UNREGISTERED SALES OF EQUITY
SECURITIES AND USE OF PROCEEDS.
None.
ITEM 3. DEFAULTS UPON SENIOR
SECURITIES.
None.
ITEM 4. MINE
SAFETY DISCLOSURES.
Not applicable.
ITEM 5. OTHER INFORMATION.
(a) There is no information required to be disclosed on Form 8-K
during the period covered by this Form 10-Q that was not so
reported.
(b) There were no material changes to the procedures by which
security holders may recommend nominees to the registrant’s
Board of Directors during the quarter ended July 31,
2017.
ITEM 6. EXHIBITS AND FINANCIAL STATEMENT
SCHEDULES
(a) Financial Statements.
Our financial statements as set forth in the Index to Financial
Statements attached hereto commencing on page F-1 are hereby
incorporated by reference.
(b) Exhibits.
The following exhibits, which are numbered in accordance with Item
601 of Regulation S-K, are filed herewith or, as noted,
incorporated by reference herein:
|
Exhibit
Number
|
|
Exhibit Description
|
|
31.1*
|
|
Certification of Chief Executive Officer Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
|
|
31.2*
|
|
Certification of Chief Financial Officer Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002.
|
|
32.1*
|
|
Certification of Chief Executive Officer Pursuant to 18 U.S.C.
Section 1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
|
|
32.2*
|
|
Certification of Chief Financial Officer Pursuant to 18 U.S.C.
Section 1350, as Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
|
|
101.INS*
|
|
XBRL Instance Document
|
|
101.SCH*
|
|
XBRL Taxonomy Extension Schema Document
|
|
101.CAL*
|
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
|
101.DEF*
|
|
XBRL Taxonomy Extension Definition Linkbase Document
|
|
101.LAB*
|
|
XBRL Taxonomy Extension Labels Linkbase Document
|
|
101.PRE*
|
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
|
*
|
Filed herewith.
|
In
accordance with Section 13 or 15(d) of the Exchange Act, the
registrant caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
|
|
PETRO RIVER OIL CORP.
|
|
|
|
|
|
|
|
By:
|
/s/ Scot Cohen
|
|
|
Name:
|
Scot Cohen
|
|
|
Title:
|
Executive Chairman
|
|
|
|
|
|
|
By:
|
/s/ David Briones
|
|
|
Name:
|
David Briones
|
|
|
Title
|
Chief Financial Officer
|
|
Date: September 14, 2017
|
|
|
|
|
|
|
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