Item
1. Financial Statements.
NORRIS
INDUSTRIES, INC.
BALANCE
SHEETS
(Unaudited)
|
|
|
May
31, 2018
|
|
|
February
28, 2018
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
205,725
|
|
|
$
|
244,997
|
|
|
Accounts receivable
- oil & gas
|
|
|
57,725
|
|
|
|
108,644
|
|
|
Accounts
receivable - other
|
|
|
18,038
|
|
|
|
-
|
|
|
Total
Current Assets
|
|
|
281,488
|
|
|
|
353,641
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Property
- Full Cost Method
|
|
|
|
|
|
|
|
|
|
Properties subject
to amortization
|
|
|
2,716,102
|
|
|
|
2,716,102
|
|
|
Less:
accumulated depletion
|
|
|
(83,790
|
)
|
|
|
(69,760
|
)
|
|
Total Oil and Gas
Property, net
|
|
|
2,632,312
|
|
|
|
2,646,342
|
|
|
Equipment, net
|
|
|
11,421
|
|
|
|
12,646
|
|
|
Total
Assets
|
|
$
|
2,925,221
|
|
|
$
|
3,012,629
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND
STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
|
Accounts payable
and accrued expenses
|
|
$
|
82,401
|
|
|
$
|
43,020
|
|
|
Accounts
payable and accrued expenses - related party
|
|
|
32,133
|
|
|
|
20,412
|
|
|
Total Current Liabilities
|
|
|
114,534
|
|
|
|
63,432
|
|
|
|
|
|
|
|
|
|
|
|
|
Convertible note payable - related party
|
|
|
1,550,000
|
|
|
|
1,550,000
|
|
|
Asset retirement
obligations
|
|
|
86,462
|
|
|
|
76,657
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Liabilities
|
|
|
1,750,996
|
|
|
|
1,690,089
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders’
Equity
|
|
|
|
|
|
|
|
|
|
Preferred stock, $0.001 par value
per share 10,000,000 shares authorized:
|
|
|
-
|
|
|
|
-
|
|
|
Series A Convertible
Preferred stock, 1,000,000 shares issued and outstanding
|
|
|
1,000
|
|
|
|
1,000
|
|
|
Common stock, $0.001 par value per
share, 150,000,000 shares authorized; 89,443,013 shares issued and outstanding
|
|
|
89,443
|
|
|
|
89,443
|
|
|
Additional paid-in
capital
|
|
|
6,021,483
|
|
|
|
5,967,483
|
|
|
Accumulated
deficit
|
|
|
(4,937,701
|
)
|
|
|
(4,735,386
|
)
|
|
Total
Stockholder’s Equity
|
|
|
1,174,225
|
|
|
|
1,322,540
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Liabilities and Stockholders’ Equity
|
|
$
|
2,925,221
|
|
|
$
|
3,012,629
|
|
The
accompanying notes are an integral part of these financial statements.
NORRIS
INDUSTRIES, INC.
STATEMENTS
OF OPERATIONS
FOR
THE THREE MONTHS ENDED MAY 31, 2018 AND 2017
(Unaudited)
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
Oil
and gas sales
|
|
$
|
126,072
|
|
|
$
|
19,979
|
|
|
Total Revenues
|
|
|
126,072
|
|
|
|
19,979
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Expenses
|
|
|
|
|
|
|
|
|
|
Lease operating
expenses
|
|
|
70,673
|
|
|
|
4,176
|
|
|
General and administrative
expenses
|
|
|
220,933
|
|
|
|
311,417
|
|
|
Depletion,
depreciation and accretion
|
|
|
25,060
|
|
|
|
2,815
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
Operating Expenses
|
|
|
316,666
|
|
|
|
318,408
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss
from Operations
|
|
|
(190,594
|
)
|
|
|
(298,429
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expenses)
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
(11,721
|
)
|
|
|
(3,000
|
)
|
|
Total
Other Income (Expense)
|
|
|
(11,721
|
)
|
|
|
(3,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net
Loss
|
|
$
|
(202,315
|
)
|
|
$
|
(301,429
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net loss per common
share - basic and diluted
|
|
$
|
(0.00
|
)
|
|
$
|
(0.01
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average
number of common shares outstanding - basic and diluted
|
|
|
89,443,013
|
|
|
|
48,805,143
|
|
The
accompanying notes are an integral part of these financial statements.
NORRIS
INDUSTRIES, INC.
STATEMENTS
OF CASH FLOWS
FOR
THE THREE MONTHS ENDED MAY 31, 2018 AND 2017
(Unaudited)
|
|
|
2018
|
|
|
2017
|
|
|
Cash Flow from Operating
Activities
|
|
|
|
|
|
|
|
|
|
Net
loss
|
|
$
|
(202,315
|
)
|
|
$
|
(301,429
|
)
|
|
Adjustments to reconcile
net loss to net cash from operating activities:
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation
and accretion
|
|
|
25,060
|
|
|
|
4,024
|
|
|
Stock-based compensation
|
|
|
54,000
|
|
|
|
119,358
|
|
|
Changes in operating
assets and liabilities:
|
|
|
|
|
|
|
|
|
|
Accounts receivable
- oil & gas
|
|
|
50,919
|
|
|
|
1,371
|
|
|
Accounts receivable
- other
|
|
|
(18,038
|
)
|
|
|
|
|
|
Accounts payable
and accrued expenses
|
|
|
39,381
|
|
|
|
3,000
|
|
|
Accounts
payable and accrued expenses - related parties
|
|
|
11,721
|
|
|
|
-
|
|
|
Net
Cash Used in Operating Activities
|
|
|
(39,272
|
)
|
|
|
(173,676
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow from Financing
Activities
|
|
|
|
|
|
|
|
|
|
Proceeds from loan
payable
|
|
|
-
|
|
|
|
200,000
|
|
|
Payments on related
party advances
|
|
|
-
|
|
|
|
(15,487
|
)
|
|
Proceeds
from issuance of stock payable
|
|
|
-
|
|
|
|
20,000
|
|
|
Net
Cash provided by Financing Activities
|
|
|
-
|
|
|
|
204,513
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase (Decrease)
in Cash
|
|
|
(39,272
|
)
|
|
|
30,837
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash –
beginning of period
|
|
|
244,997
|
|
|
|
76,365
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash –
end of period
|
|
$
|
205,725
|
|
|
$
|
107,202
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental Cash
Flow Information
|
|
|
|
|
|
|
|
|
|
Cash paid for income
taxes
|
|
$
|
-
|
|
|
$
|
-
|
|
|
Cash paid for interest
|
|
$
|
-
|
|
|
$
|
-
|
|
The
accompanying notes are an integral part of these financial statements.
NORRIS
INDUSTRIES, INC.
NOTES
TO FINANCIAL STATEMENTS
(Unaudited)
Note
1 – Organization, Nature of Operations and Summary of Significant Accounting Policies
Norris
Industries, Inc. (“NRIS” or the “Company”) (formerly International Western Petroleum, Inc.), was incorporated
on February 19, 2014 as a Nevada corporation. The Company was formed to conduct operations in the oil and gas industry. The Company’s
principal operating properties are in the Ellenberger formation in Coleman County, and in Jack and Palo-Pinto Counties. The Company’s
production operations are all located in the State of Texas.
The
accompanying unaudited interim financial statements of the Company have been prepared in accordance with accounting principles
generally accepted in the United States of America and the rules of the Securities and Exchange Commission and should be read
in conjunction with the audited financial statements and notes thereto contained in the Company’s Annual Report on Form
10-K filed with the SEC for the year ended February 28, 2018. In the opinion of management, all adjustments, consisting of normal
recurring adjustments, necessary for a fair presentation of the financial position and the results of operations for the interim
periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative of
the results to be expected for the full year. Notes to the unaudited interim financial statements that would substantially duplicate
the disclosures contained in the audited financial statements for the most recent fiscal year as reported in the Form 10-K have
been omitted.
Use
of Estimates
The
preparation of financial statements in conformity with accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure
of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expense
during the period. Actual results could differ from those estimates.
Concentrations
of Credit Risk
Financial
instruments which potentially subject the Company to concentrations of credit risk include cash deposits placed with financial
institutions. The Company maintains its cash in bank accounts which, at times, may exceed federally insured limits as guaranteed
by the Federal Deposit Insurance Corporation (“FDIC”). At May 31, 2018, $0 of the Company’s cash balances were
uninsured. The Company has not experienced any losses on such accounts.
Cash
and Cash Equivalents
The
Company considers all highly liquid investments purchased with an original maturity of the year or less to be cash equivalents.
The Company has not experienced any losses on its deposits of cash and cash equivalents
.
Accounts
Receivable
Accounts
receivable typically consist of oil and gas receivables. The Company has classified these as short-term assets in the balance
sheet because the Company expects repayment or recovery within the next 12 months. The Company evaluates these accounts receivable
for collectability considering the results of operations of these related entities and when necessary records allowances for expected
unrecoverable amounts. To date, no allowances have been recorded.
Oil
& Gas Properties
The
Company follows the full cost method of accounting for its investments in oil and gas properties, whereby all costs incurred in
connection with the acquisition, exploration for and development of petroleum and natural gas reserves, including unproductive
wells, are capitalized. Such costs include lease acquisition, geological and geophysical activities, rentals on non-producing
leases, drilling, completing and equipping of oil and gas wells and administrative costs directly attributable to those activities,
and asset retirement costs. General and administrative costs related to production and general overhead are expensed as incurred.
Disposition
of oil and gas properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such adjustment
would significantly alter the relationship between capital costs and proved reserves of oil, in which case the gain or loss is
recognized in the statement of operations.
Future
development, site restoration, dismantlement and abandonment costs, are estimated property by property, based upon current economic
conditions and regulatory requirements, and are included in amortization of our oil and natural gas property costs.
Depletion
of capitalized oil properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production
method based on proved reserves.
At
the end of each quarter, the unamortized cost of oil and natural gas properties, net of related deferred income taxes, is limited
to the sum of the estimated future after-tax net revenues from proved properties, after giving effect to cash flow hedge positions,
discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects. This limitation
is known as the “ceiling test,” and is based on SEC rules for the full cost oil and gas accounting method. There was
no ceiling test write-down recorded during the three months ended May 31, 2018 and 2017.
The
Company assesses the carrying value of its unproved properties for impairment periodically. If the results of an assessment indicate
that an unproved property is impaired (which was assessed in connection with the Company’s evaluation of goodwill impairment),
then the carrying value of the unproved properties is added to the proved oil property costs to be amortized and subject to the
ceiling test.
Asset
Retirement Obligations
If
a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon
wells can be made, the Company will record a liability (an asset retirement obligation or “ARO”) on its
balance sheet and capitalize the present value of the asset retirement cost in oil and gas properties in the period in which the
retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future
cost to satisfy the abandonment obligation assuming the normal operation of the asset, using current prices that are escalated
by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment
obligation was incurred using an assumed cost of funds for the Company. After recording these amounts, the ARO will be accreted
to its future estimated value using the same assumed cost of funds and the capitalized costs are depreciated on a unit-of-production
basis over the estimated proved developed reserves. Both the accretion and the depreciation will be included in depreciation,
depletion and amortization expense on our statements of operations.
Revenue
Recognition
ASU
2014-09,
“Revenue from Contracts with Customers (Topic 606)”
, supersedes the revenue recognition requirements
and industry-specific guidance under
Revenue Recognition (Topic 605)
. Topic 606 requires an entity to recognize revenue
when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be
entitled to in exchange for those goods or services. The Company adopted Topic 606 on March 1, 2018, using the modified retrospective
method applied to contracts that were not completed as of March 1, 2018. Under the modified retrospective method, prior period
financial positions and results will not be adjusted. The cumulative effect adjustment recognized in the opening balances included
no significant changes as a result of this adoption. While the Company does not expect fiscal year 2019 net earnings to be materially
impacted by revenue recognition timing changes, Topic 606 requires certain changes to the presentation of revenues and related
expenses beginning March 1, 2018. Refer to Note 3 – Revenue from Contracts with Customers for additional information.
The
Company’s revenue is comprised entirely of revenue from exploration and production activities. The Company’s oil is
sold primarily to wholesalers and others that sell product to end use customers. Natural gas is sold primarily to interstate and
intrastate natural-gas pipelines, various end-users, local distribution companies, and natural-gas marketers. NGLs are sold primarily
to various end-users. Payment is generally received from the customer in the month following delivery.
Contracts
with customers have varying terms, including spot sales or month-to-month contracts, or contracts with a finite term, where the
production from a well or group of wells is sold to one or more customers. The Company recognizes sales revenues for oil, natural
gas, and NGLs based on the amount of each product sold to a customer when control transfers to the customer. Generally, control
transfers at the time of delivery to the customer at a pipeline interconnect, the tailgate of a processing facility, or as a tanker
lifting is completed. Revenue is measured based on the contract price, which may be index-based or fixed, and may include adjustments
for market differentials and downstream costs incurred by the customer, including gathering, transportation, and fuel costs.
Revenues
are recognized for the sale of the Company’s net share of production volumes. Sales on behalf of other working interest
owners and royalty interest owners are not recognized as revenues. The company does not hedge nor forward sell any of its current
production via derivative financial contracts.
Income
Taxes
Income
taxes are accounted for in accordance with the provisions of ASC Topic No. 740. Deferred tax assets and liabilities are recognized
for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets
and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected
to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect
on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment
date. Valuation allowances are established, when necessary, to reduce deferred tax assets to the amounts expected to be realized.
Stock-Based
Compensation
The
Company measures stock-based compensation cost at the grant date based on the fair value of the award and recognize it as expense,
over the vesting or service period, as applicable, of the stock award.
Basic
and Diluted Net Income (Loss) per Common Share
Basic
net loss per common share amounts are computed by dividing the net loss available to International Western Petroleum, Inc. shareholders
by the weighted average number of common shares outstanding over the reporting period. In periods in which the Company reports
a net loss, dilutive securities are excluded from the calculation of diluted earnings per share as the effect would be anti-dilutive.
For the three months ended May 31, 2018, the Company’s potentially dilutive shares, which include outstanding common stock
options representing 1,440,000 common stock equivalents have not been included in the computation of diluted net loss per share
as the result would have been anti-dilutive. The Company did not have any potentially dilutive shares for the three months ended
May 31, 2017.
Reclassifications
Certain
reclassifications have been made to amounts in prior periods to conform to the current period presentation. All reclassifications
have been applied consistently to the periods presented.
Subsequent
Events
The
Company evaluated all transactions from May 31, 2018, through the financial statement issuance date for subsequent event disclosure
consideration.
Recently
Adopted Accounting Pronouncements
See
discussion of the adoption of ASU 2014-09,
“Revenue from Contracts with Customers (Topic 606)”
, above.
In
August 2016, the Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“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 Company adopted
this standard on March 1, 2018, on a retrospective basis. There was no impact of the standard on the Company’s financial statements.
In
November 2016, the FASB issued ASU 2016-18,
“Statement of Cash Flows (Topic 230)”
, requiring that the statement
of cash flows explain the change in the total cash, cash equivalents, and amounts generally described as restricted cash or restricted
cash equivalents. This guidance is effective for fiscal years, and interim reporting periods therein, beginning after December
15, 2017, with early adoption permitted. The Company adopted this standard on March 1, 2018, on a retrospective basis. There was
no impact of the standard on the Company’s financial statements.
In
May 2017, the FASB issued ASU 2017-09,
Modification Accounting for Share-Based Payment Arrangements
. The standard amends
the scope of modification accounting for share-based payment arrangements and provides guidance on the types of changes to the
terms or conditions of share-based payment awards to which an entity would be required to apply modification accounting under
ASC 718. The new standard is effective for fiscal years beginning after December 15, 2017. There was no impact on the financial
statements of adopting this new standard on March 1, 2018.
Recently
Issued Accounting Pronouncements
In
February 2016, the FASB issued ASU 2016-02,
Leases
, which aims to make leasing activities more transparent and comparable
and requires substantially all leases be recognized by lessees on their balance sheet as a right-of-use asset and corresponding
lease liability, including leases currently accounted for as operating leases. This ASU is effective for all interim and annual
reporting periods beginning after December 15, 2019, with early adoption permitted. The Company expects to adopt ASU 2016-02 beginning
March 1, 2019 and are in the process of assessing the impact that this new guidance is expected to have on our financial statements
and related disclosures.
In
September 2016, the FASB issued ASU 2016-13,
Financial Instruments-Credit Losses
. ASU 2016-13 was issued to provide more
decision-useful information about the expected credit losses on financial instruments and changes the loss impairment methodology.
ASU 2016-13 is effective for reporting periods beginning after December 15, 2019 using a modified retrospective adoption method.
A prospective transition approach is required for debt securities for which an other-than-temporary impairment had been recognized
before the effective date. The Company is currently assessing the impact this accounting standard will have on its financial statements
and related disclosures.
The
Company does not expect the adoption of recently issued accounting pronouncements to have a significant impact on its financial
position, results of operations or cash flows.
Note
3 – Revenue from Contracts with Customers
Change
in Accounting Policy
The
Company adopted ASU 2014-09,
“Revenue from Contracts with Customers (Topic 606)”
, on March 1, 2018, using the
modified retrospective method applied to contracts that were not completed as of March 1, 2018. Refer to Note 1 – Organization,
Nature of Operations and Summary of Significant Accounting Policies for additional information.
Exploration
and Production
There
were no significant changes to the timing or valuation of revenue recognized for sales of production from exploration and production
activities.
Disaggregation
of Revenue from Contracts with Customers
The
following table disaggregates revenue by significant product type for the three months ended May 31, 2018:
|
Oil sales
|
|
$
|
70,075
|
|
|
Natural gas sales
|
|
|
55,997
|
|
|
Natural gas liquids
sales
|
|
|
-
|
|
|
Total revenue
from customers
|
|
$
|
126,072
|
|
There
were no significant contract liabilities or transaction price allocations to any remaining performance obligations as of February
28, 2018 or May 31, 2018.
Note
4 – Oil & Gas Properties
The
following table summarizes the Company’s oil and gas activities by classification for the three months ended May 31, 2018:
|
|
|
February
28, 2018
|
|
|
Additions
|
|
|
May
31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties,
subject to amortization
|
|
$
|
2,646,878
|
|
|
$
|
-
|
|
|
$
|
2,646,878
|
|
|
Asset retirement costs
|
|
|
69,224
|
|
|
|
-
|
|
|
|
69,224
|
|
|
Accumulated depletion
|
|
|
(69,760
|
)
|
|
|
(14,030
|
)
|
|
|
(83,790
|
)
|
|
Total oil and
gas assets
|
|
$
|
2,646,342
|
|
|
$
|
(14,030
|
)
|
|
$
|
2,632,312
|
|
For
the three months ended May 31, 2018 and 2017, the Company recorded depletion of $14,030 and $7,384, respectively, for production
on proved properties. The Company recorded no impairment of its oil and gas properties during the three months ended May 31, 2018
and 2017.
Note
5 – Equipment
The
Company’s fixed assets consisted of a used vehicle and has an estimated useful life of five years. Fixed assets consisted
of the following at May 31, 2018 and February 28, 2018:
|
|
|
May
31,
2018
|
|
|
February
28,
2018
|
|
|
Vehicle
|
|
$
|
24,500
|
|
|
$
|
24,500
|
|
|
Accumulated depreciation
|
|
|
(13,079
|
)
|
|
|
(11,854
|
)
|
|
Total
|
|
$
|
11,421
|
|
|
$
|
12,646
|
|
The
Company recorded depreciation expense of $1,225 and $1,209, respectively, during the three months ended May 31, 2018 and 2017.
Note
6 – Asset Retirement Obligations
The
following table summarizes the change in the Company’s asset retirement obligations during the three months ended May 31,
2018:
|
Asset
retirement obligations as of February 28, 2018
|
|
$
|
76,657
|
|
|
Additions
|
|
|
-
|
|
|
Current
year revision of previous estimates
|
|
|
-
|
|
|
Accretion
during the three months ended May 31, 2018
|
|
|
9,805
|
|
|
Asset
retirement obligations as of May 31, 2018
|
|
$
|
86,462
|
|
During
the three months ended May 31, 2018 and 2017, the Company recognized accretion expense of $9,805 and $242, respectively.
Note
7 – Convertible Note Payable – Related Party
On
December 28, 2017, the Company borrowed $1,550,000 from JBB (“Loan Note”) to complete the purchases of a series of
oil and leases. The loan has an interest rate of 3% per annum, a maturity date of December 28, 2018 and is secured by all assets
of the Company. The loan is convertible to the Company’s common stock at the conversion rate of $0.20 per share. On June
13, 2018, the Company entered into an amendment of its promissory note to JBB to extend the maturity date to September 30, 2019.
During
the three months ended May 31, 2018, the Company recognized interest expense of $11,721 related to the $1,550,000 promissory note
to JBB.
The
balance of this promissory note was $1,550,000 at May 31, 2018, plus interest of $32,133 that is due at maturity.
On
June 26, 2018, the Company and JBB entered into a modification of the existing Loan Note, to add provisions to permit the Company
to obtain advances under the Loan Note up to a maximum of $1,000,000. The Company may request an advance in increments of $100,000
no more frequently than every 30 days, provided that it provides a description of the use of proceeds for the advance reasonably
acceptable to JBB, and the Company is not otherwise in default of the Loan Note. The original loan amount and the advances are
secured by all the assets of the Company and are convertible into common stock of the Company at the rate of $0.20 per share,
subject to adjustment for any reverse and forward stock splits. The Loan Note may be repaid at any time, without penalty, however,
any advance that is repaid before maturity may not be re-borrowed as a further advance. The maturity date of the original amount
and all the advances is September 30, 2019.
Note
8 – Commitments and Contingencies
Office
Lease
In
March 2015, the Company entered into an amendment to extend the term of its office lease to August 31, 2018. The obligation under
this lease extension for the remainder of its term is approximately $7,000. During the three months ended May 31, 2018, the Company
had total rent expense of $5,543.
Leasehold
Drilling Commitments
The
Company’s oil and gas leasehold acreage is subject to expiration of leases if the Company does not drill and hold such acreage
by production or otherwise exercises options to extend such leases, if available, in exchange for payment of additional cash consideration.
In the King County, Texas lease acreage, 640 acres are due to expire in June 2021. The Company plans to hold significantly all
of this acreage through a program of drilling and completing producing wells. Where the Company is not able to drill and complete
a well before lease expiration, the Company may seek to extend leases where able.
Note
9 – Equity
Preferred
Stock
As
of May 31, 2018, and February 28, 2018, the Company had 1,000,000 shares of its Series A Convertible Preferred Stock issued and
outstanding.
Holders
of the Series A Convertible Preferred Stock have the right to convert shares of Series A Convertible Preferred Stock, at any time
and from time to time, into such number of fully paid and non-assessable shares of common stock as is determined by the number
of shares Series A Convertible Preferred Stock, divided by the product of (i) the Preferred Stock Conversion Price in effect at
the time of conversion and (ii) 0.02. The “Preferred Stock Conversion Price” is initially equal to $0.75 which will
equal 666,666.66 shares of common stock upon conversion. The Preferred Stock Conversion Price is subject to adjustment in the
event of a stock split, merger, reorganization and certain dividend and distribution events. There is no mandatory conversion
or redemption right by the Company.
Common
Stock
As
of May 31, 2018 and February 28, 2018, the Company had 89,443,013 shares of its common stock outstanding.
Stock
Option
During
the year ended February 28, 2018, the Company granted two of its officer’s options to purchase a total of 1,440,000 shares
the Company’s common stock with an exercise price of $0.01 per share, a term of 2 years until August 3, 2019, and a vesting
period of 2 years. The options have an aggregate fair value of $431,956 that was calculated using the Black-Scholes option-pricing
model. Variables used in the Black-Scholes option-pricing model include: (1) discount rate of 1.34%; (2) expected life of 2 years;
(3) expected volatility of 482.51%; and (4) zero expected dividends.
The
fair value of all options issued and outstanding are being amortized over their respective vesting periods. These options had
an intrinsic value of $367,200 as of May 31, 2018. During the three months ended May 31, 2018, the Company recorded total option
expense of $54,000 related to the vesting of these options. The unrecognized compensation expense on these options at May 31,
2018 was $251,956. As of May 31, 2018, these options have a remaining life of 1.18 years.
Item
2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Cautionary
Notice Regarding Forward Looking Statements
The
information contained in this report contains forward-looking statements within the meaning of Section 27A of the Securities Act
of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Actual results may materially differ
from those indicated in the forward-looking statements as a result of certain risks and uncertainties set forth in this report.
Although the Company’s management believes that the assumptions made and expectations reflected in the forward-looking statements
are reasonable, there is no assurance that the underlying assumptions will, in fact, prove to be correct or that actual results
will not be different from expectations expressed in this report.
This
filing contains a number of forward-looking statements which reflect management’s current views and expectations with respect
to our business, strategies, products, future results and events, and financial performance. All statements made in this filing
other than statements of historical fact, including statements addressing operating performance, events or developments which
management expects or anticipates will or may occur in the future, and non-historical information are forward looking statements.
In particular, the words “believe,” “expect,” “intend,” “anticipate,” “estimate,”
“may,” and variations of those words and similar expressions identify forward-looking statements. The foregoing are
not the exclusive means of identifying forward looking statements, and their absence does not mean that a statement is not forward-looking.
These forward-looking statements are subject to certain risks and uncertainties. Our actual results, performance or achievements
could differ materially from historical results as well as those expressed in, anticipated, or implied by these forward-looking
statements.
Readers
should not place undue reliance on these forward-looking statements, which are based on management’s current expectations
and projections about future events, are not guarantees of future performance, are subject to risks, uncertainties and assumptions
(including those described below), and apply only as of the date of this filing. Factors which could cause or contribute to such
differences include, but are not limited to, the risks discussed in our Annual Report on Form 10-K and in the press releases and
other communications to shareholders issued by us from time to time which attempt to advise interested parties of the risks and
factors which may affect our business. We undertake no obligation to publicly update or revise any forward-looking statements,
whether as a result of new information, future events, or otherwise.
Overview
Norris
Industries, Inc. (“NRIS” or the “Company”) (formerly International Western Petroleum, Inc.) was incorporated
on February 19, 2014, as a Nevada corporation and is headquartered in Irving, Texas. The Company was formed to conduct operations
in the oil and gas industry, and currently focuses on the acquisition, development, and exploration of crude oil and natural gas
properties in Texas. On May 4, 2015, the Company acquired significant working interests from the Bend Arch Lion 1A and the Bend
Arch Lion 1B Joint Ventures in Coleman County of Texas, encompassing a total production of 7 producing oil and gas wells on a
total of 380 acres out of 777-acre leaseholds showing proven recoverable reserves of approximately 416.34 Mbbl and 317.45 MMcf
as of March 1, 2017. We believe that the Bend Arch Lion 1A and 1B Joint Ventures are parts of the total 777-acre leaseholds that
have not been fully explored. In fiscal year 2018, the Company, together with its affiliated operator; International Western Oil
Corporation (“IWO”), have undertaken basic maintenance of the oil and gas wells, with a total of 8 gross wells in
production in the Midland area. The Company also manages the 45-acre Marshall Walden joint venture with 8 Woodbine Sand oil wells
in Kilgore City, Texas, and acquired a 640-acre leasehold with 3 oil wells (non-producing) from the multi-zone Ratliff property
in King County, thus setting a foothold in the Eastern Permian Basin of Texas. The Company, in fiscal year 2018, also purchased
producing oil and gas mineral leases, in the Texas counties of Jack and Palo-Pinto in North Central Western part of Texas. The
lease was for 20 oil & gas wells on 2,790 gross acres with majority working and operating interest with daily production of
50+ barrels of oil equivalent (“BOE”). Currently, NRIS holds approximately 4,200 total gross acres in leaseholds in
various areas of North Central Texas region. The Company plans to acquire additional leaseholds in the future.
The
Company underwent a change of control in July 2017, when Patrick Norris, and his affiliate JBB Partners (“JBB”) acquired
the majority of ownership of the Company and provided loans and equity funding for the oil/gas mineral rights purchases and covering
the operational expenses of Company.
The
Company will, from time to time, seek strategic investors and other funding to help it develop additional exploration and acquisition
projects located within the Bend Arch-Fort Worth Basin and other prime acquisition targets in the Central West, South and East
Texas.
Our
Business Strategy
We
are an Exploration and Production (“E&P”) oil and natural gas company that focuses on the acquisition, development,
and exploration of crude oil and natural gas properties in Texas. The Company is currently managed by business and oil and gas
exploration veterans who specialize in the oil and gas acquisition and exploration markets of the Central West Texas region. The
Company’s goal is to tap into the high potential leases of the Central West Texas region of the United States, aiming to
unlock its potential, specifically in the prolific Bend Arch-Fort Worth region. This area is approximately 120 miles long and
40 miles wide running from Archer County, Texas in the north to Brown County, Texas in the south. The Company is also looking
at other acquisition opportunities in the Permian Basin, West Texas, East Texas and South Texas region.
Management
believes that focusing on the development of existing small producing fields is one of the key differentiators of the Company.
Oil and natural gas reserve development is a technologically oriented industry. Management believes that the use of current technology
has greatly increased the success rate of finding commercial oil or natural gas deposits. In this context, success means the ability
to make an oil/gas well that produces a commercialized quantity of hydrocarbons. In general, the Company expects to conduct 3D
Seismic surveys to determine more accurate drilling locations and drilling depths beside its initial georadiometry technology
application via its last 10 drilling projects. For short-term cash flow enhancement, the Company plans to seek large-reserve oil
and gas properties with low production to acquire at the lowest cost possible and then implement effective Enhanced Oil Recovery
(“EOR”) methods to improve its current revenues and assets. For long-term cash flow enhancement, the Company plans
to identify larger and more mature production opportunities while selecting capital and strategic operating partners to buyout
via the Company’s strategic joint venture partnerships, thus significantly increasing production via additional drilling
and its EOR implementations.
We
plan to execute the following business strategies:
Develop
and Grow Our Hydrocarbon Rich Resource-Style Acreage Positions Using Our Proven Development Expertise
.
We plan to continue
to seek and acquire high quality assets in hydrocarbon-rich resource plays to improve our asset quality and expand our drilling
inventory. We plan to leverage our management team’s expertise and apply the latest available EOR technologies to economically
develop our existing property portfolio in Central West and East Texas in addition to any assets in other regions we may acquire.
We operate the majority of our acreage, thus giving us certain control over the planning of capital expenditures, execution and
cost reduction. Our carefully planned operation also allows us to adjust our capital spending based on drilling results and the
economic environment. Our leasehold acquisition strategy is to pursue long-term contracts that allow us to maintain flexible development
plans and avoid short-term obligations to drill wells, as have been common in other resource plays. As a small producer, we regionally
evaluate industry drilling results and implement technologically effective operating practices which may increase our initial
production rates, ultimate recovery factors and rate of return on invested capital.
Manage
Our Property Portfolio Proactively
.
We constantly evaluate our properties to identify and divest non-core assets and higher
cost or lower volume producing properties with limited developmental potential, thus enabling us to focus on a portfolio of core
properties with the greatest economic potential to increase our proved reserves and production.
Acquire
Small Producing Companies with Compelling Underlying Values
.
We identify acquisition opportunities of exploration and
production companies with underlying assets to unlock the development potential and accelerate production using new technologies
and capital infusion from capital partners.
Maintain
positive equity Balance Sheet to our Execute Growth Plan.
Our management team is focused on maintaining its positive asset
balance sheet since this gives it the ability to increase borrowing capacity and access to capital markets, to provide us with
a liquidity level to execute continued growth in assets and revenues.
Our
operation strategy is to identify “prime time” hydrocarbon land leases in Texas with in-depth studies and develop
proven reserves via drilling new wells and re-entering existing low production wells to maximize production and enhance valuation
of our production assets. We also plan to position the Company by growing our management team with added petroleum experts in
the United States to partner up with other oil and gas players once we have established our business to positive cash flow from
our existing presence in the Texas oil field markets and apply current exploration technology on our new leases.
Our management’s experience in
the petroleum markets and our ability to contract experienced geology expertise, allows us to identify and secure acreage with
high potential reserves. Management believes that the Company’s near future prospects as a public company are attractive,
even if our current business is still small and at a risky stage of transition and development.
Our
Competitive Strengths
Management
believes that we have a number of competitive strengths that will allow us to successfully execute our business strategies:
Simple
Capital Structure.
We have a simple capital structure and de-risked inventory of quality locations with what we believe
is upside potential to take advantage of the current recovery of oil prices to acquire potential production at reasonable cost.
Management believes there are opportunities for profits to be made now that oil prices appear to have stabilized and if they continue
to gradually rise higher.
Visionary
Management Team.
With experience in key aspects of the development of resource plays, our management team includes a 4th
generation oil man and oil field supplier with business skills that have decades of combined experience in the industry and a
commitment of creating shareholder value via an acquisition strategy. We also consult with geologists, engineers, and other professionals
to execute on our business vision.
Low
Risk Exploration Practice.
Unlike many major oil companies that often drill very deep wells with a high degree of risk,
we focus on shallow well exploration (sub 5,000 feet) that is less expensive and has lower risk factors. The basis for management’s
belief that the wells that can be drilled in the prospective leases will have the capacity to produce a reasonable amount of hydrocarbon
and due to our recent studies of the general areas where we are prospecting the projects. That is our most important exploration
practice.
Under
The Radar Asset Base.
Management believes our local West Texas E&P team has a special talent in acquiring local “prime
time” hydrocarbon land leases with sub-300 barrels of oil per day (“bopd”) wells that have large hydrocarbon
reserves. Management believes that these “under the radar” prospective leases have multi-year drilling inventory and
reasonable production history with high upside potential and not readily accessible to the public for auctions, thus adding to
our competitive advantage on these “under the radar” opportunities. It is because management also believes that these
highly valuable leases are not economically justifiable for the major oil and gas companies in the region because such companies
need the wells they drill to produce at least 300 barrels (“Bbls”) of oil per day per well.
Geographic
Diversity.
We believe that our geographic diversity encompassing the West, Central West, East and South Texas regions
provides us with broad flexibility to direct our capital resources to projects with the greatest potential returns and access
to multiple key end markets, which mitigates our exposure to temporary price dislocations in any one market.
Technologies
Oil
and natural gas reserve development is a technologically oriented industry; many techniques developed by the industry are now
used in other industries, including the space program. Management believes that technological innovations have made it possible
for the oil and natural gas industry to furnish the fuels that power the world economy. Management also believes that technology
has greatly increased the success rate of finding commercial oil or natural gas deposits. In this context, success rate means
the ability to make an oil/gas well that can produce a commercialized quantity of hydrocarbon.
Georadiometry
The
use of 3-D Hydrocarbon Imaging brought georadiometric technology into the cutting edge of identifying and quantifying oil reservoirs
and reserves with sophisticated field equipment and software integration abilities that aided explorers in locating oil and gas
leasehold reserves. All specific drilling recommendations and opinions are based upon the technical results of inferences from
global positioning satellites, electrical, and gamma ray devices and calibrated measurements based on georadiometric technology.
3-D Hydrocarbon Imaging rivals conventional seismic and downhole logging for reserve identification. This technology goes beyond
conventional techniques in both arenas of cost and reserve identification and has been leveraged to meet the needs of the industry.
3-D Hydrocarbon Imaging has taken historical radiometric technology to a more complete and reliable level today. Historical documentation
of radiometric’s success ratio and interpretation average above 90% in its accuracy. To date, this radiometry technology
has demonstrated that it has clearly improved on this with its thoroughness in gathering field data and applying its sophisticated
computer modeling and interpretation.
Hydrocarbon
Satellite Imaging
Hydrocarbon
survey maps are generated from several data sources downloaded from scientific instruments installed on Earth orbit satellites.
These instruments are designed to retrieve physical data from outer space as well as from the Earth. Instruments installed on
the satellites include, for our use, Radar, Infrared (Temperature), Radiation (Radiometrics), Dialectic Potential (Tellurics),
Ionization, and Geo-Magnetics. These data sets are stacked and embedded into each data stream that result in the final map interpretation.
All of these exploration techniques can be done separately with land-based tools but with the use of satellites it is possible
to cover much larger areas more economically.
Directional
Drilling
Drilling
technology has come a long way over the years. Among the most recent advancements in drilling are Rotary Steerable tools which
allow three-dimensional control of the bit without stopping the drill string. One of the benefits of this technology is increasing
the exposed section throughout the target reservoir by drilling through it at an angle. Directional drilling also allows drilling
into reservoirs where vertical access is difficult or not possible; for instance, an oilfield under a town, lake, or hard to drill
through formation.
Fracturing
Technology
Fracturing
technology allows the industry to get more oil or natural gas out of each deposit that it finds. Newer stimulation technologies,
completion treatment fluids, and enhanced recovery techniques enable the oil or natural gas to move more easily to producing well
bores. Hydraulic fracturing techniques create small cracks from the well bore into the reservoir rock. A “proppant”
(usually sand), is then pumped into the formation to keep the fractures open. These fractures serve as a “highway”
for the hydrocarbons to be produced. Horizontal-drilling technologies allow the reservoir to be penetrated horizontally rather
than vertically, opening more of the reservoir to the well bore and enhancing recovery. “Acidizing”, is another stimulation
technique that is frequently used in carbonate (limestone, dolomite) reservoirs to increase porosity, permeability and to enhance
recovery. Sometimes the techniques of fracturing and acidizing are combined in an “acid-frac job” resulting in increased
production. Secondary and tertiary recovery techniques can include “water flood” which utilizes water injection wells
to push oil from partially depleted reservoirs to recovery wells. CO2 injection wells pressure up the depleted reservoir for the
same purpose of increasing production.
At
NRIS, we focus on core basic field EOR management practices and contract outside experts to provide us the understanding of complex
mineralogy in shale reservoirs to better determine zones prone to fracture stimulation. This technology can suggest where to frack
by providing us with available data to deliver us a greater chance of success. Our field engineers, geologists and petrophysicists
work together for better drilling decisions.
Sales
Strategy
Abilene,
Texas, is the closest city with oil handling and sales firms. Our sales strategy in relation to spot pricing will be to produce
less when the sales price is lower and produce more when the sales price is higher. To maintain the lowest production cost, we
will aim to have our inventory be virtually zero. Our E&P core team has business relationships with BML, Transport Oil, Lion
Oil Trading & Transportation, for oil sales as well as WTG Jameson for gas sales. The Company entered into production agreements
with BML, Lion Oil and WTG Jameson so that, as our tier 1 buyer, they can handle pick-up and sales of our crude oil stock to refineries
and gas via local gas pipelines.
As
such, crude oil will be picked up from our leases as needed during the calendar month. At the end of the month the crude total
sales will be tallied by lease and the 30-day average of the daily closing of oil will be tabulated. On or about the 25th of the
following month the proceeds checks will be issued to the financial parties of record.
Operational
Plans
During
fiscal year 2018, the Company was in a period of transition as result of our change of control. During this time, we actively
looked for large-reserve oil and gas concessions with existing production to acquire and are now positioned to raise enough capital
via equity or debt financing options to meet our operational goals in fiscal year 2019.
Based
on management’s general management and petroleum exploration experience as well as its geology expertise, the Company believes
it has the ability to identify high potential acreage and high production fields and to secure such.
The
Company has recently shifted its E&P plan on regional acquisition(s) to a focus in the North Texas and Permian Basin region.
This region has been producing oil continuously for nearly 100 years and the U.S. Geological Survey (“USGS”) has recently
announced that this region has the largest estimate of continuous oil production that it has ever assessed. Our area of interest
is production locations in Texas but outside of the Texas Permian Basin market where property prices are too high for a smaller
player as a result of USGS estimates that there are 20 billion barrels of undiscovered, technically recoverable oil.
The
Company has started a new, revised acquisition model which is based on a concept that has been proven in the past to be an effective
and successful path of development for many other well- known E&P players:
|
a)
|
the
financed acquisition of mature smaller oil fields that have potential for instituting
EOR incremental production processes; and
|
|
|
|
|
b)
|
Develop
strategic partnerships with existing operators to share production increases garnered
through the implementation of this EOR plan.
|
Since
the fourth quarter of fiscal year 2018, the Company has reviewed several acquisition candidates in the greater West Permian Basin,
Central and South Texas regions. After identifying any new prospect, additional research and evaluation was carried out using
our personal contacts, geologists, 3D seismic, satellite hydrocarbon imaging, production data and other available resources to
glean information and data in order to make an acquisition decision. Our operational plan after each acquisition is to increase
production of the acquired oil and gas properties using current technologies with a designated budget pre-approved by the Company’s
senior management team. In December 2017, the Company acquired certain leases in Jack County and Palo Pinto County in Texas (discussed
further below).
The
Company has plans to implement a cost effective operating budget for each exploration project associated with our acquisition
project and each budget will vary depending on the total depth of drilling and whether it is a new drilling or a re-entry. For
each project, the Company plans on hiring selected operators to work under the close supervision of a core team of Company geologists,
engineers and scientists.
The
exploration and production process is a two-phase process: 1) drilling and testing and 2) well completion. The Company plans to
hire drilling specialists and technical consultants designated to oversee the drilling and reentering of existing holes for each
well during the drilling and testing phase. For the well completion process, the Company plans to hire technical data collectors
and cementing operators to ensure the best performance upon perforating the wells at different pay zones based on thorough technical
advisory work done by our internal and external production personnel and geologists before production.
The
Company will apply selective leading edge EOR technologies from technology vendors to improve existing production after each future
acquisition.
Completed
Acquisitions with Production Enhancement Programs
To
date, the Company has prospected and completed several exploration and acquisition projects:
The
Bend Arch Lion 1A JV, Coleman County, TX
:
This
drilling joint venture is a 160-acre leasehold having four producing wells which were drilled by our Texas-based operating partner
International Western Oil. This field has been surveyed with high quality proven reserves encompassing several pay zones highlighted
by the Gray Sand, the Palo Pinto, and in some instances the Ellenburger pay zone. On May 4, 2015, the Company acquired a 39.5%
working interest from IWO in the Bend Arch Lion 1A Joint Venture (the Pittard Bend Arch White property encompassing 160 acres
– State ID# 21488) (the “1A Venture”.)
As
of May 31, 2018, the 1A Venture property had four (4) gross oil and gas wells (1.58 net wells). The initial production of this
property started in April 2014.
Management
plans to review and determine how best to implement a production improvement program on several of its wells including the Bend
Arch Lion 1A and others. As a result of recent studies that show accessible proven reserves in several pay zones highlighted by
the Gray Sand and the Ellenburger pay zones, management believes its production improvement program can offer an increase from
the current production of these fields by re-completing certain pay zones with either standard acidizing jobs, a new EOR method,
or reentering and fixing equipment in areas that have become declining wellbores.
The
Bend Arch Lion 1B JV, Coleman County, TX
:
This
drilling joint venture is a 220-acre leasehold having 6 new producing wells which were drilled by our Texas-based operating partner
International Western Oil. In May 2015, the Company acquired working interests of this leasehold which has been surveyed with
high quality proven reserves encompassing several pay zones highlighted by the Gray Sand and in some instances the Ellenburger
pay zone. At the moment, the leasehold has 3 producing wells coming from the Gray Sand formation and 3 producing wells coming
from the Ellenberger formation. On May 4, 2015, the Company acquired a 46% working interest in the Bend Arch Lion 1B Joint Venture
(the Pittard Bend Arch Red property encompassing 220 acres - State ID# 13121) (the “1B Venture”).
As
of May 31, 2018, the 1B Venture property had six (6) gross oil and gas wells (3 net wells). The initial production of this property
started in March 2015.
Management
plans to determine how best to implement a production improvement program on the Bend Arch Lion 1B as the result of our prior
in-depth studies that show accessible proven reserves in several pay zones highlighted by the Gray Sand pay zone and the Ellenburger
pay zone. Management believes this can offer a potential increase from the current production of this field by re-completing certain
Gray Sand pay zone with either standard acidizing jobs or a new EOR method and entering the virgin Gray Sand pay zone or increasing
pumping efficiency in the Ellenburger pay zone in certain declining wellbores.
The
Marshall Walden JV, Kilgore City, TX
:
As
of July 29, 2016, the Company served as the managing venturer in a 45-acre joint venture with Odyssey Enterprises LLC which has
financed the Marshall Walden joint venture for the lease purchase and optimization of wells located in Kilgore, Texas, in the
heart of the Woodbine formation. There are 8 wellbores in the acquisition, with 4 currently in production and 4 inactive. During
the year ended February 28, 2018, the Company completed a re-work of several inactive wellbores and plans to upgrade to a new
pump set up to enhance oil production levels. Management believes that this Marshall Walden acquisition put a solid foundation
in place for the Company in the East Texas region.
As
of May 31, 2018, the Marshall Walden property had six (6) gross oil and gas wells (0.6 net wells) which are active, plus two (2)
injection wells. The initial production of this property started in September 2016.
The
Ratliff Property, King County, TX
:
As
of December 6, 2016, the Company acquired, in a series of payments that totaled $100,000, a 640 acres oil and gas lease and also
3D Seismic data for 340 acres of the leasehold acreage acquired in King County, Texas. This acquisition represented a 100% working
interest with a 70% net revenue interest on leasehold acreage in King County, Texas, with additional options to lease up to 800
acres of adjoining acreage with 3D seismic data. The 640-acre leasehold comes with an existing tank facility for the production
of oil, natural gas, and water. There is also a full injection wellbore set in place that is equipped. There have been five (5)
wellbores drilled on this lease dating back to the 1970s, and these previous wellbores ranged from 4800ft – 6200ft in total
depth, with three (3) different prolific hydrocarbon formations.
Prior
management believed that this acquisition would create an initial small foothold for us in the Eastern Permian Basin. Within depth
studying of the 3D seismic data, we believe there are up to eight (8) proven undeveloped locations (“PUDs”) throughout
the lease’s acreage. Management also believes that the Company can best take full advantage of the complete 3D Seismic data
available and should be able to drill wellbores in favorable locations. The Company plans to drill a test pilot hole in order
to obtain Ellenbuger pay zone samples and complete the Canyon Reef pay zone at 6,700 ft on one wellbore and access a full log
review to determine if there is a window to drill a horizontal leg. The Company also plans to turn on 3 wellbores that are producers
via extended re-entry method. As of February 28, 2018, the Ratliff property had minimal production but had substantial potential
value in several proved developed not producing (“PDNP”) wells based on the Company’s year-end reserve analysis.
The
Stuart Leases of Jack and Palo-Pinto Counties Property
The
Jack Palo-Pinto County Stuart Oil Leases were purchased on December 28, 2017 for $1,600,000 in cash and have twenty (20) gross
oil and gas wells (15 net wells) which the management is operating production on its properties and produced well over 1,500 gross
barrels of oil equivalent since the purchase date until February 28, 2018.
Results
of Operations
Comparison
of the Three Months Ended May 31, 2018 with the Three Months Ended May 31, 2017
Revenues
The
Company generated revenues of $126,072 from oil and gas sales for the three months ended May 31, 2018, as compared to $19,979
for the three months ended May 31, 2017. The increase in revenues mainly came from revenues from the oil and gas properties that
we acquired at the end of fiscal year 2018.
Operating
Expenses
Operating
expenses for the three months ended May 31, 2018 and 2017 were $316,666 and $318,408, respectively. Our lease operating expenses
increased by $66,497, primarily related to the additional lease operating expenses incurred from the oil and gas properties that
we acquired at the end of fiscal year 2018. Our general and administrative expense decreased by $90,484, primarily because we
reduced overhead costs and implemented cost cutting measures. Our depletion, depreciation and accretion expense increased by $22,245,
primarily related to additional production related to the oil and gas properties that we acquired at the end of fiscal year 2018
Other
Income (Expense)
For
the three months ended May 31, 2018 and 2017, the Company recorded interest expense of $11,721 and $3,000 related to outstanding
debts.
Net
Loss
We
had a net loss in the amount of $202,315 for the three months ended May 31, 2018, compared to a net loss of $301,429 for the three
months ended May 31, 2017. The decrease was primarily related to additional revenues from the oil and gas properties that we acquired
at the end of 2018 and cost controls implemented by our new owner.
Liquidity
and Capital Resources
As
of May 31, 2018, the Company had cash in hand of $205,725.
Net
cash used by operating activities during the three months ended May 31, 2018 was $39,272, compared to cash used in operating activities
of $173,676 for the same period in 2017. The decrease was mainly related to us being able to better control our operating expenses
in the current period.
There
was no cash used or provided by financing activities during the three months ended May 31, 2018. Net cash provided by financing
activities during three months ended May 31, 2017 was $204,513. During the three months ended May 31, 2017, we borrowed $200,000
and sold common stock for proceeds of $20,000.
The
Company will seek capital from sources other than its officers and significant stockholders in the future, from time to time.
There is no assurance that it will be able to obtain financing of any amount or of any specific nature. If obtained the terms
may have restrictive covenants or obligations that will be difficult to meet or may be too onerous for the Company to accept.
Any financing accepted by the Company may have a dilutive effect on the outstanding equity of the Company and may restrict the
payment of dividends.
The
Company currently has a secured, convertible note entered into effective December 28, 2017, which is secured by all the assets
of the Company. The note is issued to an affiliate of the Chief Executive Officer of the Company, and the holder of the note is
a controlling majority shareholder of the Company. The existence of the notes, as well as the security interest, may limit the
opportunity to raise financing that requires a security interest or would suffer dilution because of the convertibility of the
notes. Additionally, the note is convertible into shares of common stock of the Company, which if converted will cause a substantial
dilution to the equity of the outstanding Common Stock. On February 26, 2018, the note holder converted its prior note for $750,000,
that was due July 28, 2018, into 1,000,000 Series A Preferred Stock. The note for $1,550,000 was extended to September 30, 2019
from the original due date of December 28, 2018. On June 26, 2018, the Company and JBB entered into a modification of the existing
Secured Promissory Note originally dated December 28, 2017 (“Loan Note”), to add provisions to permit the Company
to obtain advances under the Loan Note up to a maximum of $1,000,000. The Company may request an advance in an amount of $100,000
no more frequently than every 30 days, provided that it provides a description of the use of proceeds for the advance reasonably
acceptable to JBB, and the Company is not otherwise in default of the Loan Note. The original loan amount and the advances are
secured by all the assets of the Company and are convertible into common stock of the Company at the rate of $0.20 per share,
subject to adjustment for any reverse and forward stock splits. The Loan Note may be repaid at any time, without penalty, however,
any advance that is repaid before maturity may not be re-borrowed as a further advance. The maturity date of the original amount
and all the advances is September 30, 2019.
Off-Balance
Sheet Arrangements
As
of May 31, 2018, we did not have any off-balance sheet arrangements as defined in Item 303 (a)(4)(ii) of Regulation S-K promulgated
under the Securities Act of 1934.
