|
|
ITEM 2.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
The following discussion and analysis
should be read in conjunction with our consolidated financial statements and related notes. For the purpose of this discussion,
unless the context indicates another meaning, the terms: “Deep Well,” “Company,” “we,” “us,”
and “our” refer to Deep Well Oil & Gas, Inc. and its subsidiaries. This discussion includes forward-looking statements
that reflect our current views with respect to future events and financial performance that involve risks and uncertainties. Our
actual results, performance or achievements could differ materially from those anticipated in the forward-looking statements as
a result of certain factors including risks discussed in “Cautionary Note Regarding – Forward-Looking Statements”
below and elsewhere in this report, and under the heading “Risk Factors” and “Environmental Laws and Regulations”
disclosed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2018, filed with the Alberta Securities Commission
(“ASC”) on SEDAR on April 12, 2019 and the U.S. Securities and Exchange Commission (“SEC”) on December
21, 2018. Our Annual Report on Form 10-K can be downloaded from our website at
www.deepwelloil.com
.
Our consolidated financial statements
and the supplemental information thereto are reported in United States dollars and are prepared based upon United States generally
accepted accounting principles (“US GAAP”). References in this Form 10-Q to “$” are to United States dollars
and references to “Cdn$” are to Canadian dollars. The following table sets forth the rates of exchange for the Cdn$,
expressed in US dollars, in effect at the end of the following periods and the average rates of exchange during such periods, based
on the rates of exchange for such periods as reported by the Bank of Canada.
|
Period Ending March 31
|
|
2019
|
|
|
2018
|
|
|
Rate at end of period
|
|
$
|
0.7483
|
|
|
$
|
0.7756
|
|
|
Average rate for the three month period
|
|
$
|
0.7522
|
|
|
$
|
0.7910
|
|
General Overview
Deep Well Oil & Gas, Inc., along with
its subsidiaries through which it conducts business, is an independent junior oil sands exploration and development company headquartered
in Edmonton, Alberta, Canada. Our immediate corporate focus is to develop the existing oil sands land base where we have working
interests ranging from 25% to 100% in the Peace River oil sands area of Alberta, Canada. Our principal office is located at Suite
700, 10150 - 100 Street, Edmonton, Alberta, Canada T5J 0P6, our telephone number is (780) 409-8144, and our fax number is (780)
409-8146. Deep Well Oil & Gas, Inc. is a Nevada corporation and trades on the OTC Marketplace under the symbol DWOG. We maintain
a website at www.deepwelloil.com. Our financial statements are available for download on our website or you may download our financial
statements from the U.S. Securities and Exchange Commission’s website at www.sec.gov. The contents of our website are not
part of this quarterly report on Form 10-Q.
Results of Operations
Since the inception of our current business
plan, our operations have consisted of various exploration and start-up activities relating to our properties, including the acquisition
of lease holdings, raising capital, locating joint venture partners, acquiring and analyzing seismic data, complying with environmental
regulations, drilling, testing and analyzing of wells to define our oil sands reservoir, and development planning of our Alberta
Energy Regulatory (“AER”) approved thermal recovery projects, which includes our steam assisted gravity drainage project
where we have a 25% working interest.
The following table sets forth summarized
financial information:
|
|
|
Three Months Ended
|
|
|
Three Months Ended
|
|
|
Six Months Ended
|
|
|
Six Months Ended
|
|
|
|
|
March 31, 2019
|
|
|
March 31, 2018
|
|
|
March 31, 2019
|
|
|
March 31, 2018
|
|
|
Revenue
|
|
$
|
–
|
|
|
$
|
–
|
|
|
$
|
–
|
|
|
$
|
–
|
|
|
Royalty refunds (expenses)
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
Revenue, net of royalty
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
3,820
|
|
|
|
25,127
|
|
|
|
43,480
|
|
|
|
65,557
|
|
|
Operating expense covered by Farmout
|
|
|
(3,820
|
)
|
|
|
(25,127
|
)
|
|
|
(43,480
|
)
|
|
|
(65,557
|
)
|
|
General and administrative
|
|
|
39,566
|
|
|
|
55,505
|
|
|
|
93,421
|
|
|
|
174,865
|
|
|
Depreciation, accretion and depletion
|
|
|
11,411
|
|
|
|
13,050
|
|
|
|
22,853
|
|
|
|
26,075
|
|
|
Net loss from operations
|
|
|
(50,977
|
)
|
|
|
(68,555
|
)
|
|
|
(116,274
|
)
|
|
|
(200,940
|
)
|
|
Other income and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental and other income
|
|
|
20
|
|
|
|
7,050
|
|
|
|
2,066
|
|
|
|
8,864
|
|
|
Interest income
|
|
|
1,923
|
|
|
|
1,465
|
|
|
|
3,733
|
|
|
|
2,901
|
|
|
Net loss and comprehensive loss
|
|
$
|
(49,034
|
)
|
|
$
|
(60,040
|
)
|
|
$
|
(110,475
|
)
|
|
$
|
(189,175
|
)
|
First production from our present joint Steam
Assisted Gravity Drainage Demonstration Project (the “SAGD Project”) began on September 16, 2014. A majority of our
Joint Venture partners voted to temporarily suspend operations of the SAGD Project at the end of February 2016. In accordance
with the Farmout Agreement we entered into on July 31, 2013, the Farmee has agreed to provide up to $40,000,000 in funding for
our portion of the costs for the SAGD Project in return for a net 25% working interest in two oil sands leases where we had a
working interest of 50% before the execution of the Farmout Agreement. The Farmee is also required to provide funding to cover
monthly operating expenses of our Company provided that such funding shall not exceed $30,000 per month. The Farmee shall continue
to cover our administrative costs up to $30,000 per month, under the Farmout Agreement, until completion in all substantial respects
of the SAGD Demonstration Project agreement entered into between us and the operator of the SAGD Project. Our net operating margin
after operating expenses is zero, under the Farmout Agreement, any negative operating cash flows are reimbursed to us to fund
our share of the SAGD Project. Therefore, the total share of the capital costs and operating expenses of our joint SAGD Project,
has been funded in accordance with the Farmout Agreement, at a net cost to our Company of $Nil. As required by the Farmout Agreement,
as of March 31, 2019, the Farmee has since reimbursed our Company and/or paid the operator in total approximately $20.4 million
($27.2 million Cdn) for the Farmee’s share and our share of the capital costs and operating expenses of the SAGD Project.
These costs included the drilling and completion of one SAGD well pair; the purchase and transportation of equipment of which
included the once through steam generator, production tanks, water treatment plant, and power generators; installation and construction
of the steam plant facility; testing and commissioning; the purchase of the water source and disposal wells; construction of pipelines
and expenditures to connect and tie-in the source and disposal water wells to the steam plant facility along with a fuel source
tie-in pipeline; equipment for processing and treating the bitumen production at the SAGD facility site; replacement of the electrical
submersible pump; front end costs for the expansion; the operating expenses associated with the steaming and production of the
one SAGD well pair; and the expenses associated with the monthly shut-in operations of the SAGD Project facility.
For the three months ended March 31, 2019,
our general and administrative expenses decreased by $15,939 compared to the three months ended March 31, 2018, which was primarily
due to decreases of engineering fees and audit fees. We also received $90,000 during this quarter from the Farmee in accordance
with a Farmout Agreement to offset our monthly expenses. After adjusting out the non-cash item foreign exchange loss, and the funds
we received from the Farmee, our general and administrative expenses were $124,751 for the three months ended March 31, 2019 compared
to $136,230 for the three months ended March 31, 2018.
For the six months ended March 31, 2019,
our general and administrative expenses decreased by $81,444 compared to the six months ended March 31, 2018, which was primarily
due to a decrease of engineering fees of $47,428 and a decrease of audit fees of $17,530. We also received $180,000 during the
last six months from the Farmee in accordance with the Farmout Agreement, to offset our monthly expenses. After adjusting out the
non-cash items for share-based compensation and foreign exchange loss, and the funds we received from the Farmee, our general and
administrative expenses were $271,483 for the six months ended March 31, 2019 compared to $343,603 for the six months ended March
31, 2018.
For the three months ended March 31, 2019,
our depreciation, depletion, and accretion expense decreased by $1,639 compared to the three months ended March 31, 2018, which
was primarily due to the depreciating value of our assets. Depreciation expense is computed using the declining balance method
over the estimated useful life of the asset. In compliance with our accounting policy, only half of the depreciation is taken in
the year of acquisition. No significant asset purchases were made in the quarter ended March 31, 2019.
For the six months ended March 31, 2019,
our depreciation and accretion expense decreased by $3,222 compared to the six months ended March 31, 2018, which was primarily
due to the depreciating value of our assets. Depreciation expense is computed using the declining balance method over the estimated
useful life of the asset. In compliance with our accounting policy, only half of the depreciation is taken in the year of acquisition.
No significant depreciable asset purchases were made in the quarter ended March 31, 2019.
For the three months ended March 31, 2019,
rental and other income decreased by $7,030 compared to the three months ended March 31, 2018.
For the six months ended March 31, 2019,
rental and other income decreased by $6,798 compared to the six months ended March 31, 2018.
For the three months ended March 31, 2019,
there were no significant increases or decreases for interest income compared to the three months ended March 31, 2018.
For the six months ended March 31, 2019,
there were no significant increases or decreases for interest income compared to the six months ended March 31, 2018.
As a result of the above transactions,
we recorded a decrease of $11,006 in our net loss and loss from operations for the three months ended March 31, 2019 compared to
the three months ended March 31, 2018.
As a result of the above transactions,
we recorded a decrease of $78,700 in our net loss and loss from operations for the six months ended March 31, 2019 compared to
the six months ended March 31, 2018. As discussed above, this decrease was primarily due to decreases in engineering and audit
fees.
Operations
The first SAGD well pair, for the SAGD
Project, was drilled to a vertical depth of approximately 650 meters with a horizontal length of 780 meters each. Steam injection
commenced in May 2014 and production started in September of 2014. Production from this one SAGD well pair increased significantly
over the 18-month period it produced. Over January and February of 2016 production from the SAGD Project averaged 615 bopd, on
a 100% basis (154 bopd net to us), with an average SOR of 2.1 from one SAGD well pair. The SOR is reflective of the amount of steam
needed to produce one barrel of oil. This SAGD Project was temporarily suspended at the end of February 2016. The capital costs
of the existing SAGD Project steam plant facility, with pipelines and one SAGD well was approximately $26.5 million (Cdn $34.8
million) on a 100% working interest basis, of which our share is covered under the Farmout Agreement. These capital costs do not
include the start-up operating expenses to initiate oil production from the SAGD well pair.
The current SAGD Project has:
|
|
●
|
confirmed that the SAGD process works in the Bluesky formation at Sawn Lake;
|
|
|
●
|
established characteristics of ramp up through stabilization of SAGD performance;
|
|
|
●
|
indicated the productive capability and SOR of the reservoir; and
|
|
|
●
|
provided critical information required for well and facility design associated with future commercial
development.
|
The following graph sets out the production
levels that the SAGD Project achieved. These production numbers along with the corresponding SORs compare favorably to analogous
reservoirs in thermal recovery projects that we are monitoring and using as a basis of comparison.
It is anticipated that a reactivation of
the existing SAGD Project facility and current SAGD well pair will be part of a potential commercial expansion. In early May of
2016, an amended application was submitted to the AER for an expansion of the existing SAGD Project facility site which would potentially
increase the operation for up to a total of eight SAGD well pairs. This expansion application sought approval to expand the current
SAGD Project facility site to 3,200 bopd (100% basis). It is anticipated that only five SAGD well pairs will need to be operating
to achieve this production level. The expanded facility will be designed to handle up to 3,200 bopd. The AER approval for this
expansion of our existing SAGD Project was granted in December of 2017. While the joint venture has not yet approved to expand
the SAGD Project facility, currently the SAGD Project continues to move forward with engineering and identification of long lead
time items towards potential expansion to 3,200 bopd and future commercial development at Sawn Lake.
In August of 2017, we jointly participated
in drilling one well on our Sawn Lake properties. This well was drilled to a total depth of 681 meters.
On February 15, 2018, we entered into a
contribution agreement with a third-party, whereby we paid a cash contribution to drill and acquire cores and logs through the
Bluesky formation from a well drilled by a third-party on one of our oil sands leases.
In August 2013, we received approval from
the AER for our horizontal cyclic steam stimulation project (“HCSS Project”) application. It is anticipated that we
will develop a thermal demonstration project on our properties followed by a commercial expansion project on one half section of
land located on section 10-92-13W5 of our Sawn Lake oil sands properties where we currently have a 90% working interest. The final
performance results and revised reservoir modeling studies from our SAGD Project are being used to fine-tune our HCSS Project facility
design before we initiate start-up operations on the half of a section of land where we plan to drill two horizontal wells to test
the use of HCSS technology. We performed an environmental field study and surveyed the proposed location of our planned HCSS Project
site and received AER approval for the surface wellsite and access road for our HCSS Project.
Our oil sands acreage as of
March 31, 2019, covers 36,689 gross acres (28,814 net acres) of land under nine oil sands leases. Subsequently, in mid-April 2019,
Alberta Energy completed their review and final approval of one section within one of our continuation applications, which received
approval to continue another 633 gross acres (569 net acres). Until our Company extends its oil sands leases “into perpetuity”,
based on the Alberta governmental regulations, the lease expiration dates of our nine oil sands leases are as follows:
|
|
1.
|
20,242 gross acres (13,284 net acres) under five oil
sands leases were set to expiry on July 10, 2018. In November of 2017, our joint venture partner and operator of two of the five
oil sands leases, submitted two continuation applications to the Alberta Oil Sands Tenure division to apply to continue 7,591
gross acres (1,898 net acres) and on January 29, 2018, approval was received from Alberta Energy to continue 6,958 gross acres
(1,740 net acres). In June of 2018, our Company as operator of three of these five oil sands leases, submitted three continuation
applications to the Alberta Oil Sands Tenure division to apply to continue another 7,591 gross acres (6,832 net acres) where resources
were identified. In mid-July 2018, two of our continuation applications received approval from Alberta Energy to continue 5,693
gross acres (5,124 net acres). Subsequently as of mid-April 2019, one more of our continuation applications received final approval
from Alberta Energy to continue a total of 1,898 gross acres (1,708 net acres). Subsequently as of mid-April 2019, of these five
oil sands leases that were set to expiry on July 10, 2018, a total of 5,693 gross acres (4,713 net acres) expired without being
continued. These expired lands were primarily areas where our Company determined that there was no or limited exploitable resources.
Subsequently as of mid-April 2019, of these five oil sands leases 14,549 gross acres (8,571 net acres) have been approved by Alberta
Energy to be continued beyond the original expiry date of July 10, 2018. These continued leases have no future expiry dates but
are subject to yearly escalating rental payments until they are deemed to be producing leases;
|
|
|
2.
|
19,610 gross acres (17,649 net acres) under three
northern oil sands leases are set to expire on August 19, 2019. We intend to apply for a term extension on these three northern
oil sands leases, however it is not certain if an extension will be granted by Alberta Energy; and
|
|
|
3.
|
3,163 gross acres (3,163 net acres) under one oil
sands lease are set to expire on April 9, 2024. We believe that we have already met the governmental requirements for this lease
and we currently intend to apply to continue this lease into perpetuity.
|
The development progress of our properties
is governed by several factors such as federal and provincial governmental regulations. Long lead times in getting regulatory approval
for thermal recovery projects are commonplace in our industry. Road bans, winter access only roads and environmental regulations
can, and often, do delay development of similar projects. Because of these and other factors, our oil sands project could take
significantly longer to complete than regular conventional drilling programs for lighter oil.
Liquidity and Capital Resources
As of March 31, 2019, our total assets
were $22,701,537 compared to $22,827,332 as of September 30, 2018.
Our total liabilities as of March 31, 2019
were $508,284 compared to $538,604 as of September 30, 2018. There was no significant change in our total liabilities from the
September 30, 2018 year end.
Our working capital (current liabilities
subtracted from current assets) is as follows:
|
|
|
Six months Ended
|
|
|
Year Ended
|
|
|
|
|
March 31, 2019
|
|
|
September 30, 2018
|
|
|
Current Assets
|
|
$
|
209,162
|
|
|
|
363,891
|
|
|
Current Liabilities
|
|
|
21,337
|
|
|
|
45,137
|
|
|
Working Capital
|
|
$
|
187,825
|
|
|
|
318,754
|
|
As of March 31, 2019,
we had working capital of $187,825 compared to a working capital of $318,754 as of September 30, 2018. This decrease of $130,929
is primarily due to general and administrative expenses.
As reported on our condensed Consolidated
Statement of Cash Flows under “Operating Activities”, for the six months ended March 31, 2019, our net cash used in
operating activities was $150,711 compared to $246,042 for the six months ended March 31, 2018. This decrease of $95,331 in our
operating activities was due to a decrease in general and administrative expenses.
As reported on our condensed Consolidated
Statement of Cash Flows under “Investing Activities”, we had a decrease of $450,504 on investment in our oil and gas
properties for the six months ended March 31, 2019, compared to the six months ended March 31, 2018. This decrease was due to the
cash contribution of $395,500 ($500,000 Cdn) paid to a third-party operator in February of 2018, who was drilling into a deeper
formation, to drill and acquire cores and logs through the Bluesky formation on one of our oil sands leases.
As reported on our condensed Consolidated
Statement of Cash Flows under “Financing Activities”, for the six months ended March 31, 2019 and March 31, 2018, we
had an increase of $15,000 compared to the six months ended March 31, 2018, which was a payment received from one of our director’s
for the exercise of his stock options.
Our cash and cash equivalents as of March
31, 2019 was $104,223 compared to $342,184 as of March 31, 2018. This decrease of $237,961 in cash was primarily due to in general
and administrative expenses.
As of March 31, 2019,
we had no long-term debt other than our estimated future asset retirement obligations on oil and gas properties.
Our current SAGD Project operating costs
are covered by the Farmout Agreement. For our long-term operations, we anticipate that, among other alternatives, we may raise
funds during the next twenty-four months through sales of our equity securities, debt, or entering into another form of joint venture.
We also note that if we issue more shares of our common stock, our stockholders will experience dilution in the percentage of their
ownership of common stock. We may not be able to raise sufficient funding from stock sales for long-term operations and if so,
we may be forced to delay our business plans until adequate funding is obtained.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Cautionary Note Regarding Forward-Looking
Statements
This quarterly report on Form 10-Q, including
all referenced Exhibits, contains “forward-looking statements” within the meaning of the United States federal securities
laws. All statements other than statements of historical facts included or incorporated by reference in this report, including,
without limitation, statements regarding our future financial position, business strategy, projected costs and plans and objectives
of management for future operations, are forward-looking statements. The words “may,” “believe,” “intend,”
“will,” “anticipate,” “expect,” “estimate,” “project,” “future,”
“plan,” “strategy,” “probable,” “possible,” or “continue,” and other
expressions that are predictions of or indicate future events and trends and that do not relate to historical matters, often identify
forward-looking statements. For these statements, Deep Well claims the protection of the safe harbor for forward-looking statements
contained in the Private Securities Litigation Reform Act of 1995. The forward-looking statements in this quarterly report include,
among others, statements with respect to:
|
|
●
|
our current business strategy;
|
|
|
●
|
our future financial position and projected costs;
|
|
|
●
|
our projected sources and uses of cash;
|
|
|
●
|
our plan for future development and operations, including the building of all-weather roads;
|
|
|
●
|
our drilling and testing plans;
|
|
|
●
|
our proposed plans for further thermal in-situ development or demonstration project or projects;
|
|
|
●
|
the sufficiency of our capital in order to execute our business plan;
|
|
|
●
|
our reserves and resources estimates;
|
|
|
●
|
the timing and sources of our future funding;
|
|
|
●
|
the quantity and value of our reserves;
|
|
|
●
|
the intent to issue a distribution to our shareholders;
|
|
|
●
|
our or our operator’s objectives and plans for our current SAGD Project;
|
|
|
●
|
our plans for development of our Sawn Lake properties;
|
|
|
●
|
production levels from our current SAGD Project;
|
|
|
●
|
costs of our current SAGD Project;
|
|
|
●
|
funding from the Farmee to pay our costs for the current SAGD project in connection with the Farmout Agreement;
|
|
|
●
|
additional sources of funding from the Farmout Agreement;
|
|
|
●
|
funding from the Farmee to cover our monthly operating expenses;
|
|
|
●
|
our access and availability to third-party infrastructure;
|
|
|
●
|
present and future production of our properties;
|
|
|
●
|
our intention to apply to extend our leases; and
|
|
|
●
|
expectations regarding the ability of our Company and its subsidiaries to raise capital and to
continually add to reserves through acquisitions and development.
|
These forward-looking statements are based
on the beliefs and expectations of our management and are subject to significant risks and uncertainties. If underlying assumptions
prove inaccurate or unknown risks or uncertainties materialize, actual results may differ materially from current expectations
and projections. Factors that could cause actual results to differ materially from those set forward in the forward-looking statements
include, but are not limited to:
|
|
●
|
changes in general business or economic conditions;
|
|
|
●
|
changes in governmental legislation or regulation that affect our business;
|
|
|
●
|
our ability to obtain necessary regulatory approvals and permits for the development of our properties, including obtaining
the required water licences from Alberta Environment to withdraw water for our thermal operations;
|
|
|
●
|
changes to the greenhouse gas reduction program and other environmental and climate change regulations which are adopted by
provincial or federal governments of Canada or which are being considered, which may also include cap and trade regimes, carbon
taxes, increased efficiency standards, each of which could increase compliance costs and impose significant penalties for non-compliance;
|
|
|
●
|
increase in taxes and changes to existing legislation affecting governmental royalties or other governmental initiatives;
|
|
|
●
|
future marketing and transportation of our produced bitumen;
|
|
|
●
|
our ability to receive approvals from the AER for additional tests to further evaluate the wells on our lands;
|
|
|
●
|
our Farmout Agreement and joint operating agreements;
|
|
|
●
|
opposition to our regulatory requests by various third parties;
|
|
|
●
|
actions of aboriginals, environmental activists and other industrial disturbances;
|
|
|
●
|
the costs of environmental reclamation of our lands;
|
|
|
●
|
availability of labor or materials or increases in their costs;
|
|
|
●
|
the availability of sufficient capital to finance our business or development plans on terms satisfactory to us;
|
|
|
●
|
adverse weather conditions and natural disasters affecting access to our properties and well sites;
|
|
|
●
|
risks associated with increased insurance costs or unavailability of adequate coverage;
|
|
|
●
|
volatility in market prices for oil, bitumen, natural gas, diluent and natural gas liquids. A decline
in oil prices could result in a downward revision of our future reserves and a ceiling test write-down of the carrying value of
our oil sands properties, which could be substantial and could negatively impact our future net income and stockholders’
equity;
|
|
|
●
|
changes in labor, equipment and capital costs;
|
|
|
●
|
future acquisitions or strategic partnerships;
|
|
|
●
|
the risks and costs inherent in litigation;
|
|
|
●
|
imprecision in estimates of reserves, resources and recoverable quantities of oil, bitumen and natural gas;
|
|
|
●
|
product supply and demand;
|
|
|
●
|
changes and amendments in the Canadian Oil and Gas Evaluation Handbook and or the Petroleum Resources
Management System to general disclosure of reserves and resources standards and specific annual reserves and resources disclosure
requirements for reporting issuers with oil and gas activities;
|
|
|
●
|
future appraisal of potential bitumen, oil and gas properties may involve unprofitable efforts;
|
|
|
●
|
the ability to meet minimum level of requirements and obtain approval from Alberta Energy to continue
our oil sands leases beyond their expiry dates;
|
|
|
●
|
the ability to pay future escalating lease rents on continued leases;
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changes in general business or economic conditions;
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risks associated with the finding, determination, evaluation, assessment and measurement of bitumen,
oil and gas deposits or reserves;
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geological, technical, drilling and processing problems;
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third party performance of obligations under contractual arrangements;
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failure to obtain industry partner and other third-party consents and approvals, when required;
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treatment under governmental regulatory regimes and tax laws;
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royalties payable in respect of bitumen, oil and gas production;
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unanticipated operating events which can reduce production or cause production to be shut-in or delayed;
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incorrect assessments of the value of acquisitions, and exploration and development programs;
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stock market volatility and market valuation of the common shares of our Company;
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fluctuations in currency and interest rates; and
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the additional risks and uncertainties, many of which are beyond our control, referred to elsewhere
in this quarterly report and in our other SEC filings.
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The preceding bullets outline some of the
risks and uncertainties that may affect our forward-looking statements. For a full description of risks and uncertainties, see
the sections entitled “Risk Factors” and “Environmental Laws and Regulations” of our annual report on Form
10-K for the fiscal year ended September 30, 2018 filed with the ASC on SEDAR on April 12, 2019 and the SEC on December 21, 2018.
Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results
may vary materially from those anticipated, believed, estimated or expected. Any forward-looking statement speaks only as of the
date on which it was made and, except as required by law, we disclaim any obligation to publicly update any forward-looking statements,
whether as a result of new information, future events or otherwise. However, any further disclosures made on related subjects in
subsequent reports on Forms 10-K, 10-Q, 8-K and any other SEC filing or amendments thereto should be consulted.