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, 2019, filed with the U.S. Securities and
Exchange Commission ("SEC") and the Alberta Securities Commission ("ASC") on
SEDAR on January 13, 2020. 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
quarterly report on Form 10-Q to "$" are to United States ("US") dollars and
references to "Cdn$" 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                      2020         2019
Rate at end of period                     $ 0.7049     $ 0.7483

Average rate for the three month period $ 0.7443 $ 0.7522






General Overview



Deep Well Oil & Gas, Inc., through its subsidiaries conducts business, as an
independent junior oil sands exploration and development company. Its
subsidiaries are headquartered in Edmonton, Alberta, Canada. Our immediate
corporate focus is to develop the existing oil sands land base where our
subsidiaries have working interests ranging from 25% to 100% in the Peace River
oil sands area of Alberta, Canada. 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
SEC's website at www.sec.gov. The contents of our website are not part of this
quarterly report on Form 10-Q.



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 joint
Steam Assisted Gravity Drainage Demonstration Project (the "SAGD Project") where
we have a 25% working interest.



Our main objective is to develop our oil sands lease holdings located in the
Peace River oil sands area of North Central Alberta, Canada (also known as our
Sawn Lake oil sands properties) using thermal recovery technologies. We have
received approval from the AER for two thermal recovery projects located on

our
Sawn Lake properties.



                                       14






A SAGD Project on our Sawn Lake properties commenced in 2013 where we have a 25%
working interest. The SAGD Project consists of one SAGD well pair drilled to a
depth of 650 meters and a horizontal length of 780 meters and the SAGD facility
for steam generation, water handling, and bitumen treating. Steam injection
commenced in May 2014 and production started in September of 2014. The SAGD
Project reached a steady state production level in February of 2016 of 620 bopd,
on a 100% basis (155 bopd net to us) from one SAGD well pair and achieved an
instantaneous Steam oil Ratio ("ISOR") efficiency of 2.1, demonstrating the
productive capability of our Sawn Lake reservoir. The lower the ISOR the lower
the production costs and emissions per barrel of oil produced. A majority of our
Company's Joint Venture partners voted to temporarily suspend operations for the
SAGD Project at the end of February 2016. As 2021 and 2022 proceed, the operator
of the SAGD Project should be consulting with its joint venture partners
regarding development potential and alternatives for the SAGD Project.



The 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 ISOR of the reservoir; and

? provided critical information required for well and facility design associated


    with future commercial development.




The production results of the SAGD Project successfully confirmed the capability
of the Bluesky reservoir to produce using thermal recovery technology. The
following graph sets out the production levels that the SAGD Project achieved.
These production numbers compare favorably to analogous reservoirs in thermal
recovery projects that we are monitoring and using as a basis of comparison.



                               [[Image Removed]]



                                       15






An amended application was submitted to the AER for a commercial expansion of
the existing SAGD Project facility site and received regulatory approval in
December 2017. This expansion application sought approval to expand the current
SAGD Project facility site to produce up 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 SAGD Project development plan will be done in stages
to reduce initial financial costs. The first stage anticipates the reactivation
of the existing SAGD facility and existing SAGD well pair, along with the
drilling of one additional SAGD well pair, initially producing from two SAGD
well pairs. The second stage anticipates drilling an additional three SAGD well
pairs to produce up to 3,200 bopd and the expansion of the existing SAGD
facility to generate the additional steam required. The lead time to acquiring
the necessary equipment and commencing operations is estimated to be about 18
months and another 6 months is required for the start of bitumen production
(after development of the steam chamber). We anticipate our near- and or
long-term funding of our operations to be financed through the existing Farmout
Agreement, future earn-in agreements, and cash flow from the reactivation of the
existing SAGD Project. We also intend to negotiate in the future with the
Petroleum and Natural Gas holders in the area of our leases, to enter into
further downhole contribution agreements to acquire additional logs and cores of
the Bluesky formation, in order to expand the boundaries of the oil sands
reservoir we have already defined and save on drilling costs and reduce our
environmental footprint. A Sawn Lake full field development plan using SAGD
batteries has been defined for the SAGD Project.



Under Full Cost accounting we assess our unproved properties for impairment
annually. Management takes a longer-term approach to the commodity price because
of the long life of the Company's oil sands assets, that being 30, 40, or even
over, 50 years. The significant decline in oil prices may have an impact on the
Company's annual impairment assessment of its unproven Sawn Lake properties,
whereby we may have to impair some or all of our unproven properties on our
balance sheet when we preform our yearly assessment of our unproved properties
for impairment. However, management feels that any impairment decision must take
in to account the relatively long-term life of the Company's assets.



We previously received approval from the AER for a 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 at
least a 90% working interest. The final performance results and revised
reservoir modeling studies from our SAGD Project will be 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 previously 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 this HCSS Project.



Our Company to date has, but not limited to, drilled or participated in 13 wells
over our Sawn Lake leases to expand the boundaries of the Bluesky oil sands
reservoir; commissioned various independent reservoir simulation studies of our
properties; successfully produced bitumen from the SAGD Project, which
outperformed independent reservoir production type curves; acquired AER approval
for two thermal recovery projects, which includes our joint SAGD Project
facility expansion to produce up to 3,200 bopd; successfully entered into
Farmout Agreements; and we have successfully applied and received approval from
the AER to continue the best sections of our oil sands properties past their
initial lease expiry dates, where resources were identified. Currently, our
Company's Sawn Lake oil sands properties under lease covers 17,712 gross acres
(11,734 net acres) of land under six oil sands leases. The lease expiration
dates of our Company's oil sands leases are as follows:

1. Five oil sands leases covering 14,549 gross acres (8,571 net acres) were

continued under the Alberta Oil Sands Tenure division and are now held by our

Company into perpetuity and are subject to yearly escalating rental payments

until they are deemed to be producing leases.

2. One oil sands lease covering 3,163 gross acres (3,163 net acres) are set to

expire on April 9, 2024. The Company will be applying to continue this lease


   into perpetuity.




                                       16






The development progress of our Sawn Lake oil sands 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 and our projects. Because of these and other factors, our oil sands
projects can take significantly longer to complete than regular conventional
drilling programs for lighter oil.



Results of Operations



Our Company's independent auditor has not performed a review of our quarterly
condensed consolidated financial statements for the period ending March 31,
2020, in accordance with standards established by the Public Company Accounting
Oversight Board (United States) ("PCAOB") for a review of quarterly financial
statements by an entity's auditor. The accompanying unreviewed quarterly
condensed consolidated financial statements of our Company for the period ending
March 31, 2020 have been prepared by our inhouse Company accounting and other
staff but are the responsibility of our Company's management.

The following table sets forth summarized financial information:





                                            Three Months       Three Months        Six Months        Six Months
                                               Ended              Ended               Ended             Ended
                                             March 31,          March 31,           March 31,         March 31,
                                                2020               2019               2020              2019
                                                                 (Auditor                             (Auditor
                                            (Unreviewed)        Reviewed)         (Unreviewed)        Reviewed)
Revenue                                    $            -     $            -     $             -     $         -
Royalty refunds (expenses)                              -                  -                   -               -
Revenue, net of royalty                                 -                  -                   -               -
Expenses
Operating expenses                                 11,197              3,820              38,935          43,480
Operating expense covered by Farmout              (11,197 )           (3,820 )           (38,935 )       (43,480 )
General and administrative                         40,324             39,566              70,645          93,421
Depreciation, accretion and depletion              10,760             11,411              21,603          22,853
Net loss from operations                          (51,084 )          (50,977 )           (92,248 )      (116,274 )
Other income and expenses
Rental and other income                                38                 20              (2,009 )         2,066
Interest income                                     1,960              1,923               3,954           3,733
Net loss                                   $      (49,086 )   $      (49,034 )   $       (90,303 )   $  (110,475 )
There was no production volumes or revenues for the years ending March 31, 2020
and 2019, due to a majority of our Company's Joint Venture partners voting 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. Under the terms of the Farmout Agreement the Farmee is
required to provide funding to cover the monthly administrative expenses of our
Company provided that such funding shall not exceed $30,000 per month. Under the
terms of the Farmout Agreement, the Farmee is to continue to cover our Company's
administrative costs up to $30,000 per month until completion in all substantial
respects of the SAGD Project agreement entered into between the Company and the
operator of the SAGD Project. Since March of 2020, the Farmee has been
delinquent in making its monthly payments in full to us. Currently the Farmee
has only been paying about half of the $30,000 per month payments to us. To date
the Farmee owes us approximately $345,000 in reimbursement of administrative
costs as required by the Farmout Agreement. 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
Company's 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, 2020, the Farmee has reimbursed our Company and/or
paid the operator up to a total of approximately Cdn$27.4 million, which
depending upon the exchange rates used over time could presently be
approximately $19.3 million USD, 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 when the facility was producing; and the expenses
associated the monthly shut-in operations of the SAGD Project facility.



                                       17





For the three months ended March 31, 2020, our general and administrative
expenses increased by $758 compared to the three months ended March 31, 2019. We
also accrued $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 and the funds we accrued from the Farmee, our
general and administrative expenses were $132,558 for the three months ended
March 31, 2020 compared to $124,751 for the three months ended March 31, 2019.



For the six months ended March 31, 2020, our general and administrative expenses
decreased by $22,776 compared to the six months ended March 31, 2019, which was
primarily due to decreases in office rent and other general and administrative
expenses. We also accrued $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 foreign exchange and the funds we received
from the Farmee, our general and administrative expenses were $252,201 for the
six months ended March 31, 2020 compared to $271,483 for the six months ended
March 31, 2019.




For the three months ended March 31, 2020, our depreciation, depletion, and
accretion expense decreased by $651 compared to the three months ended March 31,
2019, 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, 2020.



For the six months ended March 31, 2020, our depreciation and accretion expense
decreased by $1,250 compared to the six months ended March 31, 2019, 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, 2020.

For the three months ended March 31, 2020, there were no significant increases or decreases for rental and other income compared to the three months ended March 31, 2019.

For the six months ended March 31, 2020, rental and other income decreased by $4,075 compared to the six months ended March 31, 2019.





For the three months ended March 31, 2020, there were no significant increases
or decreases for interest income compared to the three months ended March 31,
2019.

For the six months ended March 31, 2020, there were no significant increases or decreases for interest income compared to the six months ended March 31, 2019.

As a result of the above transactions, there was no significant increase or decrease in our net loss and loss from operations for the three months ended March 31, 2020 compared to the three months ended March 31, 2019.


As a result of the above transactions, we recorded a decrease of $20,172 in our
net loss and loss from operations for the six months ended March 31, 2020
compared to the six months ended March 31, 2019. As discussed above, this
decrease was primarily due to decreases in office rent and other general and
administrative expenses.



                                       18

Liquidity and Capital Resources





As of March 31, 2020, our total assets were $22,611,906 compared to $22,677,977
as of September 30, 2019. There was a decrease of $66,071 in our total assets
from the September 30, 2019 year end, which was primarily due to a decrease

of
$38,599 in cash.



Our total liabilities as of March 31, 2020 were $595,616 compared to $571,384 as
of September 30, 2019. There was a $24,232 increase in our total liabilities
from the September 30, 2019 year end, which was primarily due to an increase in
accounts payable.



Our working capital (current liabilities subtracted from current assets) is as
follows:



                      Six months Ended        Year Ended
                          March 31,          September 30,
                            2020                 2019
Current Assets        $         124,004             167,379
Current Liabilities             119,755              70,992
Working Capital       $           4,249              96,387




As of March 31, 2020, we had working capital of $4,249 compared to a working
capital of $96,387 as of September 30, 2019. This decrease of $92,138 in working
capital is primarily due to cash used for general and administrative expenses
and an increase of $48,763 in current liabilities.



As reported on our condensed Consolidated Statement of Cash Flows under
"Operating Activities", for the six months ended March 31, 2020, our net cash
used in operating activities was $15,161 compared to $150,711 for the six months
ended March 31, 2019. This decrease of $135,550 in our operating activities was
due to a decrease of $18,922 for general and administrative expenses and a
decrease of $116,628 from changes in non-cash working capital.



As reported on our condensed Consolidated Statement of Cash Flows under
"Investing Activities", we had a decrease of $34,322 on investment in our oil
and gas properties for the six months ended March 31, 2020, compared to the six
months ended March 31, 2019.



As reported on our condensed Consolidated Statement of Cash Flows under
"Financing Activities", for the six months ended March 31, 2020 and March 31,
2019. There were no financing activities for the six months ended March 31,

2020
period.

Our cash and cash equivalents as of March 31, 2020 was $11,116 compared to $104,223 as of March 31, 2019. This decrease of $93,107 in cash was primarily due to cash used in general and administrative expenses.


Our current SAGD Project capital and operating costs are covered under the terms
of the Farmout Agreement. In addition, as described above 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. 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
shareholders 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





There is no transaction, arrangement, or other relationship between our Company
or any of our subsidiaries and an unconsolidated or affiliated entity that is
not reflected on our Company's Financial Statements that is required to be
disclosed by our Company in our SEC filings and is not already disclosed.



                                       19

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 administrative operating
    expenses;

  ? our access and availability to third-party infrastructure;




  ? present and future production of our properties;

? our ability to extend our remaining lease; past its primary expiration date;

and

? expectations regarding the ability of our Company and its subsidiaries to

raise capital and to continually add to reserves through acquisitions and


    development.




                                       20






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 licenses

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;

  ? proximity and capacity of oil and natural gas pipelines and other
    transportation facilities;

? 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 shareholders' equity;

  ? competition;

  ? changes in labor, equipment and capital costs;

  ? future acquisitions or strategic partnerships;

  ? the risks and costs inherent in litigation;




                                       21

? 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 obtain approval from the AER to continue our remaining oil

sands lease beyond its expiry date;

? the ability to pay future escalating oil sands lease rents on our continued

leases;

? our ability to meet the minimum level of production requirements on our oil

sands leases as set out by the AER in order to eliminate future escalating oil


    sands lease rents on our continued leases;

  ? changes in general business or economic conditions;

? risks associated with the finding, determination, evaluation, assessment and


    measurement of bitumen, oil and gas deposits or reserves;

  ? geological, technical, drilling and processing problems;




  ? third party performance of obligations under contractual arrangements;

  ? failure to obtain industry partner and other third-party consents and
    approvals, when required;

  ? treatment under governmental regulatory regimes and tax laws;

  ? royalties payable in respect of bitumen, oil and gas production;

? unanticipated operating events which can reduce production or cause production


    to be shut-in or delayed;

  ? incorrect assessments of the value of acquisitions, and exploration and
    development programs;

? stock market volatility and market valuation of the common shares of our

Company;

? changes or amendments to the U.S. Securities Exchange Acts that may have an

impact on the over-the-counter ("OTC") market where our common shares are

publicly traded, of which changes or amendments such as Rule 15c2-11 which may

affect whether or not our common shares will continue to be publicly traded on


    the OTC Market or downgraded to the Grey Market;

  ? fluctuations in currency and interest rates;




  ? the potential negative impact of public health epidemics and outbreaks,
    including COVID-19, on our Company, our operations, our employees, our

contractors, our suppliers, our joint venture partners and the global economy;

and

? 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.


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, 2019 filed with the SEC and the ASC on SEDAR on January 13, 2020.
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.



                                       22

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