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" as disclosed in our Annual Report on Form
10-K filed the U.S. Securities and Exchange Commission ("SEC"). 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 ("U.S. GAAP"). References in this
Annual Report on Form 10-K to "$" are to United States dollars and references to
"Cdn$" are to Canadian dollars. On September 24, 2021, the daily rate of
exchange for Cdn$, expressed in US$ was Cdn$1.00 = US$0.7886 as reported by the
Bank of Canada.
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 we 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 U.S. Securities
and Exchange Commission's website at www.sec.gov. The contents of our website
are not part of this Annual Report on Form 10-K for the fiscal year ended
September 30, 2020.
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.
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.
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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]]
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 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 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 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 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 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 3200 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 cover 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.
15
2. One oil sands lease covering 3,163 gross acres (3,163 net acres) are set to
expire on April 9, 2024. It is our Company's opinion that we have already met
the governmental requirements for this lease, and we will be applying to
continue this lease into perpetuity.
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 an audit of our consolidated
financial statements for the year ended September 30, 2020, in accordance with
standards established by the Public Company Accounting Oversight Board (United
States) ("PCAOB") for an audit of annual financial statements by an entity's
auditor. The accompanying unaudited consolidated financial statements of our
Company for the year ended September 30, 2020, have been prepared in-house by
our Company and are the responsibility of our Company's management.
The following table sets forth summarized financial information:
September 30, September 30,
2020 2019
Unaudited Audited
Revenue $ - $ -
Provincial royalty expenses - -
Revenue, net of royalty - -
Expenses
Operating expenses 93,299 97,643
Operating expense covered by Farmout (93,299 ) (97,643 )
General and administrative 124,688 165,405
Depreciation, accretion and depletion 43,026 46,036
Net loss from operations (167,714 ) (211,441 )
Other income and expenses
Rental and other income 59,237 6,612
Interest income 5,175 7,694
Net loss $ (103,302 ) $ (197,135 )
There was no production volumes or revenues for the fiscal years ending
September 30, 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. The Farmee shall 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 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 September 30, 2020, the Farmee has
reimbursed our Company and/or paid the operator up to a total of approximately
Cdn$27.5 million, which depending upon the exchange rates used over time could
presently be approximately $20.6 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.
16
For the year ended September 30, 2020, our general and administrative expenses
decreased by $40,717 compared to the year ended September 30, 2019, which was
primarily due to decreases in office rent and other general and administrative
expenses. We also accrued $360,000 during the current fiscal year from the
Farmee in accordance with a 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 $477,560
for the year ended September 30, 2020 compared to $523,117 for the year ended
September 30, 2019.
For the year ended September 30, 2020, our depreciation, depletion and accretion
expense decreased by $3,010 compared to the year ended September 30, 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 year ended September 30, 2020.
For the year ended September 30, 2020, our rental and other income increased by
$52,625 compared to the year ended September 30, 2019, which was primarily due
to the income we received from COVID-19 supports granted from the Canadian
federal government. Since April 2020, the Canadian federal government announced
various COVID-19 relief programs which included, but are not limited to, loans,
commercial rent and wage subsidies, to qualifying companies.
For the year ended September 30, 2020, our interest income decreased by $2,519
compared to the year ended September 30, 2019, due to a decline in interest
rates.
As a result of the above transactions, our net loss and loss from operations for
the year ended September 30, 2020 decreased by $93,833 compared to the year
ended September 30, 2019. This decrease was primarily due to the decreases in
general and administrative expenses and an increase of $61,220 COVID-19 support
income.
Liquidity and Capital Resources
As of September 30, 2020, our total assets were $22,768,964 compared to
$22,677,977 as of September 30, 2019. There was an increase of $90,987 in our
total assets from the September 30, 2019 year end, which was primarily due to an
increase of $161,200 in accounts receivable.
As of September 30, 2020, our total liabilities were $765,673 compared to
$571,384 as of September 30, 2019. There was an increase of $194,289 in our
total liabilities from the September 30, 2019 year end, which was primarily due
to an increase of $156,796 in accounts payable and an increase of $22,491 from a
loan we received.
For the year ended September 30, 2020, we performed an assessment of our
carrying costs of our unproven oil sands properties and determined that no
write-down of our oil and gas properties as of September 30, 2020 was necessary.
No write-downs of our unproven oil sands properties were recorded in the year
ended September 30, 2019.
Our working capital is as follows.
September 30, September 30,
2020 2019
Current Assets $ 255,197 $ 167,379
Current Liabilities 227,788 70,992
Working Capital $ 27,409 $ 96,387As of September 30, 2020, we had working capital of $27,409 compared to our
working capital of $96,387 as of September 30, 2019. This decrease of $68,978 in
working capital is primarily due to cash used for general and administrative
expenses and an increase of $156,796 in current liabilities.
As reported on our Consolidated Statement of Cash Flows under "Operating
Activities", for the year ending September 30, 2020, our net cash used in
operating activities was $53,086 compared to $177,258 for the year ended
September 30, 2019. This decrease of $124,172 was primarily due to a decrease of
$40,717 for general and administrative expenses and a decrease of $68,978 from
changes in non-cash working capital.
As reported on our Consolidated Statement of Cash Flows under "Investing
Activities", we had a decrease of $56,678 on investment in our oil and gas
properties for the year ended September 30, 2020, compared to the year ended
September 30, 2019.
As reported on our Consolidated Statement of Cash Flows under "Financing
Activities", for the year ended September 30, 2020, we had increase of $7,491
compared to the year ended September 30, 2019. This increase was due to the loan
received by one of the Company's Canadian subsidiaries Canadian chartered bank
in the amount of $22,491 ($30,000 Cdn) as part of the Canadian government's
COVID-19 relief program on April 20, 2020. See Note 3 "Loan Payable" herein
included in the consolidated Financial Statements.
Our cash and cash equivalents for the year ending September 30, 2020 were
negative $12,073 compared to $49,715 in the year ending September 30, 2019. This
decrease of $61,788 in cash was primarily due to general and administrative
expenses.
17
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
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
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.
Cautionary Note Regarding Forward-Looking Statements
This Annual Report, 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 Annual 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 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.
18
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 stockholders' equity;
? competition;
? 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;
19
? 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 Annual 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" as disclosed in this Annual Report on Form 10-K for the fiscal
year ended September 30, 2020 filed with the United States Securities and
Exchange Commission ("SEC"). 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.
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