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 with the Alberta Securities Commission ("ASC") on SEDAR on January
13, 2020 and the U.S. Securities and Exchange Commission ("SEC") 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 ("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 January 3, 2020, the daily rate of exchange
for Cdn$, expressed in US$ was Cdn$1.00 = US$0.7699 as reported by the Bank of
Canada.
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 NW, 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 the Annual Report on Form 10-K for the fiscal year ended
September 30, 2019.
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. Currently,
we have received approval from the AER for two thermal recovery projects located
on our Sawn Lake properties. To date, our geological, engineering, economic
studies, and our SAGD Project production results lead us to believe that our
working interest can support future full profitable commercial production.
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 with significant future
potential value. 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.
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]]
In early May of 2016, 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. We
and our joint venture partners continue to move forward with SAGD Project with
completing detailed engineering and assessing potential marketing arrangements
for the commercial development expansion to 3,200 bopd (100% basis). As of June
30, 2019, a Sawn Lake full field development plan using SAGD batteries has been
defined by the operator of the SAGD Project.
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.
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.
14
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 to the AER to continue the best
sections of our oil sands properties past their initial lease expiry dates,
where resources were identified. Under the oil sands lease continuation
regulations an operator or leaseholder must demonstrate certain levels of
exploration and development by providing the AER with drilling, coring and
seismic data within a certain timeframe in order to maintain the lease past its
expiry date. Our Company's Sawn Lake oil sands properties under lease as of
September 30, 2019, covers 19,610 gross acres (13,442 net acres) of land under
seven oil sands leases. The lease expiration dates of our Company's oil sands
leases are as follows:
1. Out of 20,242 gross acres (13,284 net acres) under five oil sands leases were
set to expiry on July 10, 2018, 14,549 gross acres (8,571 net acres) were
granted continuation under the Alberta Oil Sands Tenure regulations and have
no set expiry date. In November of 2017, our Company's joint venture partner
and operator of two of these 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 in January 2018, approval was received
from Alberta Energy to continue 6,958 gross acres (1,740 net acres). In June
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 and in July 2018 and April 2019, approval was
received from Alberta Energy to continue 7,591 gross acres (6,832 net acres).
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. These continued leases are now
held by our Company for perpetuity, subject to yearly escalating rental
payments until they are deemed to be producing leases.
2. 19,610 gross acres (17,649 net acres) under the three most northern oil sands
leases were set to expire on August 19, 2019. In August 2019, our Company
submitted one continuation application to the Alberta Oil Sands Tenure
division to apply to continue 1,898 acres (1,708 net acres) of the 19,610
gross acres (17,649 net acres) on one of the northern most leases and
subsequently in early October 2019 approval was received from Alberta Energy
to continue 1,898 gross acres (1,708 net acres) past the expiry date of the
lease. This one partially continued lease is now held by our Company for
perpetuity, subject to yearly escalating rental payments until they are deemed
to be producing leases. On August 19, 2019, 17,712 gross acres (15,941 net
acres) expired without being continued. These expired lands were primarily
areas where we determined that there was no or limited exploitable resources.
3. 3,163 gross acres (3,163 net acres) under one oil sands lease 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
The following table sets forth summarized financial information:
September 30, September 30,
2019 2018
Revenue $ - $ -
Provincial royalty expenses - -
Revenue, net of royalty - -
Expenses
Operating expenses 97,643 148,046
Operating expense covered by Farmout (97,643 ) (148,046 )
General and administrative 165,405 289,209
Depreciation, accretion and depletion 46,036 56,032
Net loss from operations (211,441 ) (345,241 )
Other income and expenses
Rental and other income 6,612 9,054
Interest income 7,694 6,056
Net loss $ (197,135 ) $ (330,131 )
15
There was no production volumes or revenues for the fiscal years ending
September 30, 2019 and 2018, 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. 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, 2019, the Farmee
has since reimbursed our Company and/or paid the operator in total approximately
$20.6 million (Cdn$27.3 million) 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.
For the year ended September 30, 2019, our general and administrative expenses
decreased by $123,804 compared to the year ended September 30, 2018, which was
primarily due to decreases in engineering, and audit fees. We also received
$360,000 during the current fiscal year from the Farmee in accordance with a
Farmout Agreement to offset some of our monthly expenses. After adjusting out
the non-cash items for foreign exchange loss, and the funds we received from the
Farmee, our general and administrative expenses were $523,117 for the year ended
September 30, 2019 compared to $643,080 for the year ended September 30, 2018.
For the year ended September 30, 2019, our depreciation and accretion expense
decreased by $9,996 compared to the year ended September 30, 2018, which was
primarily due to the depreciating value of our assets. Our 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.
For the year ended September 30, 2019, our rental and other income decreased by
$2,442 compared to the year ended September 30, 2018.
As a result of the above transactions, our net loss and loss from operations for
the year ended September 30, 2019 decreased by $132,996 compared to the year
ended September 30, 2018. As discussed above this decrease was primarily due to
the decreases in engineering and audit fees.
Liquidity and Capital Resources
As of September 30, 2019, our total assets were $22,677,977 compared to
$22,827,332 as of September 30, 2018.
As of September 30, 2019, our total liabilities were $571,384 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.
For the year ended September 30, 2019, 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, 2019 was necessary.
No write-downs of our unproven oil sands properties were recorded in the year
ended September 30, 2018.
Our working capital is as follows.
September 30, September 30,
2019 2018
Current Assets $ 167,379 $ 363,891
Current Liabilities 70,992 45,137
Working Capital $ 96,387 $ 318,754As of September 30, 2019, our Company had working capital of $96,387 compared to
our working capital of $318,754 as of September 30, 2018. This decrease is
mainly due to cash used for general and administrative expenses.
On July 31, 2013, we entered into the Farmout Agreement to fund our share of the
costs of our joint SAGD Project. As of September 30, 2019, we recorded $38,213
in accounts payable due to the operator for our working interest share of the
outstanding monthly operating expenses of the SAGD Project, of which all is
reimbursable by the Farmee in accordance with the Farmout Agreement. Therefore,
this amount is also recorded in accounts receivable to be paid to us from the
Farmee to cover our share of the costs of the SAGD Project.
16
As reported on our Consolidated Statement of Cash Flows under "Operating
Activities", for the year ending September 30, 2019, our net cash used in
operating activities was $177,258 compared to $343,396 for the year ended
September 30, 2018. This decrease of $166,138 was primarily the result of a
decrease inoperating expenses, which included engineering fees and audit fees.
As reported on our Consolidated Statement of Cash Flows under "Investing
Activities", we had a decrease of $612,839 in the investment in our oil and gas
properties for the year ended September 30, 2019, compared to the year ended
September 30, 2018. This decrease is primarily due to the cash contribution of
$395,500 (Cdn$500,000) we paid in February 2018 to a third-party operator who
was drilling into a deeper formation below our properties, to drill and acquire
cores and logs for us through the Bluesky formation on one of our oil sands
leases.
As reported on our Consolidated Statement of Cash Flows under "Financing
Activities", for the year ended September 30, 2019 and September 30, 2018, we
received $15,000 from one of our directors for the exercise of his stock
options. We also had a decrease of $245,184 compared to the year ended September
30, 2018. This decrease is due to a $245,184 refund we received in June 2018,
which was related to a return of capital distribution our Company issued in
September of 2013.
Our cash and cash equivalents for the year ending September 30, 2019 were
$49,715 compared to $298,241 in the year ending September 30, 2018. This
decrease of $248,526 in cash was primarily due to general and administrative
expenses.
As of September 30, 2019, we had no long-term debt other than our estimated
asset retirement obligations on our oil and gas properties.
Our current SAGD Project capital and operating costs are covered under the terms
of the Farmout Agreement. 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
We do not have any off-balance sheet arrangements.
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;
17
? 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.
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;
? 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;
? 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 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;
? fluctuations in currency and interest rates; and
18
? 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, 2019 filed with the United States Securities and
Exchange Commission ("SEC") and the Alberta Securities Commission ("ASC") on
SEDAR. 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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