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 December 31 2019 2018
Rate at end of period $ 0.7699 $ 0.7330
Average rate for the three month period $ 0.7576 $ 0.7575
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 SEC's website at
www.sec.gov. The contents of our website are not part of this quarterly report
on Form 10-Q.
10
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 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 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.
12
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:
Three Months Ended Three Months Ended
December 31, 2019 December 31, 2018
Revenue $ - $ -
Provincial royalty expenses - -
Revenue, net of royalty - -
Expenses
Operating expenses 27,738 39,660
Operating expense covered by Farmout (27,738 ) (39,660 )
General and administrative 30,321 53,855
Depreciation, accretion and depletion 10,843 11,442
Net loss from operations (41,164 ) (65,297 )
Other income and expenses
Rental and other income (2,047 ) 2,046
Interest income 1,994 1,810
Net loss $ (41,217 ) $ (61,441 )
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There was no production volumes or revenues for the years ending December 31,
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 December 31, 2019, the Farmee has since
reimbursed our Company and/or paid the operator in total approximately $21.1
million (Cdn$27.4 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 three months ended December 31, 2019, our general and administrative
expenses decreased by $23,534 compared to the three months ended December 31,
2018, which was primarily due to decreases in office rent and auditor fees. We
received $90,000 during this quarter from the Farmee in accordance with a
Farmout Agreement to offset some of our monthly expenses. After adjusting out
the non-cash item for foreign exchange and the funds we received from the
Farmee, our general and administrative expenses were $119,643 for the three
months ended December 31, 2019 compared to $146,732 for the three months ended
December 31, 2018.
For the three months ended December 31, 2019, our depreciation, depletion, and
accretion expense decreased by $599 compared to the three months ended December
31, 2018, which was primarily due to the depreciating value of our assets.
Depreciation expense is computed using the declining balance method over the
estimated useful life of the asset. In compliance with our accounting policy,
only half of the depreciation is taken in the year of acquisition. No
significant asset purchases were made in the quarter ended December 31, 2019.
For the three months ended December 31, 2019, there was $4,093 decrease for
rental and other income compared to the three months ended December 31, 2018.
As a result of the above transactions, we recorded a decrease of $20,224 in our
net loss for the three months ended December 31, 2019 compared to the three
months ended December 31, 2018. As discussed above, this decrease was primarily
due to decreases in office rent fees and audit fees.
Liquidity and Capital Resources
As of December 31, 2019, our total assets were $22,672,085 compared to
$22,677,977 as of September 30, 2019.
Our total liabilities as of December 31, 2019 were $606,709 compared to $571,384
as of September 30, 2019. There was no significant change in our total
liabilities from the September 30, 2019 year end.
Our working capital (current liabilities subtracted from current assets) is as
follows:
Three months Ended Year Ended
December 31, 2019 September 30, 2019
Current Assets $ 147,497 $ 167,379
Current Liabilities 91,739 70,992
Working Capital $ 55,758 $ 96,387
As of December 31, 2019, we had working capital of $55,758 compared to a working
capital of $96,387 as of September 30, 2019. This decrease of $40,629 is
primarily due to cash used for general and administrative expenses.
As reported on our condensed Consolidated Statement of Cash Flows under
"Operating Activities", for the three months ended December 31, 2019, our net
cash used in operating activities was $1,754 compared to $81,855 for the three
months ended December 31, 2018. This decrease of $80,101 in our operating
activities was due to a decrease of $20,224 for general and administrative
expenses and a decrease of $60,476 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 $38,632 on investment in our oil
and gas properties for the three months ended December 31, 2019, compared to the
three months ended December 31, 2018. There were no significant investing
activities during these periods.
As reported on our condensed Consolidated Statement of Cash Flows under
"Financing Activities", for the three months ended December 31, 2019 and
December 31, 2018, we had a decrease of $15,000 compared to the three months
ended December 31, 2018. There were no financing activities for the three months
ended December 31, 2019 period.
14
Our cash and cash equivalents as of December 31, 2019 was $37,706 compared to
$181,691 as of December 31, 2018. This decrease of $143,985 in cash was
primarily due to the cash used in general and administrative expenses.
As of December 31, 2019, we had no long-term debt other than our estimated
future asset retirement obligations on oil and gas properties.
Our current SAGD Project 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.
Cautionary Note Regarding Forward-Looking Statements
This quarterly report on Form 10-Q, including all referenced Exhibits, contains
"forward-looking statements" within the meaning of the United States federal
securities laws. All statements other than statements of historical facts
included or incorporated by reference in this report, including, without
limitation, statements regarding our future financial position, business
strategy, projected costs and plans and objectives of management for future
operations, are forward-looking statements. The words "may," "believe,"
"intend," "will," "anticipate," "expect," "estimate," "project," "future,"
"plan," "strategy," "probable," "possible," or "continue," and other expressions
that are predictions of or indicate future events and trends and that do not
relate to historical matters, often identify forward-looking statements. For
these statements, Deep Well claims the protection of the safe harbor for
forward-looking statements contained in the Private Securities Litigation Reform
Act of 1995. The forward-looking statements in this quarterly report include,
among others, statements with respect to:
? our current business strategy;
? our future financial position and projected costs;
? our projected sources and uses of cash;
? our plan for future development and operations, including the building of
all-weather roads;
? our drilling and testing plans;
? our proposed plans for further thermal in-situ development or demonstration
project or projects;
? the sufficiency of our capital in order to execute our business plan;
? our reserves and resources estimates;
? the timing and sources of our future funding;
? the quantity and value of our reserves;
? the intent to issue a distribution to our shareholders;
? our or our operator's objectives and plans for our current SAGD Project;
? our plans for development of our Sawn Lake properties;
? production levels from our current SAGD Project;
? costs of our current SAGD Project;
? funding from the Farmee to pay our costs for the current SAGD Project in
connection with the Farmout Agreement;
? additional sources of funding from the Farmout Agreement;
? funding from the Farmee to cover our monthly operating expenses;
? our access and availability to third-party infrastructure;
? present and future production of our properties;
? our 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;
15
? 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 shareholders' 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 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;
? fluctuations in currency and interest rates; 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.
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