DEEP WELL
OIL & GAS, INC. (AND SUBSIDIARIES)
Condensed Consolidated Balance Sheets
December 31, 2019 and September 30, 2019
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December 31,
2019
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September 30,
|
|
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|
(Unaudited)
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|
|
2019
|
|
|
|
|
|
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ASSETS
|
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
37,706
|
|
|
$
|
49,715
|
|
Accounts receivable
|
|
|
70,368
|
|
|
|
83,398
|
|
Prepaid expenses
|
|
|
39,423
|
|
|
|
34,266
|
|
|
|
|
|
|
|
|
|
|
Total Current Assets
|
|
|
147,497
|
|
|
|
167,379
|
|
|
|
|
|
|
|
|
|
|
Long term investments
|
|
|
406,576
|
|
|
|
396,782
|
|
Unproved Oil and gas properties, net, based on full cost method of accounting
|
|
|
22,047,866
|
|
|
|
22,040,307
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|
Property and equipment, net
|
|
|
70,146
|
|
|
|
73,509
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
22,672,085
|
|
|
$
|
22,677,977
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
|
|
|
|
|
|
|
|
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Current Liabilities
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$
|
91,739
|
|
|
$
|
69,617
|
|
Accounts payable and accrued liabilities – related parties
|
|
|
–
|
|
|
|
1,375
|
|
|
|
|
|
|
|
|
|
|
Total Current Liabilities
|
|
|
91,739
|
|
|
|
70,992
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations (Note
7)
|
|
|
514,970
|
|
|
|
500,392
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES
|
|
|
606,709
|
|
|
|
571,384
|
|
(Commitments and contingencies Note 11)
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|
|
|
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|
|
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SHAREHOLDERS’ EQUITY
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Common Stock: (Note
8)
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Authorized: 600,000,000 shares at $0.001 par value Issued and outstanding: 230,574,603 shares (September 30, 2019 – 230,574,603 shares)
|
|
|
230,574
|
|
|
|
230,574
|
|
Additional paid in capital
|
|
|
43,104,276
|
|
|
|
43,104,276
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|
Accumulated deficit
|
|
|
(21,269,474
|
)
|
|
|
(21,228,257
|
)
|
|
|
|
|
|
|
|
|
|
Total Shareholders’ Equity
|
|
|
22,065,376
|
|
|
|
22,106,593
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
22,672,085
|
|
|
$
|
22,677,977
|
|
See accompanying notes to the condensed consolidated financial
statements
DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
(Unaudited)
Condensed Consolidated Statements of
Operations
For Three Months Ended December 31, 2019
and 2018
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December 31,
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|
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December 31,
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|
|
|
2019
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|
|
2018
|
|
|
|
|
|
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Revenue
|
|
$
|
–
|
|
|
$
|
–
|
|
Royalty refunds (expenses)
|
|
|
–
|
|
|
|
–
|
|
Revenue, net of royalty
|
|
|
–
|
|
|
|
–
|
|
|
|
|
|
|
|
|
|
|
Expenses
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
27,738
|
|
|
|
39,660
|
|
Operating expenses covered by Farmout
|
|
|
(27,738
|
)
|
|
|
(39,660
|
)
|
General and administrative
|
|
|
30,321
|
|
|
|
53,855
|
|
Depreciation, accretion and depletion
|
|
|
10,843
|
|
|
|
11,442
|
|
|
|
|
|
|
|
|
|
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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
|
)
|
|
|
|
|
|
|
|
|
|
Net loss per common share
|
|
|
|
|
|
|
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|
Basic and Diluted
|
|
$
|
(0.00
|
)
|
|
$
|
(0.00
|
)
|
|
|
|
|
|
|
|
|
|
Weighted Average Outstanding Shares (in thousands)
|
|
|
|
|
|
|
|
|
Basic and Diluted
|
|
|
230,574
|
|
|
|
230,574
|
|
See accompanying notes to the condensed consolidated financial
statements
DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
(Unaudited)
Condensed Consolidated Statements of
Changes in Shareholders’ Equity
For the Three Months Ended December 31,
2019 and 2018
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|
Common Shares
|
|
|
Additional Paid in
|
|
|
Subscription
|
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|
Accumulated
|
|
|
|
|
|
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Shares
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Amount
|
|
|
Capital
|
|
|
Receivable
|
|
|
Deficit
|
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|
Total
|
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|
|
|
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|
|
|
|
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For the Three Months Ended December 31, 2018
|
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|
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|
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Balance at September 30, 2018
|
|
|
230,574,603
|
|
|
$
|
230,574
|
|
|
$
|
43,104,276
|
|
|
$
|
(15,000
|
)
|
|
$
|
(21,031,122
|
)
|
|
$
|
22,288,728
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subscription receivable collected
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
15,000
|
|
|
|
–
|
|
|
|
15,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss for the quarter ended December 31, 2018
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
(61,441
|
)
|
|
|
(61,441
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2018
|
|
|
230,574,603
|
|
|
$
|
230,574
|
|
|
$
|
43,104,276
|
|
|
$
|
–
|
|
|
$
|
(21,092,563
|
)
|
|
$
|
22,242,287
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
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|
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For the Three Months Ended December 31, 2019
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at September 30, 2019
|
|
|
230,574,603
|
|
|
$
|
230,574
|
|
|
$
|
43,104,276
|
|
|
$
|
–
|
|
|
$
|
(21,228,257
|
)
|
|
$
|
22,106,593
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Net loss for the quarter ended December 31, 2019
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
(41,217
|
)
|
|
|
(41,217
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Balance at December 31, 2019
|
|
|
230,574,603
|
|
|
$
|
230,574
|
|
|
$
|
43,104,276
|
|
|
$
|
–
|
|
|
$
|
(21,269,474
|
)
|
|
$
|
22,065,376
|
|
See accompanying notes to the condensed consolidated financial
statements
DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
(Unaudited)
Condensed Consolidated Statements
of Cash Flows
For the Three Months Ended December 31,
2019 and 2018
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2019
|
|
|
2018
|
|
|
|
|
|
|
|
|
CASH PROVIDED BY (USED IN):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities
|
|
|
|
|
|
|
Net loss
|
|
$
|
(41,217
|
)
|
|
$
|
(61,441
|
)
|
Items not affecting cash:
|
|
|
|
|
|
|
|
|
Depreciation, accretion and depletion
|
|
|
10,843
|
|
|
|
11,442
|
|
Net changes in non-cash working capital (Note 10)
|
|
|
28,620
|
|
|
|
(31,856
|
)
|
|
|
|
|
|
|
|
|
|
Net Cash Used in Operating Activities
|
|
|
(1,754
|
)
|
|
|
(81,855
|
)
|
|
|
|
|
|
|
|
|
|
Investing Activities
|
|
|
|
|
|
|
|
|
Purchase of equipment
|
|
|
–
|
|
|
|
(534
|
)
|
Investment in oil and gas properties
|
|
|
(12,272
|
)
|
|
|
(50,904
|
)
|
Long term investments
|
|
|
2,017
|
|
|
|
1,743
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used in Investing Activities
|
|
|
(10,255
|
)
|
|
|
(49,695
|
)
|
|
|
|
|
|
|
|
|
|
Financing Activities
|
|
|
|
|
|
|
|
|
Subscription receivable collected
|
|
|
–
|
|
|
|
15,000
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by Financing Activities
|
|
|
–
|
|
|
|
15,000
|
|
|
|
|
|
|
|
|
|
|
Decrease in cash and cash equivalents
|
|
|
(12,009
|
)
|
|
|
(116,550
|
)
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, beginning of period
|
|
|
49,715
|
|
|
|
298,241
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
37,706
|
|
|
$
|
181,691
|
|
|
|
|
|
|
|
|
|
|
Supplemental Cash Flow Information:
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
–
|
|
|
$
|
–
|
|
Cash paid for income taxes
|
|
$
|
–
|
|
|
$
|
–
|
|
See accompanying notes to the condensed consolidated financial
statements
DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
(Unaudited)
Notes to the Condensed Consolidated Financial
Statements
December 31, 2019
|
1.
|
NATURE OF BUSINESS AND BASIS OF PRESENTATION
|
Nature of Business
Deep Well Oil & Gas, Inc.
was originally incorporated on July 18, 1988 under the laws of the state of Nevada as Worldwide Stock Transfer, Inc. (Worldwide
Stock Transfer, Inc. later changed its name to Allied Devices Corporation) and in connection with a plan of reorganization, effective
on September 10, 2003, the company was reorganized and changed its name to Deep Well Oil & Gas, Inc. (“Deep Well”).
These condensed consolidated
financial statements have been prepared showing the name “Deep Well Oil & Gas, Inc. (and Subsidiaries)” (“the
Company”) and the post-split common stock, with $0.001 par value.
Basis of Presentation
The interim condensed consolidated
financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of
the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements
prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) have
been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate
so as to make the information presented not misleading.
These interim condensed consolidated
financial statements follow the same significant accounting policies and methods of application as the Company’s annual consolidated
financial statements for the year ended September 30, 2019.
These statements reflect all
adjustments, consisting solely of normal recurring adjustments (unless otherwise disclosed) which, in the opinion of management,
are necessary for a fair presentation of the information contained therein. However, the results of operations for the interim
periods may not be indicative of results to be expected for the full fiscal year. It is suggested that these condensed consolidated
financial statements be read in conjunction with the audited consolidated financial statements and notes thereto included in the
Company’s Annual Report on Form 10-K for the year ended September 30, 2019.
|
2.
|
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
|
Basis of Consolidation
These interim condensed consolidated
financial statements include the accounts of two wholly owned subsidiaries: (1) Northern Alberta Oil Ltd. (“Northern”)
from the date of acquisition, being June 7, 2005, incorporated under the Business Corporations Act (Alberta), Canada; and (2) Deep
Well Oil & Gas (Alberta) Ltd., incorporated under the Business Corporations Act (Alberta), Canada on September 15, 2005. All
inter-company balances and transactions have been eliminated.
Crude oil and natural gas
properties
The Company follows the full
cost method of accounting for oil sands properties pursuant to SEC Regulation S-X Rule 4-10. The full cost method of accounting
for oil and gas operations requires that all costs associated with the exploration for and development of oil and gas reserves
be capitalized on a country by country basis. Such costs include lease acquisition costs, geological and geophysical expenses,
carrying charges on non-producing properties, costs of drilling both productive and non-productive wells, production equipment
and overhead charges directly related to acquisition, exploration and development activities.
Under
the full cost method, oil and gas properties are subject to the ceiling test performed quarterly. A
ceiling test write-down is recognized in net earnings if the carrying amount of a cost centre exceeds the “cost centre ceiling”.
The carrying amount of the cost centre includes the capitalized costs of proved oil and natural gas properties, net of accumulated
depletion and deferred income taxes. The cost centre ceiling is the sum of (A) present value of the estimated future net cash flows
from proved oil and natural gas reserves using a 10 percent per year discount factor, (B) the costs of unproved properties not
being amortized, and (C) the lower of cost or fair value of unproved properties included in
the costs being amortized; less (D) related income tax effects. As of December 31, 2019, no ceiling test write-downs were recorded
for the Company’s oil and gas properties.
Costs associated with unproved
properties are excluded from the depletion calculation until it is determined that proved reserves are attributable or impairment
has occurred. Unproved properties are assessed annually for impairment. Costs that have been impaired are included in the costs
subject to depletion within the full cost pool.
Asset Retirement Obligations
The Company accounts for asset
retirement obligations by recording the fair value of the estimated future cost of the Company’s plugging and abandonment
obligations. The asset retirement obligation is recorded when there is a legal obligation associated with the retirement of a tangible
long-lived asset and the fair value of the liability can reasonably be estimated. Upon initial recognition of an asset retirement
obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the
liabilities are accreted for the change in their present value through charges to oil and gas production and well operations costs.
The initial capitalized costs are depleted over the useful lives of the related assets through charges to depreciation, depletion,
and amortization. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the
asset retirement obligation and the asset retirement cost.
Revisions in estimated liabilities
can result from revisions of estimated inflation rates, escalating retirement costs, and changes in the estimated timing of settling
asset retirement obligations. As of December 31, 2019, and September 30, 2019, asset retirement obligations amount to $514,970
and $500,392, respectively. The Company has posted bonds, where required, with the Government of Alberta based on the amount the
government estimates the cost of abandonment and reclamation to be.
Financial, Concentration
and Credit Risk
The Company’s consideration
or related financial credit risk related to cash and cash equivalents depends on if funds are fully insured by either The Canada
Deposit Insurance Corporation (“CDIC”), or The Credit Union Deposit Guarantee Corporation (“CUDGC”) deposit
insurance limit. As of December 31, 2019, the Company has approximately $19,458 funds that are in excess of deposit insurance limits,
which may have financial credit risk. For the Company funds that are maintained in a financial institution which has its deposits
fully guaranteed by CUDGC, there is no financial credit risk.
The Company is not directly subject
to credit risk resulting from the concentration of its crude oil sales. For the period ending December 31, 2019 and December 31,
2018 the Company recorded no oil sales.
Basic and Diluted Net Loss Per Share
Basic net loss per share amounts
are computed based on the weighted average number of shares actually outstanding. Diluted net loss per share amounts are computed
using the weighted average number of common shares and common equivalent shares outstanding as if shares had been issued on the
exercise of the common share rights, unless the exercise becomes antidilutive and then the basic and diluted per share amounts
are the same. There were no potentially dilutive securities excluded from the the diluted earnings per share calculation because
their effect would be antidilutive.
Recently Adopted Accounting Standards
In February 2016, the FASB issued
ASU 2016-02, “Leases (Topic 842),” requiring lessees to recognize lease assets and lease liabilities for most leases
classified as operating leases under previous U.S. GAAP. The guidance is effective for fiscal years beginning after December 15,
2018, with early adoption permitted. The Company will be required to use a modified retrospective approach for leases that exist
or are entered into after the beginning of the earliest comparative period in the financial statements. This ASU does not apply
to the Company’s oil sand leases. The adoption of this standard did not have a material impact on the Company’s consolidated
financial statements because the Company has no leases that the new accounting standard applies to.
|
3.
|
OIL AND GAS PROPERTIES
|
The Company’s oil sands
acreage as of December 31, 2019, covers 19,610 gross acres (13,442 net acres) of land under seven oil sands leases. The lease expiration
dates of the Company’s oil sands leases are as follows:
|
1.
|
Out of 20,242 gross acres (13,284 net acres) under five oil sands leases that 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, the Company’s joint venture partner and operator of two of the five oil
sands leases, submitted two continuation applications to the Alberta Oil Sands Tenure division to apply to continue 7,591 gross
acres (1,898 net acres) and in January 2018, approval was received from Alberta Energy to continue 6,958 gross acres (1,740 net
acres). In June 2018, the 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 the Company determined that there was no or limited
exploitable resources. These continued leases are now held by the Company for perpetuity, subject to yearly escalating rental payments
until they are deemed to be producing leases;
|
|
2.
|
Out of 19,610 gross acres (17,649 net acres) under the three most northern oil sands leases that
were set to expire on August 19, 2019, 1,898 gross acres (1,708 net acres) were granted continuation under the Alberta Oil Sands
Tenure regulations and have no set expiry date. In August 2019, the Company as operator of these three most northern leases submitted
one continuation application to the Alberta Oil Sands Tenure division to apply to continue 1,898 gross acres (1,708 net acres)
and in October 2019, approval was received from Alberta Energy to continue 1,898 gross acres (1,708 net acres). Of these three
most northern oil sands leases that were set to expiry on August 19, 2019, a total of 17,712 gross acres (15,941 net acres) expired
without being continued. These expired lands were primarily areas where the Company determined that there was no or limited exploitable
resources. This one partially continued lease is now held by the Company for perpetuity, subject to yearly escalating rental payments
until the lease is deemed to be a producing lease; and
|
|
3.
|
3,163 gross acres (3,163 net acres) under one oil sands lease are set to expire on April 9, 2024.
It is the Company’s opinion that they have already met the governmental requirements for this lease, and they will be applying
to continue this lease into perpetuity.
|
Lease Rental Commitments
The Company has acquired interests
in certain oil sands properties located in North Central Alberta, Canada. The lease terms include certain commitments related to
oil sands properties that require the payments of yearly rents. As required by the Oil Sands Tenure Regulation of the Mines and
Minerals Act of Alberta continued oil sands leases past their expiry dates are subject to escalating rental payments in respect
of each term year of a continued lease that is designated as non-producing less any eligible research costs, exploration costs
and development costs that are incurred in the term year of a continued lease. Escalating rent is payable at the end of each term
year, while annual rent for leases are due at the beginning of each term year. Lessees of continued oil sands leases may reduce
or eliminate their escalating rent obligations by conducting exploration or development work, or research, on the non-producing
lease. As of December 31, 2019, excluding any eligible research, exploration and or development costs that may be used to reduce
the Company’s yearly escalating future rents, the following table sets out the estimated net payments due under this commitment,
which could be as high:
|
|
(USD $)
|
|
|
(Cdn $)
|
|
2020
|
|
$
|
20,598
|
|
|
$
|
26,754
|
|
2021
|
|
$
|
23,228
|
|
|
$
|
30,170
|
|
2022
|
|
$
|
30,204
|
|
|
$
|
39,230
|
|
2023
|
|
$
|
31,800
|
|
|
$
|
41,303
|
|
2024
|
|
$
|
27,425
|
|
|
$
|
35,621
|
|
Subsequent
|
|
$
|
153,209
|
|
|
$
|
198,998
|
|
The Company follows the full
cost method of accounting for costs of oil properties. Under this method, oil and gas properties, for which no proved reserves
have been assigned, must be assessed at least annually to ascertain whether or not a write down should occur. Unproven properties
are assessed annually, or more frequently as economic events indicate, for potential write down.
Estimates of expected future
cash flows represent management’s best estimate based on reasonable and supportable assumptions. No write downs were recognized
for the period ended December 31, 2019.
Capitalized costs of proven oil
properties will be depleted using the unit-of-production method when the property is placed in production.
Many of the Company’s oil
activities are conducted jointly with others. The accounts reflect only the Company’s proportionate interest in such activities.
|
4.
|
CAPITALIZATION OF COSTS INCURRED IN OIL AND GAS
ACTIVITIES
|
The following table illustrates
capitalized costs relating to oil producing activities for the three months ended December 31, 2019 and the fiscal year ended September
30, 2019:
|
|
December 31,
2019
|
|
|
September 30,
2019
|
|
Unproved Oil and Gas Properties
|
|
$
|
22,157,718
|
|
|
$
|
22,147,367
|
|
Accumulated Depreciation and Depletion
|
|
|
(109,852
|
)
|
|
|
(107,060
|
)
|
Net Capitalized Cost
|
|
$
|
22,047,866
|
|
|
$
|
22,040,307
|
|
Depreciation and depletion expense
for the three months ended December 31, 2019 and 2018 were $2,785 and $2,785 respectively.
|
5.
|
EXPLORATION ACTIVITIES
|
The following table presents
information regarding the Company’s costs incurred in the oil property acquisition, exploration and development activities
for the three months ended December 31, 2019 and the fiscal year ended September 30, 2019:
|
|
December 31,
2019
|
|
|
September 30,
2019
|
|
Acquisition of Properties:
|
|
|
|
|
|
|
Proved
|
|
$
|
–
|
|
|
$
|
–
|
|
Unproved
|
|
$
|
–
|
|
|
$
|
–
|
|
Exploration costs
|
|
$
|
10,351
|
|
|
$
|
75,580
|
|
Development costs
|
|
$
|
–
|
|
|
$
|
–
|
|
|
6.
|
SIGNIFICANT TRANSACTIONS WITH RELATED PARTIES
|
Accounts payable – related
parties were $Nil as of December 31, 2019 (September 30, 2019 - $1,375) for expenses to be reimbursed to directors. This amount
is unsecured, non-interest bearing, and has no fixed terms of repayment.
As of December 31, 2019, officers,
directors, their families, and their controlled entities have acquired 53.96% of the Company’s outstanding common capital
stock.
The Company incurred expenses
$34,092 to one related party, Concorde Consulting, an entity controlled by a director, for professional fees and consulting services
provided to the Company during the period ended December 31, 2019 (December 31, 2018 - $34,088). These amounts were fully paid
as of December 31, 2019.
|
7.
|
ASSET RETIREMENT OBLIGATIONS
|
The total future asset retirement
obligation is estimated by management based on the Company’s net working interests in all wells and facilities, estimated
costs as determined by the Alberta Energy Regulator to reclaim and abandon wells and facilities and the estimated timing of the
costs to be incurred in future periods. At December 31, 2019, the Company estimates the undiscounted cash flows related to asset
retirement obligations to total approximately $622,253 (September 30, 2019 - $610,291). The fair value of the liability at December
31, 2019 is estimated to be $514,970 (September 30, 2019 - $500,392) using a risk-free rate of 3.74% and an inflation rate of 2%.
The actual costs to settle the obligation are expected to occur in approximately 23 years.
Changes to the asset retirement
obligation were as follows:
|
|
December 31,
2019
|
|
|
September 30, 2019
|
|
Balance, beginning of period
|
|
$
|
500,392
|
|
|
$
|
493,467
|
|
Liabilities incurred
|
|
|
–
|
|
|
|
–
|
|
Effect of foreign exchange
|
|
|
9,884
|
|
|
|
(11,081
|
)
|
Disposal
|
|
|
–
|
|
|
|
–
|
|
Accretion expense
|
|
|
4,694
|
|
|
|
18,006
|
|
Balance, end of period
|
|
$
|
514,970
|
|
|
$
|
500,392
|
|
Common Stock Issued and
Outstanding
As of December 31, 2019, the
Company had outstanding 230,574,603 shares of common stock.
On November 17, 2019, 600,000
stock options previously granted on November 17, 2014 to one director expired unexercised.
The following is a summary of stock option activity
as at December 31, 2019:
|
|
Number of Underlying Shares
|
|
|
Weighted Average Exercise Price
|
|
|
Weighted Average Fair Market Value
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2019
|
|
|
600,000
|
|
|
$
|
0.23
|
|
|
$
|
0.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expired, November 17, 2019
|
|
|
(600,000
|
)
|
|
|
0.23
|
|
|
|
0.18
|
|
Balance, December 31, 2019
|
|
|
–
|
|
|
$
|
–
|
|
|
$
|
–
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, December 31, 2019
|
|
|
–
|
|
|
$
|
–
|
|
|
$
|
–
|
|
|
10.
|
CHANGES IN NON-CASH WORKING CAPITAL
|
|
|
Three months ended
|
|
|
Three months Ended
|
|
|
|
December 31,
2019
|
|
|
December 31,
2018
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
$
|
13,030
|
|
|
$
|
(40,607
|
)
|
Prepaid expenses
|
|
|
(5,157
|
)
|
|
|
4,835
|
|
Accounts payable
|
|
|
20,747
|
|
|
|
3,916
|
|
|
|
$
|
28,620
|
|
|
$
|
(31,856
|
)
|
Compensation to Executive
Officers
Concorde Consulting, a company
owned 100% by Mr. Curtis J. Sparrow, for providing services as Chief Financial Officer to the Company for $11,364 per month (Cdn
$15,000 per month). As of December 31, 2019, the Company did not owe Concorde Consulting any of this amount.
Office Lease
The
Company is currently negotiating a one-year extension to its office lease which expired on June 30, 2019. The Company has paid
the landlord the monthly rentals it understands to be due as the landlord finalizes a lease agreement extension with the Company.
On October 28, 2019, Provident
Premier Master Fund Ltd. (the “Plaintiff”), filed and served an Amended Statement of Claim against Northern Alberta
Oil Ltd., Deep Well Oil & Gas (Alberta) Ltd., Andora Energy Corporation and MP Energy West Canada Corp. (the “Defendants”)
in the Court of Queen’s Bench of Alberta Judicial District of Calgary. The Original Statement of Claim had been filed on
November 1, 2018 but the Company states that it had never been served so the Company was not aware of it. The Plaintiff claims
that on December 12, 2003, Nearshore Petroleum Corporation (“Nearshore”) entered into a royalty agreement with Northern
Alberta Oil Ltd. (“Northern”) in which Northern granted a 6.5% gross overriding royalty (“GORR”) in all
petroleum substances produced, saved and marketed from six of the Company’s oil sands leases located within the Company’s Sawn
Lake properties. The Plaintiff seeks: 1) A declaration that the Plaintiff is the legal owner of 0.67% of the GORR payable on all
oil sands produced from the lands which is payable by one or more of the Defendants; 2) An accounting to determine the amount of
the outstanding royalty of which judgment is estimated by the Plaintiff to be in the amount of $100,000 Cdn; and 3) Interest and
costs.
The Company continues to deny
the validity of the Purported 6.5% Royalty in the first instance. As well, if the Purported 6.5% Royalty was valid, which is denied,
it was not a gross overriding interest, but rather an overriding interest, which allowed for the deduction of operating and marketing
costs. The Company plans to vigorously defend itself against the Plaintiff’s claims. As at December 31, 2019, no contingent
liability has been recorded, as a successful outcome for the Plaintiff is not probable.
|
ITEM
2.
|
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
The
following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes.
For the purpose of this discussion, unless the context indicates another meaning, the terms: “Deep Well,” “Company,”
“we,” “us,” and “our” refer to Deep Well Oil & Gas, Inc. and its subsidiaries. This discussion
includes forward-looking statements that reflect our current views with respect to future events and financial performance that
involve risks and uncertainties. Our actual results, performance or achievements could differ materially from those anticipated
in the forward-looking statements as a result of certain factors including risks discussed in “Cautionary Note Regarding
– Forward-Looking Statements” below and elsewhere in this report, and under the heading “Risk Factors”
and “Environmental Laws and Regulations” disclosed in our Annual Report on Form 10-K for the fiscal year ended September
30, 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.
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.
|
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.
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.
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
|
)
|
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:
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Three months Ended
|
|
|
Year Ended
|
|
|
|
December 31, 2019
|
|
|
September 30, 2019
|
|
Current Assets
|
|
$
|
147,497
|
|
|
$
|
167,379
|
|
Current Liabilities
|
|
|
91,739
|
|
|
|
70,992
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|
Working Capital
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|
$
|
55,758
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|
|
$
|
96,387
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|
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.
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:
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our
current business strategy;
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our
future financial position and projected costs;
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our
projected sources and uses of cash;
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our
plan for future development and operations, including the building of all-weather roads;
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our
drilling and testing plans;
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our
proposed plans for further thermal in-situ development or demonstration project or projects;
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the
sufficiency of our capital in order to execute our business plan;
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our
reserves and resources estimates;
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the
timing and sources of our future funding;
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the
quantity and value of our reserves;
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the
intent to issue a distribution to our shareholders;
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our
or our operator’s objectives and plans for our current SAGD Project;
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our
plans for development of our Sawn Lake properties;
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production
levels from our current SAGD Project;
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costs
of our current SAGD Project;
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●
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funding
from the Farmee to pay our costs for the current SAGD Project in connection with the
Farmout Agreement;
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additional
sources of funding from the Farmout Agreement;
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funding
from the Farmee to cover our monthly operating expenses;
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our
access and availability to third-party infrastructure;
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present
and future production of our properties;
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our
ability to extend our remaining lease; past its primary expiration date; and
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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:
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changes
in general business or economic conditions;
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changes
in governmental legislation or regulation that affect our business;
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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;
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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;
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increase
in taxes and changes to existing legislation affecting governmental royalties or other
governmental initiatives;
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future
marketing and transportation of our produced bitumen;
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our
ability to receive approvals from the AER for additional tests to further evaluate the
wells on our lands;
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our
Farmout Agreement and joint operating agreements;
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opposition
to our regulatory requests by various third parties;
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actions
of aboriginals, environmental activists and other industrial disturbances;
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the
costs of environmental reclamation of our lands;
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availability
of labor or materials or increases in their costs;
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the
availability of sufficient capital to finance our business or development plans on terms
satisfactory to us;
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adverse
weather conditions and natural disasters affecting access to our properties and well
sites;
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risks
associated with increased insurance costs or unavailability of adequate coverage;
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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;
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changes
in labor, equipment and capital costs;
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future
acquisitions or strategic partnerships;
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the
risks and costs inherent in litigation;
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imprecision
in estimates of reserves, resources and recoverable quantities of oil, bitumen and natural
gas;
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product
supply and demand;
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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;
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future
appraisal of potential bitumen, oil and gas properties may involve unprofitable efforts;
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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;
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the
ability to pay future escalating oil sands lease rents on our continued leases;
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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;
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changes
in general business or economic conditions;
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risks
associated with the finding, determination, evaluation, assessment and measurement of
bitumen, oil and gas deposits or reserves;
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geological,
technical, drilling and processing problems;
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third
party performance of obligations under contractual arrangements;
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failure
to obtain industry partner and other third-party consents and approvals, when required;
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treatment
under governmental regulatory regimes and tax laws;
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royalties
payable in respect of bitumen, oil and gas production;
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unanticipated
operating events which can reduce production or cause production to be shut-in or delayed;
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incorrect
assessments of the value of acquisitions, and exploration and development programs;
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stock
market volatility and market valuation of the common shares of our Company;
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fluctuations
in currency and interest rates; and
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the
additional risks and uncertainties, many of which are beyond our control, referred to
elsewhere in this quarterly report and in our other SEC filings.
|
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.