Notes
to the Condensed Consolidated Financial Statements
December
31, 2017
|
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, 2017.
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, 2017.
|
2.
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
Basis
of Consolidation
These
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, 2017, 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, 2017, and September 30, 2017, asset retirement obligations
amount to $495,414 and $493,411, 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, 2017, the Company has approximately $41,352 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, 2017 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 11,530,000 potentially dilutive securities excluded from the the diluted
earnings per share calculation because their effect would be antidilutive.
Recently
Adopted Accounting Standards
In
August 2015, the FASB issued ASU 2015-14, “Revenue from Contracts with Customers (Topic 606) — Deferral of the Effective
Date.” ASU 2015-14 defers the effective date of ASU 2014-09 by one year to annual reporting periods beginning after December
15, 2017 with early adoption permitted for periods beginning after December 15, 2016. The adoption of this standard is not expected
to have a material impact on the Company’s consolidated financial statements.
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.
The adoption of this standard is not expected to have a material impact on the Company’s consolidated financial statements.
The
Company does not expect the adoption of any other recent accounting pronouncements to have a material impact on the Company’s
financial statements.
|
3.
|
OIL
AND GAS PROPERTIES
|
The
Company’s oil sands acreage as of December 31, 2017, covers 43,015 gross acres (34,096 net acres) of land under nine oil
sands leases. Until the Company extends the leases “into perpetuity” based on the Alberta governmental regulations,
the lease expiration dates of the Company’s nine oil sands leases are as follows:
|
1)
|
32
sections of land under five oil sands leases are set to expire on July 10, 2018. 17 out
of 32 sections contain the majority of the resources identified to date on these five
oil sands leases. The Company has completed or is in the process of applying for continuation
of these leases or parts of the leases where the majority of the oil sands resources
have been confirmed. Currently, 11 out of the 17 sections that contain the majority of
the resources identified to date have been granted continuance under the Alberta governmental
tenure guidelines;
|
|
2)
|
31
sections of land under three oil sands leases are set to expire on August 19, 2019; and
|
|
3)
|
5
sections of land under one oil sands lease are set expire on April 9, 2024. It is the
Company’s opinion that the Company has already met the governmental requirements
for this lease and it will be applying to continue all 5 sections of this lease into
perpetuity.
|
On
November 21, 2017, the Company’s joint venture partner and operator of two jointly held oil sands leases, where the Company
has working interests, submitted two continuation applications to the Alberta Oil Sands Tenure division to apply to continue two
oil sands leases that were set to expire on July 10, 2018. On January 29, 2018, the Company’s joint venture partner received
approval from Alberta Energy, under the Alberta Oil Sands Tenure Regulation, to continue 2,816 gross hectares (704 hectares net
to the Company) of lands, with a non-producing status, effective July 10, 2018. These two continued leases have no future expiry
dates but are subject to yearly escalating rental payments until they are deemed to be producing leases.
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, 2017, 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 as:
|
|
|
(USD $)
|
|
|
(Cdn $)
|
|
|
2018
|
|
$
|
24,878
|
|
|
$
|
31,211
|
|
|
2019
|
|
$
|
21,539
|
|
|
$
|
27,022
|
|
|
2020
|
|
$
|
21,539
|
|
|
$
|
27,022
|
|
|
2021
|
|
$
|
20,468
|
|
|
$
|
25,678
|
|
|
2022
|
|
$
|
27,689
|
|
|
$
|
34,738
|
|
|
Subsequent
|
|
$
|
155,953
|
|
|
$
|
195,650
|
|
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.
This
consists of comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest
costs. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable
assumptions. Proven oil properties are reviewed for any write down on a field-by-field basis. No write downs were recognized for
the period ended December 31, 2017.
Capitalized
costs of proven oil properties will be depleted using the unit-of-production method when the property is placed in production.
Substantially
all 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, 2017
and the fiscal year ended September 30, 2017:
|
|
|
December 31,
2017
|
|
|
September 30,
2017
|
|
|
Unproved Oil and Gas Properties
|
|
$
|
21,414,428
|
|
|
$
|
21,380,452
|
|
|
Proved Oil and Gas Properties
|
|
|
–
|
|
|
|
–
|
|
|
Accumulated Depreciation and Depletion
|
|
|
(87,563
|
)
|
|
|
(84,778
|
)
|
|
Net Capitalized Cost
|
|
$
|
21,326,865
|
|
|
$
|
21,295,674
|
|
Depreciation
and depletion expense for the three months ended December 31, 2017 and 2016 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, 2017 and the fiscal year ended September 30, 2017:
|
|
|
December 31,
2017
|
|
|
September 30,
2017
|
|
|
Acquisition of Properties:
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
–
|
|
|
$
|
–
|
|
|
Unproved
|
|
$
|
8,525
|
|
|
$
|
142,400
|
|
|
Exploration costs
|
|
$
|
64,474
|
|
|
$
|
–
|
|
|
Development costs
|
|
$
|
–
|
|
|
$
|
–
|
|
|
6.
|
SIGNIFICANT
TRANSACTIONS WITH RELATED PARTIES
|
Accounts
payable – related parties was $4,584 as of December 31, 2017 (September 30, 2017 - $9,934) 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, 2017, officers, directors, their families, and their controlled entities have acquired 53.63% of the Company’s
outstanding common capital stock. This percentage does not include unexercised warrants or stock options.
The
Company incurred expenses $35,402 to one related party, Concorde Consulting, and entity controlled by a director, for professional
fees and consulting services provided to the Company during the period ended December 31, 2017 (December 31, 2016 - $33,516).
These amounts were fully paid as of December 31, 2017.
|
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, 2017, the Company estimates the undiscounted
cash flows related to asset retirement obligation to total approximately $644,236 (September 30, 2017 - $647,631). The fair value
of the liability at December 31, 2017 is estimated to be $495,414 (September 30, 2017 - $493,411) 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 25 years.
Changes
to the asset retirement obligation were as follows:
|
|
|
December 31,
2017
|
|
|
September 30,
2017
|
|
|
Balance, beginning of period
|
|
$
|
493,411
|
|
|
$
|
452,533
|
|
|
Liabilities incurred
|
|
|
–
|
|
|
|
–
|
|
|
Effect of foreign exchange
|
|
|
(2,526
|
)
|
|
|
23,969
|
|
|
Disposal
|
|
|
–
|
|
|
|
–
|
|
|
Accretion expense
|
|
|
4,529
|
|
|
|
16,909
|
|
|
Balance, end of period
|
|
$
|
495,414
|
|
|
$
|
493,411
|
|
Common
Stock Issued and Outstanding
As
of December 31, 2017, the Company had outstanding 229,374,605 shares of common stock.
For
the period ended December 31, 2017, the Company recorded no share-based compensation expense related to stock options (September
30, 2017 – $2,314). As of December 31, 2017, there was no unrecognized compensation cost related to option awards. Compensation
expense is based upon straight-line depreciation of the grant-date fair value over the vesting period of the underlying unit option.
|
|
|
Shares Underlying
Options Outstanding
|
|
|
Shares Underlying
Options Exercisable
|
|
|
Range of Exercise Price
|
|
Shares
Underlying
Options
Outstanding
|
|
|
Weighted
Average
Remaining
Contractual
Life
|
|
|
Weighted
Average
Exercise
Price
|
|
|
Shares
Underlying
Options
Exercisable
|
|
|
Weighted
Average
Exercise
Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$0.05 at December 31, 2017
|
|
|
3,450,000
|
|
|
|
0.47
|
|
|
|
0.05
|
|
|
|
3,450,000
|
|
|
|
0.05
|
|
|
$0.30 at December 31, 2017
|
|
|
250,000
|
|
|
|
0.82
|
|
|
|
0.30
|
|
|
|
250,000
|
|
|
|
0.30
|
|
|
$0.34 at December 31, 2017
|
|
|
450,000
|
|
|
|
0.93
|
|
|
|
0.34
|
|
|
|
450,000
|
|
|
|
0.34
|
|
|
$0.38 at December 31, 2017
|
|
|
6,780,000
|
|
|
|
1.72
|
|
|
|
0.38
|
|
|
|
6,780,000
|
|
|
|
0.38
|
|
|
$0.23 at December 31, 2017
|
|
|
600,000
|
|
|
|
1.88
|
|
|
|
0.23
|
|
|
|
600,000
|
|
|
|
0.23
|
|
|
|
|
|
11,530,000
|
|
|
|
1.30
|
|
|
$
|
0.27
|
|
|
|
11,530,000
|
|
|
$
|
0.27
|
|
The
aggregate intrinsic value of exercisable options as of December 31, 2017, was $Nil (September 30, 2017 - $Nil).
The
following is a summary of stock option activity as at December 31, 2017:
|
|
|
Number of
Underlying
Shares
|
|
|
Weighted
Average Exercise
Price
|
|
|
Weighted
Average Fair
Market Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2017
|
|
|
11,530,000
|
|
|
$
|
0.27
|
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2017
|
|
|
11,530,000
|
|
|
$
|
0.27
|
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, December 31, 2017
|
|
|
11,530,000
|
|
|
$
|
0.27
|
|
|
$
|
0.22
|
|
There
were no remaining unvested stock options outstanding as of December 31, 2017 (September 30, 2017 – Nil).
|
10.
|
CHANGES
IN NON-CASH WORKING CAPITAL
|
|
|
|
Three Months Ended
|
|
|
Three Months Ended
|
|
|
|
|
December 31,
2017
|
|
|
December 31,
2016
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
$
|
30,749
|
|
|
$
|
(57,952
|
)
|
|
Prepaid expenses
|
|
|
(613
|
)
|
|
|
5,756
|
|
|
Accounts payable
|
|
|
(17,092
|
)
|
|
|
(4,976
|
)
|
|
|
|
$
|
13,044
|
|
|
$
|
(57,172
|
)
|
Compensation
to Directors
Concorde
Consulting, a company owned 100% by Mr. Curtis J. Sparrow, for providing services as Chief Financial Officer to the Company for
$11,801 per month (Cdn $15,000 per month). As of December 31, 2017, the Company did not owe Concorde Consulting any of this amount.
Rental
Agreement
On
June 19, 2017, the Company renewed its Edmonton office lease commencing effective on July 1, 2017 and expiring on June 30, 2019.
As part of the lease renewal the Company received the first 3 months of basic rent free. The quarterly payments due are as follows:
|
|
|
USD $
|
|
|
Cdn $
|
|
|
2018 Q2 (January - March)
|
|
$
|
6,352
|
|
|
$
|
7,969
|
|
|
2018 Q3 (April - June)
|
|
$
|
6,352
|
|
|
$
|
7,969
|
|
|
2018 Q4 (July - September)
|
|
$
|
6,352
|
|
|
$
|
7,969
|
|
|
2019 Q1 (October - December)
|
|
$
|
6,352
|
|
|
$
|
7,969
|
|
|
2019 Q2 (January - March)
|
|
$
|
6,352
|
|
|
$
|
7,969
|
|
|
2019 Q3 (April - June)
|
|
$
|
6,352
|
|
|
$
|
7,969
|
|
On
February 15, 2018, the Company participated in a well on one of its oil sands leases to acquire cores and logs through the Bluesky
formation, whereby the Company paid, to a third-party operator, a cash contribution of $395,500 ($500,000 Cdn). The Company and
its advisors are currently analyzing the cores and logs.