Notes to the Consolidated Financial Statements
September 30, 2018 and 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”).
Deep Well together with its subsidiaries,
Northern Alberta Oil Ltd. and Deep Well Oil & Gas (Alberta) Ltd, (collectively referred to as the “Company”) is
an independent junior oil sands exploration and development company with an existing oil sands land base in the Peace River oil
sands area in Alberta, Canada.
These 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
These consolidated financial statements
are expressed in U.S. dollars and are prepared in accordance with accounting principles generally accepted in the United States
of America (“U.S. GAAP”).
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 herein.
|
2.
|
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
|
Basis of Consolidation
These 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.
Cash and Cash Equivalents
The Company considers all highly
liquid instruments with a maturity of three months or less at the time of issuance to be cash equivalents.
Allowance for Doubtful Accounts
The Company determines allowances
for doubtful accounts based on aging of specific accounts. Accounts receivable are stated at the historical carrying amounts net
of allowances for doubtful accounts and include only the amounts the Company deems to be collectable. The allowance for bad debts
was $nil and $nil at September 30, 2018 and September 30, 2017, respectively.
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. During the 2018 fiscal year, no ceiling test write-downs were recorded for our 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.
Property and Equipment
Property and equipment are stated
at cost less accumulated depreciation. Depreciation expense is computed using the declining balance method over the estimated useful
life of the asset. Only half of the depreciation rate is taken in the year of acquisition. The following is a summary of the depreciation
rates used in computing depreciation expense:
|
|
|
%
|
|
|
Software
|
|
|
100
|
|
|
Computer equipment
|
|
|
55
|
|
|
Portable work camp
|
|
|
30
|
|
|
Vehicles
|
|
|
30
|
|
|
Road Mats
|
|
|
30
|
|
|
Wellhead
|
|
|
25
|
|
|
Office furniture and equipment
|
|
|
20
|
|
|
Oilfield Equipment
|
|
|
20
|
|
|
Tanks
|
|
|
10
|
|
Expenditures for major repairs
and renewals that extend the useful life of the asset are capitalized. Minor repair expenditures are charged to expense as incurred.
Leasehold improvements are amortized over the greater of five years or the remaining life of the lease agreement.
Depreciation, Depletion
and Amortization
-
Capitalized costs within each country are depleted and depreciated on the unit-of-production
method based on the estimated gross proved reserves as determined by independent petroleum engineers. Depletion and depreciation
is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future costs to be incurred
in developing proved reserves, net of estimated salvage value.
Costs of acquiring and evaluating
unproved properties and major development projects are initially excluded from the depletion and depreciation calculation until
it is determined whether or not proved reserves can be assigned to such properties. Costs of unproved properties and major development
projects are transferred to depletable costs based on the percentage of reserves assigned to each project over the expected total
reserves when the project was initiated. These costs are assessed periodically to ascertain whether impairment has occurred.
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 September 30, 2018, and 2017, asset retirement obligations amount to $493,467 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.
Foreign Currency Translation
The functional currency of the
Canadian subsidiaries is the United States dollar. However, the Canadian subsidiaries transact in Canadian dollars. Consequently,
monetary assets and liabilities are remeasured into United States dollars at the exchange rate on the balance sheet date and non-monetary
items are remeasured at the rate of exchange in effect when the assets are acquired or obligations incurred. Revenues and expenses
are remeasured at the average exchange rate prevailing during the period. Foreign currency transaction gains and losses are included
in results of operations.
Accounting Method
The Company recognizes income
and expenses based on the accrual method of accounting.
Dividend Policy
The Company has not yet adopted
a policy regarding payment of dividends.
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 the 2018 fiscal year end the Company has approximately $199,988 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 year ended September 30, 2018 and September 30,
2017, the Company recorded no oil sales.
Income Taxes
The Company utilizes the liability
method of accounting for income taxes. Under the liability method, deferred tax assets and liabilities are determined based on
the differences between financial reporting and the tax bases of the assets and liabilities, and are measured using the enacted
tax rates and laws that will be in effect when the differences are expected to reverse. An allowance against deferred tax assets
is recorded when it is more likely than not that such tax benefits will not be realized.
Due to the uncertainty regarding
the Company’s profitability, a valuation allowance has been recorded against the future tax benefits of its losses and no
net benefit has been recorded in the consolidated financial statements.
Revenue Recognition
The Company is in the business
of exploring for, developing, producing, and selling crude oil. Crude oil revenue is recognized when the product is taken from
the storage tanks on the lease and delivered to the purchaser and title transfers to the purchaser. Payment is generally received
one to three months after the sale has occurred.
Occasionally the Company may sell
specific leases, and the gain or loss associated with these transactions will be shown separately from the profit or loss from
the operations or sales of oil products. Such gain or losses will be measured and recognized when all of the following have occurred:
(1) there is persuasive evidence of an arrangement to sell; (2) the price of the sale is fixed or determinable; (3) the title to
the lease has transferred; and (4) collection is reasonably assured.
Advertising and Market Development
The Company expenses advertising and market development
costs as incurred.
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 8,080,000 potentially dilutive securities excluded from the the diluted earnings per share calculation
because their effect would be antidilutive.
Financial Instruments
Financial instruments include
cash and cash equivalents, accounts receivable, long-term investments, investment in equity securities, accounts payable and accounts
payable - related parties. The fair value of these financial instruments approximates their carrying value because of the short-term
maturity of these items unless otherwise noted. The fair value of the investment in equity securities cannot be determined as the
market value is not readily obtainable. The equity securities are reported using the cost method.
Environmental Requirements
At the report date, environmental
requirements related to the oil properties acquired are unknown and therefore an estimate of any future cost cannot be made.
Share-Based Compensation
The Company accounts for stock
options granted to directors, officers, employees and non-employees using the fair value method of accounting. The fair value of
stock options for directors, officers, employees and their corporate entities are calculated at the date of grant and are expensed
over the vesting period of the options on a straight-line basis. For non-employees, the fair value of the options is measured on
the earlier of the date at which the counterparty performance is complete or the date at which the performance commitment is reached.
The Company uses the Black-Scholes model to calculate the fair value of stock options issued, which requires certain assumptions
to be made at the time the options are awarded, including the expected life of the option, the expected number of granted options
that will vest and the expected future volatility of the stock. The Company reflects estimates of award forfeitures at the time
of grant and revises in subsequent periods, if necessary, when forfeiture rates are expected to change.
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. It may affect the equipment leases. The adoption of this standard is not expected to have
a material impact on the Company’s consolidated financial statements.
Accounting Standard Update No.
2014-09, (“ASU 2014-09”)
Revenue from Customers (Topic 606)
, became effective for us in the period ending September
30, 2018.
No significant adjustment was required as a result of adopting the new revenue standard. The
comparative information has not been restated and continues to be reported under the historic accounting standards in effect for
those periods. The impact of the adoption of the new revenue standard is expected to be immaterial to the Company’s net income
on an ongoing basis.
Estimates and Assumptions
Management uses estimates and
assumptions in preparing financial statements in accordance with generally accepted accounting principles. Those estimates and
assumptions affect the reported amounts of the assets and liabilities, the disclosure of contingent assets and liabilities, and
the reported revenues and expenses. Actual results could vary from the estimates that were used in preparing these consolidated
financial statements.
Significant estimates by management
include valuations of oil properties, valuation of accounts receivable, useful lives of long-lived assets, asset retirement obligations,
valuation of share-based compensation, and the realizability of future income taxes.
|
3.
|
OIL AND GAS PROPERTIES
|
The Company’s oil sands
acreage as of September 30, 2018, covers 37,322 gross acres (29,383 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:
|
(i)
|
Of the Company’s acreage, 20,242 gross acres (13,284 net acres) under five oil sands leases
were set to expiry on July 10, 2018. In November of 2017, the 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 on January 29, 2018, approval was received from Alberta Energy to continue 6,958 gross acres
(1,740 net acres). In June of 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 on July 15, 2018, approval was received from Alberta Energy to continue 5,693 gross acres (5,124 net acres).
The Company has not yet received approval on one continuation application it submitted in June of 2018 to continue another 1,898
gross acres (1,708 net acres). As of September 30, 2018, a total of 5,693 gross acres (4,713 net acres) on five oil sands leases
expired without being continued. These expired lands were primarily areas where the Company was unable to ascertain exploitable
resources. Continued leases have no future expiry dates but are subject to yearly escalating rental payments until they are deemed
to be producing leases.
|
|
(ii)
|
Of the Company’s acreage, 19,610 gross acres (17,649 net acres) under three northern oil
sands leases are set to expire on August 19, 2019. The Company intends to apply for a term extension on these three northern oil
sands leases, however it is not certain if an extension will be granted by Alberta Energy.
|
|
(iii)
|
Of the Company’s acreage, 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 the Company has already met the governmental requirements
for this lease and it will be applying to continue this lease beyond its expiry date.
|
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 September 30, 2018, 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 $)
|
|
|
2019
|
|
$
|
20,874
|
|
|
$
|
27,022
|
|
|
2020
|
|
$
|
20,874
|
|
|
$
|
27,022
|
|
|
2021
|
|
$
|
19,836
|
|
|
$
|
25,678
|
|
|
2022
|
|
$
|
26,835
|
|
|
$
|
34,738
|
|
|
2023
|
|
$
|
23,632
|
|
|
$
|
30,592
|
|
|
Subsequent
|
|
$
|
127,505
|
|
|
$
|
165,058
|
|
The government of Alberta owns
this land and the Company has acquired the rights to perform oil activities on these lands. If the Company meets the conditions
of the leases the Company will then be permitted to drill on and produce oil from the land into perpetuity. These conditions give
the Company until the expiration of the leases to meet the following requirements on its oil sands leases:
|
1)
|
The original requirement was to drill evaluation wells on each section within the lease, however
the Alberta Department of Energy has temporarily relaxed the drilling requirements under section 3(2)(a) of the Oil Sands Tenure
Regulation of the Mines and Minerals Act of Alberta whereby the drilling requirement is now to drill one evaluation well per three
sections; or
|
|
2)
|
drill evaluation wells on at least 60% of the sections within the lease of which 25% of the evaluation
wells must be cored, and acquire and process two miles of seismic data for the remaining undrilled sections within the lease.
|
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 year ended September
30, 2018.
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.
Farmout Agreement
On July 31, 2013, the Company
entered into a Farmout agreement (the “Farmout Agreement”) with an additional joint venture partner (the “Farmee”)
to fund the Company’s share of the Alberta Energy Regulator (“AER”) approved joint Steam Assisted Gravity Drainage
Demonstration project (“SAGD Project”) at the Company’s Sawn Lake heavy oil reservoir in North Central Alberta,
Canada. In accordance with the Farmout Agreement the Farmee has agreed to provide up to $40,000,000 in funding for the Company’s
portion of the costs for the SAGD Project, in return for a net 25% working interest in 12 sections where the Company had a working
interest of 50% (before the execution of the Farmout Agreement). The Farmee will also provide funding to cover monthly operating
expenses of the Company, of which the first such monthly payment began in respect of the month of August 2013 and shall not to
exceed $30,000 per month.
|
4.
|
CAPITALIZATION OF COSTS INCURRED IN OIL AND GAS ACTIVITIES
|
The following table illustrates
capitalized costs relating to oil producing activities for the year ended September 30, 2018 and September 30, 2017:
|
|
|
September 30,
2018
|
|
|
September 30,
2017
|
|
|
Unproved Oil and Gas Properties
|
|
$
|
22,071,787
|
|
|
$
|
21,380,452
|
|
|
Accumulated Depreciation and Depletion
|
|
|
(95,919
|
)
|
|
|
(84,778
|
)
|
|
Net Capitalized Cost
|
|
$
|
21,975,868
|
|
|
$
|
21,295,674
|
|
Depreciation and depletion expenses
for the years ended September 30, 2018 and 2017 were $11,141 and $11,141 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 years
ended September 30, 2018 and September 30, 2017:
|
|
|
September 30,
2018
|
|
|
September 30,
2017
|
|
|
Acquisition of Properties:
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
–
|
|
|
$
|
–
|
|
|
Unproved
|
|
|
38,185
|
|
|
|
142,400
|
|
|
Exploration costs
|
|
|
710,012
|
|
|
|
–
|
|
|
Development costs
|
|
|
–
|
|
|
|
–
|
|
|
6.
|
INVESTMENT IN EQUITY SECURITIES
|
On February 25, 2005, the Company
acquired an interest in Signet Energy Inc. (“Signet” formerly Surge Global Energy, Inc.) as a result of a Farmout Agreement
dated February 25, 2005. Signet amalgamated with Andora Energy Corporation (“Andora”) in 2007.
As of November 19, 2008, the Company
converted its Signet shares into 2,241,558 shares of Andora, which presently represents an equity interest in Andora of approximately
2.24% as of December 31, 2017, which is Andora’s fiscal year end. These shares are carried at a nominal value using the cost
method and their value is included under oil and gas properties on the Company’s balance sheet.
|
7.
|
PROPERTY AND EQUIPMENT
|
|
|
|
September 30, 2018
|
|
|
|
|
|
|
|
Accumulated
|
|
|
Net Book
|
|
|
|
|
Cost
|
|
|
Depreciation
|
|
|
Value
|
|
|
Computer equipment
|
|
$
|
35,689
|
|
|
$
|
34,175
|
|
|
|
1,514
|
|
|
Office furniture and equipment
|
|
|
34,130
|
|
|
|
31,249
|
|
|
|
2,881
|
|
|
Software
|
|
|
5,826
|
|
|
|
5,826
|
|
|
|
–
|
|
|
Leasehold improvements
|
|
|
4,936
|
|
|
|
4,936
|
|
|
|
–
|
|
|
Portable work camp
|
|
|
170,580
|
|
|
|
164,862
|
|
|
|
5,718
|
|
|
Vehicles
|
|
|
38,077
|
|
|
|
38,077
|
|
|
|
–
|
|
|
Oilfield equipment
|
|
|
249,046
|
|
|
|
217,511
|
|
|
|
31,534
|
|
|
Road mats
|
|
|
364,614
|
|
|
|
352,108
|
|
|
|
12,506
|
|
|
Wellhead
|
|
|
3,254
|
|
|
|
3,254
|
|
|
|
–
|
|
|
Tanks
|
|
|
96,085
|
|
|
|
60,721
|
|
|
|
35,364
|
|
|
|
|
$
|
1,002,237
|
|
|
$
|
912,720
|
|
|
|
89,518
|
|
|
|
|
September 30, 2017
|
|
|
|
|
|
|
|
Accumulated
|
|
|
Net Book
|
|
|
|
|
Cost
|
|
|
Depreciation
|
|
|
Value
|
|
|
Computer equipment
|
|
$
|
34,750
|
|
|
$
|
32,899
|
|
|
$
|
1,851
|
|
|
Office furniture and equipment
|
|
|
34,130
|
|
|
|
30,529
|
|
|
|
3,601
|
|
|
Software
|
|
|
5,826
|
|
|
|
5,826
|
|
|
|
–
|
|
|
Leasehold improvements
|
|
|
4,936
|
|
|
|
4,936
|
|
|
|
–
|
|
|
Portable work camp
|
|
|
170,580
|
|
|
|
162,305
|
|
|
|
8,275
|
|
|
Vehicles
|
|
|
38,077
|
|
|
|
38,077
|
|
|
|
–
|
|
|
Oilfield equipment
|
|
|
249,045
|
|
|
|
204,917
|
|
|
|
44,128
|
|
|
Road mats
|
|
|
364,614
|
|
|
|
346,748
|
|
|
|
17,866
|
|
|
Wellhead
|
|
|
3,254
|
|
|
|
2,747
|
|
|
|
507
|
|
|
Tanks
|
|
|
96,085
|
|
|
|
56,793
|
|
|
|
39,292
|
|
|
|
|
$
|
1,001,297
|
|
|
$
|
885,777
|
|
|
$
|
115,520
|
|
There was $26,942 of depreciation
expense for the year ended September 30, 2018 (September 30, 2017 - $48,887).
Long-term investments
consist of cash held in trust by the AER which bears interest at a rate of prime minus 0.375% and has no stated date of maturity.
These investments are required by the AER to ensure there are sufficient future cash flows to meet the expected future asset retirement
obligations and are restricted for this purpose.
|
9.
|
SIGNIFICANT TRANSACTIONS WITH RELATED PARTIES
|
Accounts payable – related
parties were $Nil as of September 30, 2018 (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.
Subscriptions receivable –
related parties was $15,000 as of September 30, 2018 (September 30, 2017 - $Nil) for the amount owed to the Company from one director
for the exercise of his stock options. This amount was subsequently paid to the Company.
As of September 30, 2018, officers,
directors, their families, and their controlled entities have acquired 53.96% of the Company’s outstanding common capital
stock. This percentage does not include unexercised stock options.
The Company incurred expenses
$140,274 to one related party, Concorde Consulting, an entity controlled by a director, for professional fees and consulting services
provided to the Company during the year ended September 30, 2018 (September 30, 2017 - $136,980). These amounts were fully paid
as of September 30, 2018.
|
10.
|
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 September 30, 2018, the Company estimates the undiscounted cash flows related to asset
retirement obligation to total approximately $624,354 (September 30, 2017 - $647,631). The fair value of the liability at September
30, 2018 is estimated to be $493,467 (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:
|
|
|
September 30,
2018
|
|
|
September 30,
2017
|
|
|
Balance, beginning of period
|
|
$
|
493,411
|
|
|
$
|
452,533
|
|
|
Liabilities incurred
|
|
|
–
|
|
|
|
–
|
|
|
Effect of foreign exchange
|
|
|
(17,893
|
)
|
|
|
23,969
|
|
|
Disposal
|
|
|
–
|
|
|
|
–
|
|
|
Accretion expense
|
|
|
17,949
|
|
|
|
16,909
|
|
|
Balance, end of period
|
|
$
|
493,467
|
|
|
$
|
493,411
|
|
As of September 30,
2018, the Company had outstanding 230,574,603 shares of common stock.
Return of Capital Distribution
O
n
August 9, 2013,
the Company approved a distribution to its shareholders in the amount of $0.07 per share to be payable on
September 20, 2013 to the holders of record of all the issued and outstanding shares of common stock of the Company as of the close
of business on August 16, 2013.
This cash distribution to the Company’s shareholders
was not a dividend paid out of the earnings and profits, but was a non-dividend distribution characterized as a “return of
capital”. On June 20, 2018, $245,184 was returned to the Company.
Warrants
On June 20, 2016, warrants to
acquire up to 520,000 common shares of the Company, expired unexercised.
On November 23, 2016, warrants
to acquire up to 52,155,221 common shares of the Company, expired unexercised.
There were no warrants outstanding
as of September 30, 2018 (September 30, 2017 – Nil).
On November 28, 2005, and as amended
on December 4, 2013, the Board of Deep Well adopted the Deep Well Oil & Gas, Inc. Stock Option Plan (the “Plan’).
The Plan was approved by the majority of shareholders at the February 24, 2010 general meeting of shareholders. The Plan, is administered
by the Board, permits options to acquire shares of the Company’s common stock (the “Common Shares”) to be granted
to directors, senior officers and employees of the Company and its subsidiaries, as well as certain consultants and other persons
providing services to the Company or its subsidiaries.
The maximum number of shares,
which may be reserved for issuance under the Plan, may not exceed 10% of the Company’s issued and outstanding Common Shares,
subject to adjustment as contemplated by the Plan. The aggregate number of Common Shares with respect to which options may be vested
to any one person (together with their associates) under the plan, together with all other incentive plans of the Company in any
one year shall not exceed 2% of the total number of Common Shares outstanding, and in total may not exceed 6% of the total number
of Common Shares outstanding.
On March 23, 2016, 900,000 stock
options previously granted on March 23, 2011 to two directors, expired unexercised.
Between June 8 to 10, 2018, five
directors, two contractors and one employee of the Company, exercised a total of 3,150,000 option shares at an exercise price of
$0.05 by way of a cashless exercise to acquire a total of 899,998 common shares of the Company, based upon the market value of
the Company’s common stock of $0.07 per share on June 8, 2018, whereby 2,250,002 common shares were withheld by the Company
to pay for the exercise price of the options.
On June 19, 2018, one director
of the Company acquired 300,000 common shares of the Company upon exercising stock options, at an exercise price of $0.05 per common
share for total gross proceeds to the Company of $15,000.
For the year ended September 30,
2018, the Company recorded no share-based compensation expense related to stock options (September 30, 2017 – $2,314). As
of September 30, 2018, 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 Prices
|
|
Shares Underlying Options Outstanding
|
|
|
Weighted Average Remaining Contractual Life
|
|
|
Weighted Average Exercise Price
|
|
|
Shares Underlying Options Exercisable
|
|
|
Weighted Average Exercise Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$0.30 at September 30, 2018
|
|
|
250,000
|
|
|
|
0.08
|
|
|
|
0.30
|
|
|
|
250,000
|
|
|
|
0.30
|
|
|
$0.34 at September 30, 2018
|
|
|
450,000
|
|
|
|
0.18
|
|
|
|
0.34
|
|
|
|
450,000
|
|
|
|
0.34
|
|
|
$0.38 at September 30, 2018
|
|
|
6,780,000
|
|
|
|
0.97
|
|
|
|
0.38
|
|
|
|
6,780,000
|
|
|
|
0.38
|
|
|
$0.23 at September 30, 2018
|
|
|
600,000
|
|
|
|
1.13
|
|
|
|
0.23
|
|
|
|
600,000
|
|
|
|
0.23
|
|
|
|
|
|
8,080,000
|
|
|
|
0.91
|
|
|
|
0.36
|
|
|
|
8,080,000
|
|
|
|
0.36
|
|
The aggregate intrinsic value
of exercisable options as of September 30, 2018, was $Nil (September 30, 2017 - $Nil).
The following is a summary of stock option activity
as at September 30, 2018:
|
|
|
Number of Underlying Shares
|
|
|
Weighted Average Exercise Price
|
|
|
Weighted Average Fair Market Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2017
|
|
|
11,530,000
|
|
|
$
|
0.27
|
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercised, June 8, 2018
|
|
|
(3,450,000
|
)
|
|
|
0.05
|
|
|
|
0.04
|
|
|
Balance, September 30, 2018
|
|
|
8,080,000
|
|
|
|
0.36
|
|
|
|
0.29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, September 30, 2018
|
|
|
8,080,000
|
|
|
|
0.36
|
|
|
|
0.29
|
|
A summary of the options granted
at September 30, 2018 and 2017 and changes during the periods then ended is presented below:
|
|
|
September 30, 2018
|
|
|
September 30, 2017
|
|
|
|
|
Shares
|
|
|
Weighted Average Exercise Price
|
|
|
Shares
|
|
|
Weighted Average Exercise Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding balance at beginning of period
|
|
|
11,530,000
|
|
|
$
|
0.27
|
|
|
|
11,530,000
|
|
|
$
|
0.27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested - November 17, 2016
|
|
|
|
|
|
|
|
|
|
|
200,000
|
|
|
|
0.23
|
|
|
Exercised, June 8, 2018
|
|
|
(3,450,000
|
)
|
|
|
0.05
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
8,080,000
|
|
|
$
|
0.36
|
|
|
|
11,530,000
|
|
|
$
|
0.27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable
|
|
|
8,080,000
|
|
|
$
|
0.36
|
|
|
|
11,530,000
|
|
|
$
|
0.27
|
|
There were no remaining unvested stock options outstanding
as of September 30, 2018 (September 30, 2017 – Nil).
Measurement Uncertainty for Stock Options
The Company used the Black-Scholes
pricing model (“Black-Scholes”) to value the stock options. This pricing model was developed for use in estimating
the fair value of traded “European” options. The stock options that are granted to employees, directors and consultants
are non-transferable and some vest over time, and are “American” options. This pricing model requires the input of
subjective assumptions including expected share price volatility. The fair value estimate can vary materially as a result of changes
in the assumptions, and therefore can materially affect the calculated fair value of the stock options. The following assumptions
were used in the Black-Scholes pricing model to value the stock options:
Expected Term – Expected
term of 5 years represents the period that the Company’s stock-based awards are expected to be outstanding.
Expected Volatility – Expected
volatilities are based on historical volatility of the Company’s stock, adjusted where determined by management for unusual
and non-representative stock price activity not expected to recur. The expected volatility used ranged from 102% to 122%.
Expected Dividend – The
Black-Scholes valuation model calls for a single expected dividend yield as an input. The Company currently pays no dividends and
does not expect to pay dividends in the foreseeable future.
Risk-Free Interest rate –
The Company bases the risk-free interest rate on the implied yield currently available on U.S. Treasury zero-coupon issues with
an equivalent remaining term. The risk-free rate used ranged from 1.31% to 2.07%.
|
13.
|
CHANGES IN NON-CASH WORKING CAPITAL
|
|
|
|
September 30,
|
|
|
September 30,
|
|
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
$
|
40,372
|
|
|
$
|
(58,715
|
)
|
|
Prepaid expenses
|
|
|
11,346
|
|
|
|
(3,125
|
)
|
|
Accounts payable and accounts payable and accrued liabilities - related party
|
|
|
(121,015
|
)
|
|
|
116,177
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(69,297
|
)
|
|
$
|
54,337
|
|
As of September 30, 2018, the
Company has approximately $6,442,069 (2017 – $6,311,751) of operating losses expiring through 2038 that may be used to offset
future taxable income but are subject to various limitations imposed by rules and regulations of the Internal Revenue Service.
The net operating losses are limited each year to offset future taxable income, if any, due to the change of ownership in the Company's
outstanding shares of common stock. In addition, at September 30, 2018, the Company had an unused Canadian net operating loss carry-forward
of approximately $8,096,433 (2017 – $7,864,432), expiring through 2038. These operating loss carry-forwards may result in
future income tax benefits of approximately $3,538,871. However, because realization is uncertain at this time, a valuation reserve
in the same amount has been established. Deferred income taxes reflect the net tax effects of temporary differences between the
carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.
The components of the net deferred tax asset, the statutory
tax rate, the effective rate and the elected amount of the valuation allowance are as follows:
|
|
|
Year Ended
September 30,
2018
|
|
|
Year Ended
September 30,
2017
|
|
|
Statutory and effective tax rate
|
|
|
|
|
|
|
|
|
|
Domestic
|
|
|
|
|
|
|
|
|
|
Statutory U.S. federal rate
|
|
|
21
|
%
|
|
|
21
|
%
|
|
Foreign
|
|
|
27
|
%
|
|
|
27
|
%
|
|
|
|
Year Ended
September 30, 2018
|
|
|
Year Ended
September 30, 2017
|
|
|
Income taxes recovered at the statutory and effective tax rate
|
|
|
|
|
|
|
|
Domestic
|
|
|
|
|
|
|
|
Statutory U.S. federal rate
|
|
$
|
28,484
|
|
|
$
|
24,570
|
|
|
Foreign
|
|
|
52,513
|
|
|
|
47,547
|
|
|
|
|
|
|
|
|
|
|
|
|
Timing differences:
|
|
|
|
|
|
|
|
|
|
Non-deductible expenses
|
|
|
(21,102
|
)
|
|
|
(14,266
|
)
|
|
Other deductible charges
|
|
|
|
|
|
|
–
|
|
|
Benefit of tax losses not recognized in the year
|
|
|
(59,895
|
)
|
|
|
(57,851
|
)
|
|
Income tax recovery (expense) recognized in the year
|
|
$
|
–
|
|
|
$
|
–
|
|
The approximate tax effects of
each type of temporary difference that gives rise to deferred tax assets are as follows:
|
|
|
Year Ended
September 30, 2018
|
|
|
Year Ended
September 30, 2017
|
|
|
Deferred income tax assets (liabilities)
|
|
|
|
|
|
|
|
Net operating loss carry-forwards
|
|
$
|
3,538,871
|
|
|
$
|
3,448,864
|
|
|
Oil and gas properties
|
|
|
(1,936,342
|
)
|
|
|
(173,294
|
)
|
|
Equipment
|
|
|
209,647
|
|
|
|
200,186
|
|
|
Valuation allowance
|
|
|
(1,812,176
|
)
|
|
|
(3,475,756
|
)
|
|
Net deferred income tax assets
|
|
$
|
–
|
|
|
$
|
–
|
|
In accordance with generally accepted
accounting principles, the Company has analyzed its filing positions in all jurisdictions where it is required to file income tax
returns for the open tax years in such jurisdictions. The Company has identified its federal income tax returns for the previous
five years remain subject to examination. The Company’s income tax returns in state income tax jurisdictions also remain
subject to examination for the previous five years. The Company currently believes that all significant filing positions are highly
certain and that all of its significant income tax filing positions and deductions would be sustained upon audit. Therefore, the
Company has no significant reserves for uncertain tax positions, and no adjustments to such reserves were required by generally
accepted accounting principles. No interest or penalties have been levied against the Company and none are anticipated, therefore
no interest or penalty has been included in the provision for income taxes in the consolidated statements of operations.
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 $11,690 per month (Cdn
$15,000 per month). As of September 30, 2018, 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 effective 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 $
|
|
|
2019 Q1 (October - December)
|
|
$
|
6,156
|
|
|
$
|
7,969
|
|
|
2019 Q2 (January - March)
|
|
$
|
6,156
|
|
|
$
|
7,969
|
|
|
2019 Q3 (April - June)
|
|
$
|
6,156
|
|
|
$
|
7,969
|
|
|
16.
|
CRUDE OIL AND NATURAL GAS PROPERTY INFORMATION (Unaudited)
|
Results of Operations from Oil and Gas Producing
Activities
The following table sets forth
the results of the Company’s operations from oil producing activities from the Company’s Sawn Lake oil sands properties
located in Alberta, Canada, for the years ending September 30, 2018 and 2017:
|
|
|
September 30,
2018
|
|
|
September 30,
2017
|
|
|
Oil sales after royalties
|
|
$
|
–
|
|
|
$
|
–
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (Operating) expenses
|
|
|
–
|
|
|
|
–
|
|
|
Depreciation, accretion and depletion
|
|
|
(54,036
|
)
|
|
|
(75,232
|
)
|
|
Oil sales less expenses
|
|
|
(54,036
|
)
|
|
|
(75,232
|
)
|
|
Income tax expenses
|
|
|
–
|
|
|
|
–
|
|
|
Results of operations from producing activities
|
|
$
|
(54,036
|
)
|
|
$
|
(75,232
|
)
|
There was no production volumes
or revenues for the fiscal years ending September 30, 2018 and 2017, due to a majority of the Company’s Joint Venture partners
voting to temporarily suspend operations of the SAGD Project at the end of February 2016.
Operating expenses are zero since
at this time they were paid for under the Farmout Agreement. Transportation costs are included in these operating costs. The total
share of the material costs and operating expenses of the Company’s joint Steam Assisted Gravity Drainage Demonstration project
(“SAGD Project”), has been funded in accordance with the Farmout Agreement, at a net cost to the Company of $Nil.
As
required by the Farmout Agreement, the Farmee has since reimbursed the Company and or paid the operator in total approximately
$20.8 million (
Cdn $27.0 million) for the SAGD Project for the Farmee’s share and the Company’s
share of the capital costs and operating expenses of the SAGD Project up to
September 30, 2018
.
These costs include the drilling and completion of one SAGD well pair; the purchase and transportation of equipment of which
included the once through steam generator (“OTSG”), 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 and expenditures to connect these water wells with pipelines 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; and the monthly operating expenses
associated with the steaming and production of the SAGD well pair up to September 30, 2018. The capital costs to complete the SAGD
Project steam plant facility with one SAGD well pair was approximately $26.5 million (Cdn $34.8 million) on a 100% working interest
basis, of which the Company’s share was covered under the Farmout Agreement. These capital costs do not include the start-up
operating expenses to initiate oil production from the SAGD well pair.
SAGD Project Outlook -
The
SAGD Project has successfully shown the capability of producing oil from the Bluesky reservoir using steam. 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 steam-oil ratio (“SOR’), of the reservoir;
and
|
|
●
|
provided critical information required for well and facility design associated with future commercial
development.
|
The first SAGD well pair, for
the SAGD Project, was drilled to a vertical depth of approximately 650 meters with a horizontal length of 780 meters each. Steam
injection commenced in May 2014 and production started in September of 2014. Production from this one SAGD well pair increased
significantly over the 18-month period it produced. Over January and February of 2016 production from the SAGD Project averaged
615 bopd, on a 100% basis (154 bopd net to us), with an average SOR of 2.1 from one SAGD well pair. The SOR is reflective of the
amount of steam needed to produce one barrel of oil. This SAGD Project was temporarily suspended at the end of February 2016. The
Company anticipates that a reactivation of the existing SAGD Project facility and current SAGD well pair will be part of a potential
commercial expansion. In early May of 2016, an amended application was submitted to the Alberta Energy Regulator (“AER”)
for an expansion of the existing SAGD Project facility site which would potentially increase the operation for up to a total of
eight SAGD well pairs. This expansion application sought approval to expand the current SAGD Project facility site to 3,200 bopd
(100% basis). The Company anticipates that only five SAGD well pairs will need to be operating to achieve this production level.
The expanded facility will be designed to handle up to 3,200 bopd. The AER approval for this expansion of the Company’s existing
SAGD Project was granted in December of 2017. While the joint venture has not yet approved to expand the SAGD Project facility,
currently the SAGD Project continues to move forward with engineering and identification of long lead time items towards potential
expansion to 3,200 bopd and future commercial development at Sawn Lake.
Capitalized Costs Relating Specifically to the
SAGD Project
The Company entered into a Farmout
Agreement dated July 31, 2013, whereby the Company’s operating costs of the SAGD Project are paid in full by the Farmee in
accordance with the Farmout Agreement; therefore, the Company has not capitalized any of the capital costs and operating expenses
paid by the Farmee to the operator of the SAGD Project.
See Note 4 herein “
Capitalization
of Costs Incurred in Oil and Gas Activities”.
Costs Incurred in Oil and Gas Property Acquisition,
Exploration, and Development
See
Note 5 herein “
Exploration Activities”.