Notes
to the Consolidated Financial Statements
September
30, 2015 and 2014
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.
Change
in Accounting Principle
During
the fourth quarter of 2015, the Company voluntarily changed its method of accounting for its oil and gas properties from the successful
efforts method to the full cost method. Accordingly, financial information for prior periods has been recast to reflect retrospective
application of the full cost method. The Company believes that the full cost method is preferable as it reflects the results of
the Company’s operations and the economics of exploring for and developing its non-traditional long life oil sands assets
in the Peace River oil sands area in Alberta, Canada. The Company’s consolidated financial statements have been recast to
reflect these differences.
The
following tables present the effects of the change to the full cost method on the consolidated statement of operations:
Year
ended September 30, 2015
|
|
|
As reported under the successful efforts
method
|
|
|
As reported under the full cost method
|
|
|
Effect of change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
$
|
1,867,619
|
|
|
$
|
1,821,528
|
|
|
$
|
(46,091
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, accretion and depletion
|
|
$
|
86,835
|
|
|
$
|
81,762
|
|
|
$
|
(5,073
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from operations
|
|
|
(1,954,454
|
)
|
|
|
(1,903,290
|
)
|
|
|
51,164
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss and comprehensive loss
|
|
$
|
(1,935,831
|
)
|
|
$
|
(1,884,667
|
)
|
|
$
|
51,164
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
–
|
|
Year
ended September 30, 2014
|
|
|
As reported under the successful efforts
method
|
|
|
As reported under the full cost method
|
|
|
Effect of change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
$
|
1,970,824
|
|
|
$
|
1,926,422
|
|
|
$
|
(44,402
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from operations
|
|
|
(2,071,433
|
)
|
|
|
(2,027,031
|
)
|
|
|
44,402
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss and comprehensive loss
|
|
$
|
(2,040,260
|
)
|
|
$
|
(1,995,858
|
)
|
|
$
|
44,402
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted
|
|
$
|
(0.01
|
)
|
|
$
|
(0.01
|
)
|
|
$
|
–
|
|
The
following tables present the effects of the change to the full cost method on the consolidated balance sheet:
Year
ended September 30, 2015
|
|
|
As
reported under the successful efforts method
|
|
|
As
reported under the full cost method
|
|
|
Effect of change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties, net
|
|
$
|
19,677,912
|
|
|
$
|
20,981,652
|
|
|
$
|
1,303,740
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
22,380,653
|
|
|
$
|
23,684,393
|
|
|
$
|
1,303,740
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated deficit
|
|
|
(20,714,197
|
)
|
|
|
(19,853,519
|
)
|
|
|
860,678
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Shareholders’ Equity
|
|
|
21,677,122
|
|
|
|
22,980,862
|
|
|
|
1,303,740
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILTIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
22,380,653
|
|
|
$
|
23,684,393
|
|
|
$
|
1,303,740
|
|
Year
ended September 30, 2014
|
|
|
As reported under the successful efforts
method
|
|
|
As reported under the full cost method
|
|
|
Effect of change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
Oil and gas properties, net
|
|
$
|
19,604,050
|
|
|
$
|
20,856,626
|
|
|
$
|
1,252,576
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
23,691,595
|
|
|
$
|
24,944,171
|
|
|
$
|
1,252,576
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated deficit
|
|
|
(18,778,366
|
)
|
|
|
(17,525,790
|
)
|
|
|
1,252,576
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Shareholders’ Equity
|
|
|
22,491,407
|
|
|
|
23,743,983
|
|
|
|
1,252,576
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILTIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
23,691,595
|
|
|
$
|
24,944,171
|
|
|
$
|
1,252,576
|
|
The
following tables present the effects of the change to the full cost method on the consolidated statement of cash flows:
Year
ended September 30, 2015
|
|
|
As
reported under
the
successful efforts method
|
|
|
As
reported under the
full cost method
|
|
|
Effect
of change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flows from operating activities
|
|
|
|
|
|
|
|
|
|
|
Net
loss
|
|
$
|
(1,935,831
|
)
|
|
$
|
(1,884,667
|
)
|
|
$
|
51,164
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
accretion and depletion
|
|
$
|
86,835
|
|
|
$
|
81,762
|
|
|
$
|
(5,073
|
)
|
|
Cash
used in operating activities
|
|
$
|
(432,259
|
)
|
|
$
|
(386,168
|
)
|
|
$
|
46,091
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment
in oil and gas properties
|
|
$
|
(147,875
|
)
|
|
$
|
(193,966
|
)
|
|
$
|
(46,091
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
used in investing activities
|
|
$
|
(111,228
|
)
|
|
$
|
(157,319
|
)
|
|
$
|
(46,091
|
)
|
Year
ended September 30, 2014
|
|
|
As reported under the successful efforts
method
|
|
|
As reported under the full cost method
|
|
|
Effect of change
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from operating activities
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(2,040,260
|
)
|
|
$
|
(1,995,858
|
)
|
|
$
|
44,402
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in operating activities
|
|
$
|
(1,363,537
|
)
|
|
$
|
(1,319,135
|
)
|
|
$
|
44,402
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in oil and gas properties
|
|
$
|
(3,672,309
|
)
|
|
$
|
(3,716,711
|
)
|
|
$
|
(44,402
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in investing activities
|
|
$
|
(3,755,217
|
)
|
|
$
|
(3,799,619
|
)
|
|
$
|
(44,402
|
)
|
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.
Accounts
Receivable, net
As
of September 30, 2014, accounts receivable included a prepayment by the Company of $1,075,440 ($1,200,000 Cdn) that the Company
subsequently collected from Farmout partner on October 21, 2014.
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, 2015 and September 30, 2014, 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 2015 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 at September 30, 2015 and 2014, asset retirement obligations amount
to $426,607 and $469,013, 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 2015 fiscal year end the Company has approximately $863,334 funds that
are in excess of deposit insurance limits, which may have been adjusted to 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 years ended September
30, 2015 and 2014, the Company has recorded oil sales received from the operator of the Company’s producing properties.
The Company’s joint venture partner is the operator of the Company’s producing properties and it is the Company’s
joint venture partner who sells 100% of the Company’s oil production to 11 purchasers in the oil and gas industry. The Company
does not require collateral and management periodically evaluates the operator’s financial statements and the collectability
of oil sales receivables from the operator and believes that the Company’s oil sales receivables are fully collectable and
that the risk of loss is minimal.
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 Income (Loss) Per Share
Basic
net income (loss) per share amounts are computed based on the weighted average number of shares actually outstanding. Diluted
net income (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 65,105,221 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 and employees 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
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.
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, 2015, covers 43,015 gross acres (34,096 net acres) on 68 sections 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)
|
32
sections of land under 5 oil sands leases are set to expire on July 10, 2018. It is the
Company’s opinion that the Company has already met the governmental requirements
on two of these leases and it will be applying to continue these two leases into perpetuity;
|
|
(ii)
|
31
sections of land under 3 oil sands leases are set to expire on August 19, 2019; and
|
|
(iii)
|
5
sections of land under 1 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 this lease into perpetuity.
|
Effective
September 25, 2014, the Company, through its subsidiary Deep Well Alberta, entered into a Purchase and Sale agreement with Classic
Energy Inc. (“Classic”), pursuant to which the Company acquired Classic’s 20% working interest in five sections
in one Sawn Lake oil sands lease where the Company already owned working interests. As of September 25, 2014, the Company increased
its net acres in the Sawn Lake oil sands properties from 33,463 to 34,096 net acres.
Lease
Rental Commitments
The
Company has acquired interests in certain oil sands properties located in North Central Alberta, Canada. The terms include certain
commitments related to oil sands properties that require the payments of rents as long as the leases are non-producing. As of
September 30, 2015, the Company’s net payments due under this commitment are as follows:
|
|
|
(USD $)
|
|
|
(Cdn $)
|
|
|
2016
|
|
$
|
36,008
|
|
|
|
48,294
|
|
|
2017
|
|
$
|
36,008
|
|
|
|
48,294
|
|
|
2018
|
|
$
|
36,008
|
|
|
|
48,294
|
|
|
2019
|
|
$
|
21,979
|
|
|
|
29,478
|
|
|
2020
|
|
$
|
3,340
|
|
|
|
4,480
|
|
|
Subsequent
|
|
$
|
13,361
|
|
|
|
17,920
|
|
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
Alberta Department of Energy has relaxed the drilling requirements under section 3(2)(a)
option 1 of the Oil Sands Tenure Regulation of the Mines and Minerals Act of Alberta.
Under the relaxed rules the Company would now have to drill 26 wells throughout the 68
sections to preserve
all
of the Company’s nine oil sands leases; or
|
|
2)
|
drill
44 wells within the 68 sections and having acquired and processed two miles of seismic
on each other undrilled section.
|
With
the revised requirements the Company now plans to meet the first of these conditions. As at September 30, 2015 and 2014, out of
the 26 wells to be drilled in option 1 above, the Company has an interest in ten wells which it has drilled, logged and cored,
which can be counted towards these requirements, and in addition the Company has also identified three other wells drilled and
logged through the oil sands zone by others who own or owned the rights to explore zones deeper than the Company’s Bluesky
zone where the Company has oil sands rights. The wells drilled by others may be included in the satisfaction of these requirements
under option 1 above. Therefore, under option 1 above the Company may have to drill up to another 13 wells to preserve
all
of the 68 sections. In the event the Company does not drill all or part of the 13 wells the Company can also elect to retain
a portion of each lease where the Company has identified the reservoir and has completed the amount of work to retain that portion
of the lease. Presently, without drilling any more wells it is the Company’s opinion that under the newer rules the Company
can retain about 67% of the lands where the Company has already identified resources.
In
the event that the Company uses option 2 above, the Company has also acquired and processed 25 miles of seismic on the leases,
which can be counted towards the option 2 requirements. The Company’s joint venture partner and operator of the SAGD Project
has also acquired additional seismic that can be used towards the requirements under option 2 above.
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, 2015 (September 30, 2014 - $nil).
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
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. In addition,
until December 31, 2015, as amended on November 17, 2014, the Farmee has the option to elect to obtain a working interest of 45%
to 50% working interest in the remaining 56 sections of land where the Company has working interests ranging from 90% to 100%,
by committing an additional $110,000,000 of financing to the development of the Company’s Sawn Lake oil sands properties.
As of the date of the options expiration, December 31, 2015, the Farmee did not exercise its option to acquire such interests.
Acquisition
of Royalty Interests
On
March 18, 2014 and June 27, 2014, the Company, through its 100% wholly owned subsidiary company Northern Alberta Oil Ltd., entered
into and subsequently closed two Acquisition of Royalty Interest Agreements and General Indenture of Conveyance, Assignment and
Transfer Agreements (collectively the “Agreements”), with the Company’s joint venture partner (“JV Partner”)
and one related party (Mr. Malik Youyou), whereby the Company acquired and cancelled 5.5% of a disputed 6.5% overriding royalty
claim (the “Purported 6.5% Royalty”) potentially on some lands owned by the Company. The Company’s counsel and
vendor’s counsel negotiated the terms and conditions of both the “Acquisition of Royalty Interest” and “General
Indenture of Conveyance, Assignment and Transfer” agreements. Although the Company does not confirm the validity of the
Purported 6.5% Royalty, the Company determined that it was in the best interests of its shareholders to come to an arrangement
to acquire and cancel most of the Purported 6.5% Royalty to prevent a potential encumbrance over its land or the possibility of
future litigation resulting from these alleged royalty claims. Pursuant to the terms and conditions of the Agreements to acquire
the purported overriding royalty interest claims, the Company paid the following consideration:
|
(i)
|
US
$2,435,124 (Cdn $2,697,600) was paid to the JV Partner for the purchase and transfer
of an undivided 3% interest out of the Purported 6.5% Royalty. The consideration paid
was the original cost (in Canadian dollars) that the JV Partner paid to acquire its 3%
interest in the Purported 6.5% Royalty.
|
|
(ii)
|
US
$1,007,000 was paid to Mr. Malik Youyou, who is a director and majority shareholder of
the Company, for the purchase and transfer of an undivided 2.5% interest out of the Purported
6.5% Royalty. The consideration paid was for the reimbursement of the original cost (in
US dollars) that Mr. Youyou paid to acquire this 2.5% interest in the Purported 6.5%
Royalty from an arm’s length third party.
|
|
4.
|
CAPITALIZATION
OF COSTS INCURRED IN OIL AND GAS ACTIVITIES
|
The
following table illustrates capitalized costs relating to oil producing activities as of September 30, 2015 and September 30,
2014:
|
|
|
September 30,
2015
|
|
|
September 30,
2014
|
|
|
Unproved Oil and Gas Properties
|
|
$
|
21,044,015
|
|
|
$
|
20,903,872
|
|
|
Proved Oil and Gas Properties
|
|
|
–
|
|
|
|
4,568
|
|
|
Accumulated Depreciation and Depletion
|
|
|
(62,363
|
)
|
|
|
(51,814
|
)
|
|
Net Capitalized Cost
|
|
$
|
20,981,652
|
|
|
$
|
20,856,626
|
|
Depreciation
and depletion expense for the years ended September 30, 2015 and 2014 were $10,549 and $10,067 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, 2015 and September 30, 2014:
|
|
|
September 30,
2015
|
|
|
September 30,
2014
|
|
|
Acquisition of Properties:
|
|
|
|
|
|
|
|
Proved
|
|
$
|
–
|
|
|
$
|
–
|
|
|
Unproved
|
|
|
135,575
|
|
|
|
3,736,748
|
|
|
Exploration costs
|
|
|
46,351
|
|
|
|
47,182
|
|
|
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, 2014, 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, 2015
|
|
|
|
|
|
|
|
Accumulated
|
|
|
Net Book
|
|
|
|
|
Cost
|
|
|
Depreciation
|
|
|
Value
|
|
|
Computer equipment
|
|
$
|
32,198
|
|
|
$
|
31,834
|
|
|
$
|
364
|
|
|
Office furniture and equipment
|
|
|
34,130
|
|
|
|
28,412
|
|
|
|
5,718
|
|
|
Software
|
|
|
5,826
|
|
|
|
5,826
|
|
|
|
–
|
|
|
Leasehold improvements
|
|
|
4,936
|
|
|
|
4,936
|
|
|
|
–
|
|
|
Portable work camp
|
|
|
170,580
|
|
|
|
153,585
|
|
|
|
16,995
|
|
|
Vehicles
|
|
|
38,077
|
|
|
|
34,269
|
|
|
|
3,808
|
|
|
Oilfield equipment
|
|
|
249,045
|
|
|
|
157,833
|
|
|
|
91,212
|
|
|
Road mats
|
|
|
364,614
|
|
|
|
328,152
|
|
|
|
36,462
|
|
|
Wellhead
|
|
|
3,254
|
|
|
|
2,353
|
|
|
|
901
|
|
|
Tanks
|
|
|
96,085
|
|
|
|
47,575
|
|
|
|
48,510
|
|
|
|
|
$
|
998,745
|
|
|
$
|
794,775
|
|
|
$
|
203,970
|
|
|
|
|
September 30, 2014
|
|
|
|
|
|
|
|
Accumulated
|
|
|
Net Book
|
|
|
|
|
Cost
|
|
|
Depreciation
|
|
|
Value
|
|
|
Computer equipment
|
|
$
|
32,198
|
|
|
$
|
31,264
|
|
|
$
|
934
|
|
|
Office furniture and equipment
|
|
|
34,130
|
|
|
|
26,880
|
|
|
|
7,250
|
|
|
Software
|
|
|
5,826
|
|
|
|
5,826
|
|
|
|
–
|
|
|
Leasehold improvements
|
|
|
4,936
|
|
|
|
4,936
|
|
|
|
–
|
|
|
Portable work camp
|
|
|
170,580
|
|
|
|
146,211
|
|
|
|
24,369
|
|
|
Vehicles
|
|
|
38,077
|
|
|
|
32,637
|
|
|
|
5,440
|
|
|
Oilfield equipment
|
|
|
249,045
|
|
|
|
135,030
|
|
|
|
114,015
|
|
|
Road mats
|
|
|
364,614
|
|
|
|
312,525
|
|
|
|
52,089
|
|
|
Wellhead
|
|
|
3,254
|
|
|
|
2,053
|
|
|
|
1,201
|
|
|
Tanks
|
|
|
96,085
|
|
|
|
42,185
|
|
|
|
53,900
|
|
|
|
|
$
|
998,745
|
|
|
$
|
739,547
|
|
|
$
|
259,198
|
|
There
was $55,228 of depreciation expense for the year ended September 30, 2015 (September 30, 2014 - $72,956).
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 was $4,833 as of September 30, 2015 (September 30, 2014 - $16,977) for expenses to be reimbursed
to directors. This amount is unsecured, non-interest bearing, and has no fixed terms of repayment.
As
of September 30, 2015, 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 $147,006 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, 2015 (September 30, 2014 - $198,703).
These amounts were fully paid as of September 30, 2015.
As
of June 27, 2014, $1,007,000 was paid to Mr. Malik Youyou, who is a director and majority shareholder of the Company, for the
purchase and transfer of an undivided 2.5% interest out of the Purported 6.5% Royalty. The consideration paid was for the reimbursement
of the original cost (in US Dollars) that Mr. Youyou paid to acquire this 2.5% interest in the Purported 6.5% Royalty from a third
party based on that third parties alleged costs.
As
of June 30, 2013, the Company received a loan for $260,000 as a note payable from one of the Company’s directors. On August
15, 2013, the loan payable was offset by the amount of $70,500 for exercising that director’s stock options reducing the
total loan payable to $189,500 as of September 30, 2013. In November 2013, this note payable in the amount of $189,500, from one
of the Company’s directors, was fully paid.
|
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, 2015, the Company estimates the undiscounted
cash flows related to asset retirement obligation to total approximately $602,613 (September 30, 2014 - $ 689,445). The fair value
of the liability at September 30, 2015 is estimated to be $426,607 (September 30, 2014 - $ 469,013) 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 28 years.
Changes
to the asset retirement obligation were as follows:
|
|
|
September 30,
2015
|
|
|
September 30,
2014
|
|
|
Balance, beginning of period
|
|
$
|
469,013
|
|
|
$
|
446,155
|
|
|
Liabilities incurred
|
|
|
35,031
|
|
|
|
73,395
|
|
|
Effect of foreign exchange
|
|
|
(93,421
|
)
|
|
|
(64,079
|
)
|
|
Disposal
|
|
|
–
|
|
|
|
(4,045
|
)
|
|
Accretion expense
|
|
|
15,984
|
|
|
|
17,587
|
|
|
Balance, end of period
|
|
$
|
426,607
|
|
|
$
|
469,013
|
|
As
of September 30, 2015, the Company had outstanding 229,374,605 shares of common stock.
Warrants
On
June 23, 2014, 47,618 common share purchase warrants were transferred to a non-related party.
On
October 3, 2014, a warrant holder of the Company acquired 47,618 shares of the Company’s common stock, upon exercising warrants,
at an exercise price of $0.105 per share of common stock for gross proceeds to the Company of $5,000.
On
July 28, 2015, the Company’s Board approved the extension of the expiration date of some warrants to purchase shares of
the Company’s common stock. The exercise price of the warrants remained unchanged at $0.105 per share. As a result of this
extension, the expiration dates of the warrants were amended from the original expiry date of November 23, 2015 to November 23,
2016, with all other terms of the original warrants remaining in full force and effect. In consideration of extending the expiry
date of this series of warrants, the number of outstanding warrants was reduced from 71,857,141 to 52,155,221 common share purchase
warrants.
The
Company valued the affected warrants immediately before and after the warrants modification. The value of the warrants after the
modification was increased by $443,062, resulting in an accounting adjustment to additional paid-in capital and accumulated deficit
in the consolidated statements of shareholders’ equity.
The
following table summarizes the Company’s warrants outstanding as of September 30, 2015:
|
|
|
Shares Underlying
Warrants Outstanding
|
|
|
Shares Underlying
Warrants Exercisable
|
|
|
Range of Exercise Price
|
|
Shares Underlying Warrants Outstanding
|
|
|
Weighted Average Remaining Contractual Life
|
|
|
Weighted Average Exercise Price
|
|
|
Shares Underlying Warrants Exercisable
|
|
|
Weighted Average Exercise Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$0.105 at September 30, 2015
|
|
|
52,155,221
|
|
|
|
1.15
|
|
|
$
|
0.105
|
|
|
|
52,155,221
|
|
|
$
|
0.105
|
|
|
$0.075 at September 30, 2015
|
|
|
520,000
|
|
|
|
0.72
|
|
|
|
0.075
|
|
|
|
520,000
|
|
|
|
0.075
|
|
|
|
|
|
52,675,221
|
|
|
|
1.15
|
|
|
$
|
0.105
|
|
|
|
52,675,221
|
|
|
$
|
0.105
|
|
The
following is a summary of warrant activity for the year ended September 30, 2015:
|
|
|
Number of Warrants
|
|
|
Weighted Average Exercise Price
|
|
|
Intrinsic Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2014
|
|
|
72,424,759
|
|
|
$
|
0.105
|
|
|
$
|
0.215
|
|
|
Exercised
|
|
|
(47,618
|
)
|
|
|
0.105
|
|
|
|
–
|
|
|
Cancelled due to warrants extension
|
|
|
(19,701,920
|
)
|
|
|
0.105
|
|
|
|
–
|
|
|
Granted
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
Balance, September 30, 2015
|
|
|
52,675,221
|
|
|
$
|
0.105
|
|
|
$
|
–
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding Warrants, September 30, 2015
|
|
|
52,675,221
|
|
|
$
|
0.105
|
|
|
$
|
–
|
|
|
Exercisable Warrants, September 30, 2015
|
|
|
52,675,221
|
|
|
$
|
0.105
|
|
|
$
|
–
|
|
There
were 52,675,221 warrants outstanding as of September 30, 2015 (September 30, 2014 – 72,424,759), which have a fair value
of $3,153,216 (September 30, 2014 - $1,743,336).
Measurement
Uncertainty for Warrants
The
Company used the Black-Scholes option pricing model (“Black-Scholes”) to value the warrants. This pricing model was
developed for use in estimating the fair value of traded “European” options. The private placement warrants issued
by the Company are transferable and have no vesting restrictions and can be exercised at any time up to their expiration date,
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 warrants. The following assumptions were used in the Black-Scholes pricing model to value
the warrants:
Expected
Term – Expected term of 1.34 years, represents the period that the warrants were 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 96% to 180%.
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 0.62% to 0.67%.
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.
Prior
to October 1, 2013, the Company had a total of 4,350,000 options outstanding, that were previously granted to directors, consultants
and an employee of the Company on March 23, 2011 and June 20, 2013, to purchase up to 3,450,000 and 900,000 shares, respectively,
each of common stock at exercise prices ranging from $0.14 to $0.05, respectively, of which a total of 950,000 options granted
on June 20, 2013 remain unvested.
On
October 28, 2013, the Company granted a contractor an option to purchase 250,000 shares of common stock at an exercise price of
$0.30 per Common Share, all vesting immediately, with a five-year life, for his services in connection with the Farmout Agreement
dated July 31, 2013.
On
December 4, 2013, the Company appointed a new director to its Board and in connection with the appointment the Company granted
the new director an option to purchase 450,000 shares each of common stock at an exercise price of $0.34 per Common Share, 150,000
vesting immediately and the remaining vesting one-third on December 4, 2014, and one-third on December 4, 2015, with a five-year
life.
On
September 19, 2014, the Company granted seven of its directors options to purchase 600,000 shares each of common stock at an exercise
price of $0.38 per Common Share, 200,000 vesting immediately and the remaining vesting one-third on September 19, 2015, and one-third
on September 19, 2016, with a five-year life.
On
September 19, 2014, the Company granted two consultants an option to purchase each 1,200,000 shares each of common stock at an
exercise price of $0.38 per Common Share, 600,000 vesting immediately and remaining vesting on September 19, 2015.
On
September 19, 2014, the Company granted one employee an option to purchase 180,000 shares each of common stock at an exercise
price of $0.38 per Common Share, 60,000 vesting immediately and the remaining vesting one-third on September 19, 2015, and one-third
on September 19, 2016, with a five-year life.
On
November 17, 2014, the Company appointed a new director to its Board and in connection with the appointment the Company granted
the new director an option to purchase 600,000 shares each of common stock at an exercise price of $0.23 per Common Share, 200,000
vesting immediately and the remaining vesting one-third on November 17, 2015, and one-third on November 17, 2016, with a five-year
life.
For
the year ended September 30, 2015, the Company recorded share-based compensation expense related to stock options in the amount
of $1,116,544 (September 30, 2014 – $1,087,356) on the stock options that were previously granted. As of September 30, 2015,
there was remaining unrecognized compensation cost of $240,285 related to the non-vested portion of these unit 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$0.14 at September 30, 2015
|
|
|
900,000
|
|
|
|
0.48
|
|
|
$
|
0.14
|
|
|
|
900,000
|
|
|
$
|
0.14
|
|
|
$0.05 at September 30, 2015
|
|
|
3,450,000
|
|
|
|
2.72
|
|
|
|
0.05
|
|
|
|
3,450,000
|
|
|
|
0.05
|
|
|
$0.30 at September 30, 2015
|
|
|
250,000
|
|
|
|
3.08
|
|
|
|
0.30
|
|
|
|
250,000
|
|
|
|
0.30
|
|
|
$0.34 at September 30, 2015
|
|
|
450,000
|
|
|
|
3.18
|
|
|
|
0.34
|
|
|
|
300,000
|
|
|
|
0.34
|
|
|
$0.38 at September 30, 2015
|
|
|
6,780,000
|
|
|
|
3.97
|
|
|
|
0.38
|
|
|
|
5,320,000
|
|
|
|
0.38
|
|
|
$0.23 at September 30, 2015
|
|
|
600,000
|
|
|
|
4.13
|
|
|
|
0.23
|
|
|
|
200,000
|
|
|
|
0.23
|
|
|
|
|
|
12,430,000
|
|
|
|
3.33
|
|
|
$
|
0.26
|
|
|
|
10,420,000
|
|
|
$
|
0.24
|
|
The
aggregate intrinsic value of exercisable options as of September 30, 2015, was $Nil (September 30, 2014 - $0.11).
The
following is a summary of stock option activity as at September 30, 2015:
|
|
|
Number of Underlying Shares
|
|
|
Weighted Average Exercise Price
|
|
|
Weighted Average Fair Market Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2014
|
|
|
11,830,000
|
|
|
$
|
0.26
|
|
|
$
|
0.21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2015
|
|
|
12,430,000
|
|
|
$
|
0.26
|
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, September 30, 2015
|
|
|
10,420,000
|
|
|
$
|
0.24
|
|
|
$
|
0.20
|
|
A
summary of the options granted at September 30, 2015 and 2014 and changes during the periods then ended is presented below:
|
|
|
September 30, 2015
|
|
|
September 30, 2014
|
|
|
|
|
Shares
|
|
|
Weighted Average Exercise Price
|
|
|
Shares
|
|
|
Weighted Average Exercise Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding balance at beginning of period
|
|
|
11,830,000
|
|
|
$
|
0.26
|
|
|
|
900,000
|
|
|
$
|
0.14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,450,000
|
|
|
|
0.05
|
|
|
Granted - October 28, 2013
|
|
|
|
|
|
|
|
|
|
|
250,000
|
|
|
|
0.30
|
|
|
Granted - December 4, 2013
|
|
|
|
|
|
|
|
|
|
|
450,000
|
|
|
|
0.34
|
|
|
Granted - September 19, 2014
|
|
|
|
|
|
|
|
|
|
|
6,780,000
|
|
|
|
0.38
|
|
|
Granted - November 17, 2014
|
|
|
600,000
|
|
|
|
0.23
|
|
|
|
|
|
|
|
|
|
|
Vested - November 17, 2014
|
|
|
200,000
|
|
|
|
0.23
|
|
|
|
|
|
|
|
|
|
|
Vested - December 4, 2014
|
|
|
150,000
|
|
|
|
0.34
|
|
|
|
|
|
|
|
|
|
|
Vested - June 20, 2015
|
|
|
950,000
|
|
|
|
0.05
|
|
|
|
|
|
|
|
|
|
|
Vested - September 19, 2015
|
|
|
2,660,000
|
|
|
|
0.38
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of period
|
|
|
12,430,000
|
|
|
$
|
0.26
|
|
|
|
11,830,000
|
|
|
$
|
0.26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable
|
|
|
10,420,000
|
|
|
|
0.24
|
|
|
|
6,460,000
|
|
|
|
0.21
|
|
There
were 2,010,000 unvested stock options outstanding as of September 30, 2015 (September 30, 2014 – 5,370,000).
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 option-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,
|
|
|
|
|
2015
|
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
$
|
748,267
|
|
|
|
(994,883
|
)
|
|
Prepaid expenses
|
|
|
6,177
|
|
|
|
38,825
|
|
|
Accounts payable and accounts payable and accrued liabilities – related party
|
|
|
(454,251
|
)
|
|
|
444,773
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
300,193
|
|
|
|
(511,285
|
)
|
As
of September 30, 2015, the Company has approximately $6,067,348 (2014 – $5,909,394) of operating losses expiring through
2035 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, 2015, the Company had
an unused Canadian net operating loss carry-forward of approximately $8,447,043 (2014 – $10,361,017), expiring through 2035.
These operating loss carry-forwards may result in future income tax benefits of approximately $4,404,273. 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,
2015
|
|
|
Year Ended
September 30,
2014
|
|
|
Statutory and effective tax rate
|
|
|
|
|
|
|
|
|
|
Domestic
|
|
|
|
|
|
|
|
|
|
Statutory U.S. federal rate
|
|
|
35.00
|
%
|
|
|
35.00
|
%
|
|
Foreign
|
|
|
25.50
|
%
|
|
|
25.00
|
%
|
|
|
|
Year Ended
September 30,
2015
|
|
|
Year Ended
September 30,
2014
|
|
|
Income taxes recovered at the statutory and effective tax rate
|
|
|
|
|
|
|
|
|
|
Domestic
|
|
|
|
|
|
|
|
|
|
Statutory U.S. federal rate
|
|
$
|
470,101
|
|
|
$
|
449,831
|
|
|
Foreign
|
|
|
151,134
|
|
|
|
188,757
|
|
|
|
|
|
|
|
|
|
|
|
|
Timing differences:
|
|
|
|
|
|
|
|
|
|
Non-deductible expenses
|
|
|
(614,014
|
)
|
|
|
(487,505
|
)
|
|
Other deductible charges
|
|
|
–
|
|
|
|
59,858
|
|
|
Benefit of tax losses not recognized in the year
|
|
|
(7,221
|
)
|
|
|
(210,941
|
)
|
|
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,
2015
|
|
|
Year Ended
September 30,
2014
|
|
|
Deferred income tax assets (liabilities)
|
|
|
|
|
|
|
|
Net operating loss carry-forwards
|
|
$
|
4,404,273
|
|
|
$
|
4,658,542
|
|
|
Oil and gas properties
|
|
|
(1,797,827
|
)
|
|
|
(1,306,095
|
)
|
|
Equipment
|
|
|
191,884
|
|
|
|
187,394
|
|
|
Valuation allowance
|
|
|
(2,798,330
|
)
|
|
|
(3,539,841
|
)
|
|
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
$11,184 per month (Cdn $15,000 per month). As of September 30, 2015, the Company did not owe Concorde Consulting any of this amount.
Rental
Agreement
On
July 27, 2015, the Company renewed its Edmonton office lease commencing effective on July 1, 2015 and expiring on June 30, 2017.
The quarterly payments due are as follows:
|
|
|
USD $
|
|
|
Cdn $
|
|
|
2016 Q1 (October - December)
|
|
|
5,942
|
|
|
|
7,969
|
|
|
2016 Q2 (January - March)
|
|
|
5,942
|
|
|
|
7,969
|
|
|
2016 Q3 (April - June)
|
|
|
5,942
|
|
|
|
7,969
|
|
|
2016 Q4 (July - September)
|
|
|
5,942
|
|
|
|
7,969
|
|
|
2017 Q1 (October - December)
|
|
|
5,942
|
|
|
|
7,969
|
|
|
2017 Q2 (January - March)
|
|
|
5,942
|
|
|
|
7,969
|
|
|
2017 Q3 (April - June)
|
|
|
5,942
|
|
|
|
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 year ended September 30, 2015 and 2014:
|
|
|
September 30,
2015
|
|
|
September 30,
2014
|
|
|
Oil sales after royalties
|
|
$
|
516,407
|
|
|
$
|
47,116
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (Operating) expenses
|
|
|
(516,407
|
)
|
|
|
(47,116
|
)
|
|
Depreciation, accretion and depletion
|
|
|
(79,659
|
)
|
|
|
(97,646
|
)
|
|
Oil sales less expenses
|
|
|
(79,659
|
)
|
|
|
(97,646
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expenses
|
|
|
–
|
|
|
|
–
|
|
|
Results of operations from producing activities
|
|
$
|
(79,659
|
)
|
|
$
|
(97,646
|
)
|
For the years ended September
30, 2015 and September 30, 2014, the Company booked oil revenue in the amount of $516,407 and $47,116, respectively, after deduction
of royalties. For the years ended September 30, 2015 and September 30, 2014, the volumes of oil delivered were booked to be 25,737
barrels and 819 barrels, respectively, net to the Company, before royalties, with an average oil sales price of $23.68 and $61.77
per barrel for the years ended September 30, 2015 and September 30, 2014. 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 $17.8 million
(Cdn $23.9 million) 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, 2015. These costs include the capital costs of the drilling of the SAGD well pair; the purchase
and transportation of equipment; 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;
replacement of the electrical submersible pump; Phase 2 front end costs relating to the purchase of long lead items such as pipe;
and the operating expenses associated with the steaming and production of the SAGD well pair up to September 30, 2015.
Steam
Assisted Gravity Drainage Demonstration Project
On
July 30, 2013, the Company entered into a SAGD Project to jointly participate in an AER approved SAGD Project on one section of
land where the Company had a 25% working interest (after the execution of the Farmout Agreement as defined below). The SAGD Project
is located on section 30-91-12W5 of the Company’s Peace River oil sands properties located in North Central Alberta, Canada
(also known as the Sawn Lake heavy oil reservoir).
SAGD
Project Phase 1 -
The SAGD Project started with the first phase (“Phase 1”) which consisted of the drilling
and completion of one SAGD well pair, the construction of a facility for steam generation, water handling and oil treating, plus
water source and disposal facilities, construction of and pipelines to connect the source wells and fuel tie-in to the SAGD facility.
This first phase included start-up steam operations of the SAGD facility with production commencing on September 16, 2014. The
estimated capital costs to complete the SAGD Project steam plant facility with one SAGD well pair has been estimated by the operator
to be approximately $24.5 million (Cdn $32.9 million) on a 100% working interest basis, of which the Company’s share is
covered under the Farmout Agreement (does not include any of the Phase 2 costs for the SAGD Project).
SAGD
Project Outlook -
The demonstration of the SAGD Project has successfully completed its goal to be able to show the capability
of the Bluesky reservoir to produce using steam, the Company’s joint venture partners decided to suspend the SAGD Project
operations at the end of February 2016. The SAGD Project has successfully captured the key data associated with the objectives
of the demonstration project. The demonstration project has:
|
●
|
demonstrated
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
Sawn Lake Demonstration Project reached a steady state production level in January and February of 2016 with an average of 615
barrels of oil per day (“bopd”), on a 100% basis (154 bopd net to the Company), with an average SOR of 2.1 from the
one SAGD well pair. It is expected that a reactivation of the SAGD Project facility and well pair will be part of a potential
commercial expansion of the project. The SAGD Project has provided the Company with the data and insight to now make the application
to expand the SAGD Project at Sawn Lake. An expansion is dependent on regulatory approval, completion of detailed engineering
and a higher commodity price environment to support project economics and financing. This decision considers the expectation that
extremely low bitumen prices may continue for some time and the estimated time required for approval of the 3,200 bopd expansion
application at the SAGD Project site. The expansion application was submitted in early May of 2016 and approval, if granted, is
expected to take up to approximately a year and a half.
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”.
|
17.
|
SUPPLEMENTARY
INFORMATION ON OIL AND GAS RESERVES (UNAUDITED)
|
The
following supplemental information regarding the Company’s oil and gas activities is presented pursuant to the disclosure
requirements promulgated by the U.S. Securities and Exchange Commission (“SEC”) and ASC 932, Extractive Activities
- Oil and Gas, (“ASC 932”).
Users
of this supplemental information should be aware that the process of estimating quantities of “proved” and “proved
developed” oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological,
engineering and economic data for the reservoir. The data for a reservoir may also change substantially over time as a result
of numerous factors including, but not limited to, additional development activity, evolving production history and continual
reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates
may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most
accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates
generally less precise than other estimates included in the financial statement disclosures.
Proved
reserves represent estimated quantities of natural gas and crude oil that geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the
estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place
and under operating methods used when the estimates were made.
Under
current SEC standards, “Proved Reserves” are those quantities of oil and gas, which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known
reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which
contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether
deterministic or probabilistic methods are used for the estimation.
Under
current SEC standards, the term “Reasonable Certainty” if deterministic methods are used, implies a high degree of
confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability
that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is
much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical,
and geochemical), engineering, and economic data are made to estimated ultimate recovery (“EUR”) with time, reasonably
certain EUR is much more likely to increase or remain constant than to decrease. Reasonable certainty can be established using
techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir
or by other evidence using reliable technology that establishes reasonable certainty.
Under
current SEC standards, “Reliable Technology” is a grouping of one or more technologies (including computational methods)
that have been field tested and have demonstrated to provide reasonably certain results with consistency and repeatability in
the formation being evaluated or in an analogous formation.
Estimated
Oil and Gas Reserve Quantities of Proved Developed and Proved Undeveloped Reserves
The
following table illustrates the Company’s estimated net proved reserves for the periods indicated, as estimated by third
party reservoir engineers.
The Company’s
oil reserves are attributable solely to properties within Alberta, Canada. The following table discloses, in the aggregate, the
Company’s estimated reserves on the Company’s Sawn Lake oil sands properties located in the Peace River oil sands
area of Alberta, Canada, as of September 30, 2015, based on estimated constant prices and cost assumptions. As of September 30,
2015, the Company is reporting no reserves.
|
|
|
Oil (Bitumen)
|
|
|
Natural Gas
|
|
|
Total
|
|
|
|
|
Gross
(1)
(Mbbl)
|
|
|
Net
(2)
(Mbbl)
|
|
|
Gross (Mmcf)
|
|
|
Net
(Mmcf)
|
|
|
BOE (MBOE)
|
|
|
Proved developed and undeveloped reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of year - as of September 30, 2014
|
|
|
571
|
|
|
|
530
|
|
|
|
–
|
|
|
|
–
|
|
|
|
571
|
|
|
Revisions of previous estimates
|
|
|
(545
|
)
|
|
|
(504
|
)
|
|
|
|
|
|
|
|
|
|
|
(545
|
)
|
|
Improved recovery
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
Purchases of minerals in place
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
Extensions and discoveries
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
Production
|
|
|
(26
|
)
|
|
|
(26
|
)
|
|
|
–
|
|
|
|
–
|
|
|
|
(26
|
)
|
|
Sales of minerals in place
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
End of year - as of September 30, 2015
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
as of September 30, 2014
|
|
|
571
|
|
|
|
530
|
|
|
|
–
|
|
|
|
–
|
|
|
|
571
|
|
|
as of September 30, 2015
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
(1)
Gross
Reserves – are defined as the Company’s working interest reserves (operating or non-operating) before deduction
of royalties.
(2)
Net
Reserves – are defined as the Company’s working interest reserves (operating or non-operating) after deduction of
royalties.
As
of September 30, 2015, the Company is reporting no reserves based on the following revisions of its previous year’s proved
reserve estimates:
Revisions
of previous estimates
– are revisions that represent changes in previous estimates of proved reserves, either upward
or downward, resulting from new information (except for an increase in proved acreage) normally obtained from development drilling
and production history or resulting from a change in economic factors. The Company was not assigned any proved reserves on its
properties; therefore the Company recorded a reduction in the Company’s reserves of approximately 545,000 barrels.
Improved
recovery
– are changes in reserve estimates resulting from application of improved recovery techniques. The Company
did not report any additions under improved recovery of proved.
Purchases
of minerals in place
– The Company did not report any property acquisitions whereby the Company purchased any
properties with proved reserves or any reserves.
Extensions
and discoveries
– are additions to proved reserves that result from (1) extension of the proved acreage of previously
discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved
reserves or of new reservoirs of proved reserves in old fields.
The
Company did not report any additions under extensions or discoveries of proved reserves or any reserves.
Production
– are downward revisions associated with actual production. The Company’s first SAGD well pair began producing
oil on September 16, 2014 and continued to produce throughout the year. T
he
Company recorded
a reduction in the Company’s reserves of approximately 26,000 barrels.
Sales
of minerals in place
–
For the year
ended September 30, 2015, the Company did not report any sale of its properties of which had proved reserves.
Standardized
Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserve Quantities
The
following table discloses, in the aggregate, the Company’s estimated net present value of future cash flows attributable
to the Company’s estimated oil reserves on the Company’s Sawn Lake oil sands properties located in the Peace River
oil sands area of Alberta, Canada, as of September 30, 2015, based on estimated constant prices and cost assumptions. The future
cash flow estimate set forth below are estimates only and the actual realized cash flow may be greater or less than those calculated
and should not be considered as representative of the current value of the Company. As of September 30, 2015, the Company is reporting
no proved reserves:
|
|
|
As of
|
|
|
As of
|
|
|
In Thousands
|
|
September 30,
2015
|
|
|
September 30,
2014
|
|
|
|
|
|
|
|
|
|
|
Future cash inflows
|
|
$
|
–
|
|
|
$
|
31,062
|
|
|
Future Royalties
|
|
|
–
|
|
|
|
(2,456
|
)
|
|
Future Operating costs
|
|
|
–
|
|
|
|
(13,040
|
)
|
|
Future Development Costs
|
|
|
–
|
|
|
|
(8,586
|
)
|
|
Future Abandonment Costs
|
|
|
–
|
|
|
|
(161
|
)
|
|
Future income tax expenses
|
|
|
–
|
|
|
|
–
|
|
|
Future net cash flows
|
|
$
|
–
|
|
|
$
|
6,819
|
|
|
10% annual discount for estimated timing of cash flows
|
|
|
–
|
|
|
|
(4,919
|
)
|
|
Standardize measure of discounted future net cash flows
|
|
$
|
–
|
|
|
$
|
1,900
|
|
Changes
in the Standardized Measure of Discounted Cash Flows Related to Proved Oil and Gas Reserve Quantities
The
Company’s independent third party qualified reserves evaluator, DeGolyer and MacNaughton Canada Limited (“DeGolyer”),
was engaged by the Company to independently evaluate the Company’s properties. DeGolyer was unable to assign SEC reserves
as of September 30, 2015 to the Company’s properties, as a result of pricing and operational issues. Therefore, DeGolyer
did not prepare an update to the Company’s previous reserves report entitled, “Appraisal Report as of September 30,
2014 on the Proved and Probable Reserves of the Sawn Lake Property owned by Deep Well Oil & Gas, Inc. in Canada SEC Case”
dated January 9, 2015.
As
previously disclosed, the Company entered into a Farmout Agreement to fund the Company’s share of the SAGD Project. As part
of the Farmout Agreement, as amended on November 17, 2014, the Farmee had the option, up to December 31, 2015, by committing an
additional $110,000,000 of financing to the development of the Company’s Sawn Lake oil sands properties, to obtain an additional
working interest of 45% to 50% in the remaining 56 sections of land where the Company has working interests ranging from 90% to
100%. As of the date of the options expiration (December 31, 2015), the Farmee did not exercise its option to acquire such interests.
On
March 23, 2016, 900,000 stock options previously granted on March 23, 2011 to two directors, expired unexercised.
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.
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 $
|
|
|
2017 Q4 (July - September)
|
|
$
|
–
|
|
|
$
|
–
|
|
|
2018 Q1 (October - December)
|
|
$
|
5,942
|
|
|
$
|
7,969
|
|
|
2018 Q2 (January - March)
|
|
$
|
5,942
|
|
|
$
|
7,969
|
|
|
2018 Q3 (April - June)
|
|
$
|
5,942
|
|
|
$
|
7,969
|
|
|
2018 Q4 (July - September)
|
|
$
|
5,942
|
|
|
$
|
7,969
|
|
|
2019 Q1 (October - December)
|
|
$
|
5,942
|
|
|
$
|
7,969
|
|
|
2019 Q2 (January - March)
|
|
$
|
5,942
|
|
|
$
|
7,969
|
|
|
2019 Q3 (April - June)
|
|
$
|
5,942
|
|
|
$
|
7,969
|
|