|
ITEM
1.
|
CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS
|
DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
Condensed Consolidated Balance Sheets
June 30, 2016 and September 30, 2015
|
|
June 30,
|
|
|
September 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,493,893
|
|
|
$
|
1,786,270
|
|
Accounts receivable
|
|
|
62,200
|
|
|
|
301,832
|
|
Prepaid expenses
|
|
|
28,905
|
|
|
|
37,698
|
|
|
|
|
|
|
|
|
|
|
Total Current Assets
|
|
|
1,584,998
|
|
|
|
2,125,800
|
|
|
|
|
|
|
|
|
|
|
Long term investments
|
|
|
386,692
|
|
|
|
372,971
|
|
Oil and gas properties, net, based on full cost method of accounting
|
|
|
21,064,705
|
|
|
|
20,981,652
|
|
Property and equipment, net
|
|
|
172,589
|
|
|
|
203,970
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
23,208,984
|
|
|
$
|
23,684,393
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
|
|
|
|
|
|
|
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$
|
26,550
|
|
|
$
|
272,091
|
|
Accounts payable and accrued liabilities– related parties
|
|
|
3,311
|
|
|
|
4,833
|
|
|
|
|
|
|
|
|
|
|
Total Current Liabilities
|
|
|
29,861
|
|
|
|
276,924
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
(Note 7)
|
|
|
452,160
|
|
|
|
426,607
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES
|
|
|
482,021
|
|
|
|
703,531
|
|
(Commitments and contingencies (Note 11)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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SHAREHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
Common Stock:
(Note 8)
|
|
|
|
|
|
|
|
|
Authorized: 600,000,000 shares at $0.001 par value Issued and outstanding: 229,374,605 shares (September 30, 2015 – 229,374,605 shares)
|
|
|
229,374
|
|
|
|
229,374
|
|
Additional paid in capital
|
|
|
42,790,910
|
|
|
|
42,605,007
|
|
Accumulated deficit
|
|
|
(20,293,321
|
)
|
|
|
(19,853,519
|
)
|
|
|
|
|
|
|
|
|
|
Total Shareholders’ Equity
|
|
|
22,726,963
|
|
|
|
22,980,862
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
23,208,984
|
|
|
$
|
23,684,393
|
|
See accompanying notes to the condensed consolidated financial
statements
DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
(Unaudited)
Condensed Consolidated Statements of
Operations and Comprehensive Loss
For the Three and Nine Months Ended June
30, 2016 and 2015
|
|
Three Months Ended
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30,
2016
|
|
|
June 30,
2015
|
|
|
June 30,
2016
|
|
|
June 30,
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
–
|
|
|
$
|
219,346
|
|
|
$
|
150,669
|
|
|
$
|
449,147
|
|
Royalty expenses
|
|
|
–
|
|
|
|
(11,127
|
)
|
|
|
(22,977
|
)
|
|
|
(23,512
|
)
|
Revenue, net of royalty
|
|
|
–
|
|
|
|
208,219
|
|
|
|
127,692
|
|
|
|
425,635
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
85,045
|
|
|
|
425,684
|
|
|
|
697,814
|
|
|
|
1,540,206
|
|
Operating expenses covered by Farmout
|
|
|
(85,045
|
)
|
|
|
(217,465
|
)
|
|
|
(570,122
|
)
|
|
|
(1,114,571
|
)
|
General and administrative
|
|
|
105,465
|
|
|
|
337,016
|
|
|
|
398,929
|
|
|
|
1,434,203
|
|
Depreciation, accretion and depletion
|
|
|
17,397
|
|
|
|
21,721
|
|
|
|
51,924
|
|
|
|
64,541
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from operations
|
|
|
(122,862
|
)
|
|
|
(358,737
|
)
|
|
|
(450,853
|
)
|
|
|
(1,498,744
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental and other income
|
|
|
142
|
|
|
|
3,432
|
|
|
|
8,425
|
|
|
|
10,635
|
|
Interest income
|
|
|
896
|
|
|
|
1,081
|
|
|
|
2,626
|
|
|
|
3,778
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss and comprehensive loss
|
|
$
|
(121,824
|
)
|
|
$
|
(354,224
|
)
|
|
$
|
(439,802
|
)
|
|
$
|
(1,484,331
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted
|
|
$
|
(0.00
|
)
|
|
$
|
(0.00
|
)
|
|
$
|
(0.00
|
)
|
|
$
|
(0.01
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Outstanding Shares (in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted
|
|
|
229,374
|
|
|
|
229,374
|
|
|
|
229,374
|
|
|
|
229,374
|
|
See accompanying notes to the condensed consolidated financial
statements
DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
(Unaudited)
Condensed Consolidated Statements of
Cash Flows
For the Nine Months Ended June 30, 2016
and 2015
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2016
|
|
|
2015
|
|
|
|
|
|
|
|
|
CASH PROVIDED BY (USED IN):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities
|
|
|
|
|
|
|
Net loss
|
|
$
|
(439,802
|
)
|
|
$
|
(1,484,331
|
)
|
Items not affecting cash:
|
|
|
|
|
|
|
|
|
Share based compensation
|
|
|
185,903
|
|
|
|
865,756
|
|
Depreciation, accretion and depletion
|
|
|
51,924
|
|
|
|
64,541
|
|
Net changes in non-cash working capital (Note 10)
|
|
|
1,362
|
|
|
|
276,472
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used in Operating Activities
|
|
|
(200,613
|
)
|
|
|
(277,562
|
)
|
|
|
|
|
|
|
|
|
|
Investing Activities
|
|
|
|
|
|
|
|
|
Investment in oil and gas properties
|
|
|
(93,909
|
)
|
|
|
(31,637
|
)
|
Long term investments
|
|
|
2,145
|
|
|
|
2,671
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used in Investing Activities
|
|
|
(91,764
|
)
|
|
|
(28,966
|
)
|
|
|
|
|
|
|
|
|
|
Financing Activities
|
|
|
|
|
|
|
|
|
Proceeds from issuance of common stock
|
|
|
–
|
|
|
|
5,001
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by Financing Activities
|
|
|
–
|
|
|
|
5,001
|
|
|
|
|
|
|
|
|
|
|
Decrease in cash and cash equivalents
|
|
|
(292,377
|
)
|
|
|
(301,527
|
)
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, beginning of period
|
|
|
1,786,270
|
|
|
|
2,324,755
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
1,493,893
|
|
|
$
|
2,023,228
|
|
|
|
|
|
|
|
|
|
|
Supplemental Cash Flow Information:
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
–
|
|
|
$
|
–
|
|
Cash paid for income taxes
|
|
$
|
–
|
|
|
$
|
–
|
|
See accompanying notes to the condensed consolidated financial
statements
DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
(Unaudited)
Notes to the Condensed Consolidated Financial
Statements
June 30, 2016
1.
|
NATURE OF BUSINESS AND BASIS OF PRESENTATION
|
Nature of Business
Deep Well Oil & Gas, Inc.
was originally incorporated on July 18, 1988 under the laws of the state of Nevada as Worldwide Stock Transfer, Inc. (Worldwide
Stock Transfer, Inc. later changed its name to Allied Devices Corporation) and in connection with a plan of reorganization, effective
on September 10, 2003, the company was reorganized and changed its name to Deep Well Oil & Gas, Inc. (“Deep Well”).
These condensed consolidated
financial statements have been prepared showing the name “Deep Well Oil & Gas, Inc. (and Subsidiaries)” (“the
Company”) and the post-split common stock, with $0.001 par value.
Basis of Presentation
The interim condensed consolidated
financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of
the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements
prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) have
been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate
so as to make the information presented not misleading.
These interim condensed consolidated
financial statements follow the same significant accounting policies and methods of application as the Company’s annual consolidated
financial statements for the year ended September 30, 2015.
These statements reflect all
adjustments, consisting solely of normal recurring adjustments (unless otherwise disclosed) which, in the opinion of management,
are necessary for a fair presentation of the information contained therein. However, the results of operations for the interim
periods may not be indicative of results to be expected for the full fiscal year. It is suggested that these condensed consolidated
financial statements be read in conjunction with the audited consolidated financial statements and notes thereto included in the
Company’s Annual Report on Form 10-K for the year ended September 30, 2015.
2.
|
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
|
Basis of Consolidation
These condensed consolidated
financial statements include the accounts of two wholly owned subsidiaries: (1) Northern Alberta Oil Ltd. (“Northern”)
from the date of acquisition, being June 7, 2005, incorporated under the Business Corporations Act (Alberta), Canada; and (2) Deep
Well Oil & Gas (Alberta) Ltd., incorporated under the Business Corporations Act (Alberta), Canada on September 15, 2005. All
inter-company balances and transactions have been eliminated.
Change in Accounting Principle
During the fourth fiscal 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 have 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 condensed consolidated financial statements have been recast to reflect
these differences. There was no effect on the prior period financial statements as a result of the change in accounting policy.
Crude oil and natural gas
properties
The Company follows the full
cost method of accounting for oil sands properties pursuant to SEC Regulation S-X Rule 4-10. The full cost method of accounting
for oil and gas operations requires that all costs associated with the exploration for and development of oil and gas reserves
be capitalized on a country by country basis. Such costs include lease acquisition costs, geological and geophysical expenses,
carrying charges on non-producing properties, costs of drilling both productive and non-productive wells, production equipment
and overhead charges directly related to acquisition, exploration and development activities.
Under
the full cost method, oil and gas properties are subject to the ceiling test
performed quarterly.
A
ceiling test write-down is recognized in net earnings if the carrying amount of a cost centre exceeds the “cost centre ceiling”.
The carrying amount of the cost centre includes the capitalized costs of proved oil and natural gas properties, net of accumulated
depletion and deferred income taxes. The cost centre ceiling is the sum of (A) present value of the estimated future net cash flows
from proved oil and natural gas reserves using a 10 percent per year discount factor, (B) the costs of unproved properties not
being amortized
,
and (C) the lower of cost or fair value of unproved properties included in
the costs being amortized; less (D) related income tax effects. As of June 30, 2016, no ceiling test write-downs were recorded
for the Company’s oil and gas properties.
Costs associated with unproved
properties are excluded from the depletion calculation until it is determined that proved reserves are attributable or impairment
has occurred. Unproved properties are assessed annually for impairment. Costs that have been impaired are included in the costs
subject to depletion within the full cost pool.
Asset Retirement Obligations
The Company accounts for asset
retirement obligations by recording the fair value of the estimated future cost of the Company’s plugging and abandonment
obligations. The asset retirement obligation is recorded when there is a legal obligation associated with the retirement of a tangible
long-lived asset and the fair value of the liability can reasonably be estimated. Upon initial recognition of an asset retirement
obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the
liabilities are accreted for the change in their present value through charges to oil and gas production and well operations costs.
The initial capitalized costs are depleted over the useful lives of the related assets through charges to depreciation, depletion,
and amortization. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the
asset retirement obligation and the asset retirement cost.
Revisions in estimated liabilities
can result from revisions of estimated inflation rates, escalating retirement costs, and changes in the estimated timing of settling
asset retirement obligations. As of June 30, 2016 and September 30, 2015, asset retirement obligations amount to $452,160 and $426,607,
respectively. The Company has posted bonds, where required, with the Government of Alberta based on the amount the government estimates
the cost of abandonment and reclamation to be.
Financial, Concentration
and Credit Risk
The Company’s consideration
or related financial credit risk related to cash and cash equivalents depends on if funds are fully insured by either The Canada
Deposit Insurance Corporation (“CDIC”), or The Credit Union Deposit Guarantee Corporation (“CUDGC”) deposit
insurance limit. As of June 30, 2016, the Company has approximately $573,240 funds that are in excess of deposit insurance limits,
which may have financial credit risk. For the Company funds that are maintained in a financial institution which has its deposits
fully guaranteed by CUDGC, there is no financial credit risk.
The Company is not directly subject
to credit risk resulting from the concentration of its crude oil sales. For the period ending June 30, 2016 and for the year ended
September 30, 2015, 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 all 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.
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 63,685,221 potentially dilutive securities excluded from the the diluted earnings per share
calculation because their effect would be antidilutive.
Recently Adopted Accounting Standards
In February 2016, the FASB issued
ASU 2016-02, “Leases (Topic 842),” requiring lessees to recognize lease assets and lease liabilities for most leases
classified as operating leases under previous U.S. GAAP. The guidance is effective for fiscal years beginning after December 15,
2018, with early adoption permitted. The Company will be required to use a modified retrospective approach for leases that exist
or are entered into after the beginning of the earliest comparative period in the financial statements. The adoption of this standard
is not expected to have a material impact on the Company’s consolidated financial statements.
The Company does not expect the
adoption of any other recent accounting pronouncements to have a material impact on the Company’s financial statements.
3.
|
OIL AND GAS PROPERTIES
|
The Company’s oil sands
acreage as of June 30, 2016, 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:
|
1)
|
32 sections of land under 5 oil sands leases are set to expire on July 10, 2018. Of the 5 oil sands
leases totaling 32 sections of land, it is the Company’s opinion that the Company has already met the governmental requirements
on 17 of the 32 sections to continue these sections into perpetuity. These 17 sections contain the majority of the resources identified
to date on these 5 oil sands leases. The Company has completed or is in the process of applying for continuation of these leases
or parts of the leases where the majority of the oil sands resources have been confirmed;
|
|
2)
|
31 sections of land under 3 oil sands leases are set to expire on August 19, 2019; and
|
|
3)
|
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 all 5
sections of this lease into perpetuity.
|
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 June 30, 2016, the Company’s
net payments due under this commitment are as follows:
|
|
|
(USD $)
|
|
|
(Cdn $)
|
|
|
2016
|
|
$
|
9,281
|
|
|
$
|
12,074
|
|
|
2017
|
|
$
|
37,124
|
|
|
$
|
48,294
|
|
|
2018
|
|
$
|
37,124
|
|
|
$
|
48,294
|
|
|
2019
|
|
$
|
22,660
|
|
|
$
|
29,478
|
|
|
2020
|
|
$
|
3,444
|
|
|
$
|
4,480
|
|
|
Subsequent
|
|
$
|
13,775
|
|
|
$
|
17,920
|
|
The Company follows the full
cost method of accounting for costs of oil properties. Under this method, oil and gas properties, for which no proved reserves
have been assigned, must be assessed at least annually to ascertain whether or not a write down should occur. Unproven properties
are assessed annually, or more frequently as economic events indicate, for potential write down.
This consists of comparing the
carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. Estimates of
expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. Proven oil
properties are reviewed for any write down on a field-by-field basis. No write downs were recognized for the period ended June
30, 2016.
Capitalized costs of proven oil
properties will be depleted using the unit-of-production method when the property is placed in production.
Substantially all of the Company’s
oil activities are conducted jointly with others. The accounts reflect only the Company’s proportionate interest in such
activities.
|
4.
|
CAPITALIZATION OF COSTS INCURRED IN OIL AND GAS ACTIVITIES
|
The following table illustrates
capitalized costs relating to oil producing activities for the nine months ended June 30, 2016 and the fiscal year ended September
30, 2015:
|
|
|
June 30,
2016
|
|
|
September 30, 2015
|
|
|
|
|
|
|
|
|
|
|
Unproved Oil and Gas Properties
|
|
$
|
21,135,557
|
|
|
$
|
21,044,015
|
|
|
Proved Oil and Gas Properties
|
|
|
–
|
|
|
|
–
|
|
|
Accumulated Depreciation and Depletion
|
|
|
(70,852
|
)
|
|
|
(62,363
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net Capitalized Cost
|
|
$
|
21,064,705
|
|
|
$
|
20,981,652
|
|
Depreciation and depletion expense
for the nine months ended June 30, 2016 and 2015 were $8,489 and $10,800 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 nine months ended June 30, 2016 and the fiscal year ended September 30, 2015:
|
|
|
June 30,
2016
|
|
|
September 30, 2015
|
|
|
|
|
|
|
|
|
|
|
Acquisition of Properties:
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
–
|
|
|
$
|
–
|
|
|
Unproved
|
|
$
|
91,542
|
|
|
$
|
135,575
|
|
|
Exploration costs
|
|
$
|
20,463
|
|
|
$
|
46,351
|
|
|
Development costs
|
|
$
|
–
|
|
|
$
|
–
|
|
6.
|
SIGNIFICANT TRANSACTIONS WITH RELATED PARTIES
|
Accounts payable – related
parties was $3,311 as of June 30, 2016 (September 30, 2015 - $4,833) for expenses to be reimbursed to directors. This amount is
unsecured, non-interest bearing, and has no fixed terms of repayment.
As of June 30, 2016, 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
$101,358 to one related party, Concorde Consulting, for professional fees and consulting services provided to the Company during
the period ended June 30, 2016 (June 30, 2015 - $112,590). These amounts were fully paid as of June 30, 2016.
7.
|
ASSET RETIREMENT OBLIGATIONS
|
The total future asset retirement
obligation is estimated by management based on the Company’s net working interests in all wells and facilities, estimated
costs as determined by the Alberta Energy Regulator to reclaim and abandon wells and facilities and the estimated timing of the
costs to be incurred in future periods. At June 30, 2016, the Company estimates the undiscounted cash flows related to asset retirement
obligation to total approximately $621,283 (September 30, 2015 - $602,613). The fair value of the liability at June 30, 2016 is
estimated to be $452,160 (September 30, 2015 - $426,607) 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 27 years.
Changes to the asset retirement
obligation were as follows:
|
|
|
June 30, 2016
|
|
|
September 30, 2015
|
|
|
Balance, beginning of period
|
|
$
|
426,607
|
|
|
$
|
469,013
|
|
|
Liabilities incurred
|
|
|
–
|
|
|
|
35,031
|
|
|
Effect of foreign exchange
|
|
|
13,498
|
|
|
|
(93,421
|
)
|
|
Disposal
|
|
|
–
|
|
|
|
–
|
|
|
Accretion expense
|
|
|
12,055
|
|
|
|
15,984
|
|
|
Balance, end of period
|
|
$
|
452,160
|
|
|
$
|
426,607
|
|
Common Stock Issued and
Outstanding
As of June 30, 2016, the Company
had outstanding 229,374,605 shares of common stock.
Warrants
The
following table summarizes the Company’s warrants outstanding as of June 30, 2016:
|
|
|
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 June 30, 2016
|
|
|
52,155,221
|
|
|
|
0.40
|
|
|
$
|
0.105
|
|
|
|
52,155,221
|
|
|
$
|
0.105
|
|
|
|
|
|
52,155,221
|
|
|
|
0.40
|
|
|
$
|
0.105
|
|
|
|
52,155,221
|
|
|
$
|
0.105
|
|
The
following is a summary of warrant activity for the period ended June 30, 2016:
|
|
|
Number of Warrants
|
|
|
Weighted Average Exercise Price
|
|
|
Intrinsic
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2015
|
|
|
52,675,221
|
|
|
$
|
0.105
|
|
|
$
|
–
|
|
|
Expired at June 20, 2016
|
|
|
(520,000
|
)
|
|
|
0.075
|
|
|
|
–
|
|
|
Granted
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
Exercised
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
Balance, June 30, 2016
|
|
|
52,155,221
|
|
|
$
|
0.105
|
|
|
$
|
–
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding Warrants, June 30, 2016
|
|
|
52,155,221
|
|
|
$
|
0.105
|
|
|
$
|
–
|
|
There were 52,155,221 warrants
outstanding as of June 30, 2016 (September 30, 2015 – 52,675,221), which have a historical fair market value of $3,153,216
(September 30, 2015 - $3,153,216).
For the period ended June 30,
2016, the Company recorded share based compensation expense related to stock options in the amount of $185,903 (September 30, 2015
– $1,116,544) on the stock options that were previously granted. As of June 30, 2016, there was remaining unrecognized compensation
cost of $54,382 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 Price
|
|
Shares Underlying Options Outstanding
|
|
|
Weighted Average Remaining Contractual Life
|
|
|
Weighted Average Exercise Price
|
|
|
Shares Underlying Options Exercisable
|
|
|
Weighted Average Exercise Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$0.05 at June 30, 2016
|
|
|
3,450,000
|
|
|
|
1.97
|
|
|
|
0.05
|
|
|
|
3,450,000
|
|
|
|
0.05
|
|
|
$0.30 at June 30, 2016
|
|
|
250,000
|
|
|
|
2.33
|
|
|
|
0.30
|
|
|
|
250,000
|
|
|
|
0.30
|
|
|
$0.34 at June 30, 2016
|
|
|
450,000
|
|
|
|
2.43
|
|
|
|
0.34
|
|
|
|
450,000
|
|
|
|
0.34
|
|
|
$0.38 at June 30, 2016
|
|
|
6,780,000
|
|
|
|
3.22
|
|
|
|
0.38
|
|
|
|
5,320,000
|
|
|
|
0.38
|
|
|
$0.23 at June 30, 2016
|
|
|
600,000
|
|
|
|
3.38
|
|
|
|
0.23
|
|
|
|
400,000
|
|
|
|
0.23
|
|
|
|
|
|
11,530,000
|
|
|
|
2.81
|
|
|
$
|
0.27
|
|
|
|
9,870,000
|
|
|
$
|
0.25
|
|
The aggregate intrinsic value
of exercisable options as of June 30, 2016, was $Nil (September 30, 2015 - $Nil).
The following is a summary of stock option activity
as at June 30, 2016:
|
|
|
Number of Underlying Shares
|
|
|
Weighted Average Exercise Price
|
|
|
Weighted Average Fair Market
Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2015
|
|
|
12,430,000
|
|
|
$
|
0.26
|
|
|
$
|
0.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, June 30, 2016
|
|
|
11,530,000
|
|
|
$
|
0.27
|
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, June 30, 2016
|
|
|
9,870,000
|
|
|
$
|
0.25
|
|
|
$
|
0.20
|
|
There were 1,660,000 unvested stock options outstanding
as of June 30, 2016 (September 30, 2015 – 2,010,000).
10.
|
CHANGES IN NON-CASH WORKING CAPITAL
|
|
|
|
Nine months ended
|
|
|
Nine months Ended
|
|
|
|
|
June 30, 2016
|
|
|
June 30, 2015
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable decrease
|
|
$
|
239,632
|
|
|
$
|
823,334
|
|
|
Prepaid expenses decrease
|
|
|
8,793
|
|
|
|
(5,582
|
)
|
|
Accounts payable decrease
|
|
|
(247,063
|
)
|
|
|
(541,280
|
)
|
|
|
|
$
|
1,362
|
|
|
$
|
276,472
|
|
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 $11,262 per month (Cdn
$15,000 per month). As of June 30, 2016, 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 Q4 (July - September)
|
|
$
|
6,126
|
|
|
$
|
7,969
|
|
|
2017 Q1 (October - December)
|
|
$
|
6,126
|
|
|
$
|
7,969
|
|
|
2017 Q2 (January - March)
|
|
$
|
6,126
|
|
|
$
|
7,969
|
|
|
2017 Q3 (April - June)
|
|
$
|
6,126
|
|
|
$
|
7,969
|
|
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)
|
|
$
|
6,126
|
|
|
$
|
7,969
|
|
|
2018 Q2 (January - March)
|
|
$
|
6,126
|
|
|
$
|
7,969
|
|
|
2018 Q3 (April - June)
|
|
$
|
6,126
|
|
|
$
|
7,969
|
|
|
2018 Q4 (July - September)
|
|
$
|
6,126
|
|
|
$
|
7,969
|
|
|
2019 Q1 (October - December)
|
|
$
|
6,126
|
|
|
$
|
7,969
|
|
|
2019 Q2 (January - March)
|
|
$
|
6,126
|
|
|
$
|
7,969
|
|
|
2019 Q3 (April - June)
|
|
$
|
6,126
|
|
|
$
|
7,969
|
|
First production from the Company’s
joint Steam Assisted Gravity Drainage Demonstration Project (the “SAGD Project”) began on September 16, 2014. As a
result of the low-price environment for bitumen in 2015 and early 2016, a majority of the Company’s Joint Venture partners
voted to temporarily suspend operations of the SAGD Project at the end of February 2016. In early May of 2016, an amended application
was submitted to the 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. The amended application sought approval to expand the existing SAGD Project facility
site to 3,200 bopd (100% basis). It is anticipated that only five SAGD well pairs 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 the expansion of the existing SAGD Project was granted on December 14, 2017. While the joint venture has
not yet approved to expand the SAGD Project, 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 development at Sawn Lake.
|
ITEM
2.
|
MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
The
following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes.
For the purpose of this discussion, unless the context indicates another meaning, the terms: “Deep Well,” “Company,”
“we,” “us,” and “our” refer to Deep Well Oil & Gas, Inc. and its subsidiaries. This discussion
includes forward-looking statements that reflect our current views with respect to future events and financial performance that
involve risks and uncertainties. Our actual results, performance or achievements could differ materially from those anticipated
in the forward-looking statements as a result of certain factors including risks discussed in “Cautionary Note Regarding
– Forward-Looking Statements” below and elsewhere in this report, and under the heading “Risk Factors”
and “Environmental Laws and Regulations” disclosed in our annual report on Form 10-K for the fiscal year ended September
30, 2015, filed with the U.S. Securities and Exchange Commission (“SEC”) on December 29, 2017.
Our
consolidated financial statements and the supplemental information thereto are reported in United States dollars and are prepared
based upon United States generally accepted accounting principles (“US GAAP”). References in this Form 10-Q to “$”
are to United States dollars and references to “Cdn$” are to Canadian dollars. On February 20, 2018, the daily rate
of exchange for Canadian dollars expressed in US$ was Cdn$1.00 = US$0.7923 as reported by the Bank of Canada. The following table
sets forth the rates of exchange for the Cdn$, expressed in US dollars, in effect at the end of the following periods and the
average rates of exchange during such periods, based on the daily rates of exchange for such periods as reported by the Bank of
Canada.
Period
Ending June 30
|
|
2016
|
|
|
2015
|
|
Rate
at end of period
|
|
|
0.7687
|
|
|
|
0.8017
|
|
Average rate
for the three month period
|
|
|
0.7760
|
|
|
|
0.8132
|
|
General
Overview
Deep
Well Oil & Gas, Inc., along with its subsidiaries through which it conducts business, is an emerging independent junior oil
sands exploration and development company headquartered in Edmonton, Alberta, Canada. Our immediate corporate focus is to develop
the existing oil sands land base where we have working interests ranging from 25% to 100% in the Peace River oil sands area of
Alberta, Canada. Our principal office is located at Suite 700, 10150 - 100 Street, Edmonton, Alberta, Canada T5J 0P6, our telephone
number is (780) 409-8144, and our fax number is (780) 409-8146. Deep Well Oil & Gas, Inc. is a Nevada corporation and trades
on the OTC Marketplace under the symbol DWOG. We maintain a website at www.deepwelloil.com or www.DWOG.com. The contents of our
website are not part of the quarterly report on Form 10-Q.
Results
of Operations
Since
the inception of our current business plan, our operations have consisted of various exploration and start-up activities relating
to our properties, including the acquisition of lease holdings, raising capital, locating joint venture partners, acquiring and
analyzing seismic data, complying with environmental regulations, providing project management, drilling, testing and analyzing
of wells to define our oil sands reservoir, and development planning of our Alberta Energy Regulatory (“AER”) approved
thermal recovery projects, which includes our steam assisted gravity drainage project where we have a 25% working interest.
During
the fourth quarter of our 2015 fiscal year, our Company voluntarily changed its method of accounting for our oil and gas properties
from the successful efforts method to the full cost method of accounting. Accordingly, financial information for prior periods
has been recast to reflect retrospective application of the full cost method. We believe that the full cost method is preferable
as it better reflects the results of our Company’s operations and the economics of exploring for and developing our non-traditional
long life oil sands assets in the Peace River oil sands area in Alberta. See Note 2 - Summary of Significant Accounting Policies
of the Notes to Consolidated Financial Statements under Item 1 of this quarterly report on Form 10-Q. The following table sets
forth summarized financial information:
|
|
Three Months
Ended
|
|
|
Three Months
Ended
|
|
|
Nine Months
Ended
|
|
|
Nine Months
Ended
|
|
|
|
June
30,
2016
|
|
|
June
30,
2015
|
|
|
June
30,
2016
|
|
|
June
30,
2015
|
|
Revenue
|
|
$
|
–
|
|
|
$
|
219,346
|
|
|
$
|
150,669
|
|
|
$
|
449,147
|
|
Provincial royalty
expenses
|
|
|
–
|
|
|
|
(11,127
|
)
|
|
|
(22,977
|
)
|
|
|
(23,512
|
)
|
Revenue,
net of royalty
|
|
|
–
|
|
|
|
208,219
|
|
|
|
127,692
|
|
|
|
425,635
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
expenses
|
|
|
85,045
|
|
|
|
425,684
|
|
|
|
697,814
|
|
|
|
1,540,206
|
|
Operating
expense covered by Farmout
|
|
|
(85,045
|
)
|
|
|
(217,465
|
)
|
|
|
(570,122
|
|
|
|
(1,114,571
|
)
|
General
and administrative (excluding share-based compensation)
|
|
|
46,841
|
|
|
|
61,297
|
|
|
|
213,026
|
|
|
|
568,447
|
|
Share based
compensation
|
|
|
58,624
|
|
|
|
275,719
|
|
|
|
185,903
|
|
|
|
865,756
|
|
Depreciation,
accretion and depletion
|
|
|
17,397
|
|
|
|
21,721
|
|
|
|
51,924
|
|
|
|
64,541
|
|
Net
loss from operations
|
|
|
(122,862
|
)
|
|
|
(358,737
|
)
|
|
|
(450,853
|
)
|
|
|
(1,498,744
|
)
|
Other
income and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental and other
income
|
|
|
142
|
|
|
|
3,432
|
|
|
|
8,425
|
|
|
|
10,635
|
|
Interest
income
|
|
|
896
|
|
|
|
1,081
|
|
|
|
2,626
|
|
|
|
3,778
|
|
Net
loss and comprehensive loss
|
|
$
|
(121,824
|
)
|
|
$
|
(354,224
|
)
|
|
$
|
(439,802
|
)
|
|
$
|
(1,484,331
|
)
|
First
production from our present joint Steam Assisted Gravity Drainage Demonstration Project (the “SAGD Project”) began
on September 16, 2014. As a result of the low-price environment for bitumen in 2015 and early 2016, a majority of our Company’s
Joint Venture partners voted to temporarily suspend operations of the SAGD Project at the end of February 2016. For the three
month period ending June 30, 2016, oil revenue totaled $Nil and no volumes of oil were produced, due to the shut-in of the SAGD
Project. For the nine month period ending June 30, 2016, we recorded oil revenue in the amount of $150,669 before deduction of
royalties. For the nine month period
Existing
SAGD Project Surface Facility located on Section 7-30-91-12W5.
ending
June 30, 2016, the volume of oil delivered was 19,156 barrels net to our Company, before royalties, with an average oil sales
price of $7.87 per barrel ($10.48 per barrel Cdn). For the three month period ending June 30, 2015, we recorded oil revenue in
the amount of $219,346 before deduction of royalties. For the three month period ending June 30, 2015, the volume of oil delivered
was 6,892 barrels net to our Company, before royalties, with an average oil sales price of $31.83 per barrel ($39.14 per barrel
Cdn). For the nine month period ending June 30, 2015, we recorded oil revenue in the amount of $449,147 before deduction of royalties.
For the nine month period ending June 30, 2015, the volume of oil delivered was 17,043 barrels net to our Company, before royalties,
with an average oil sales price of $26.35 per barrel ($31.60 per barrel Cdn). The realized sales price of our oil is discounted
for diluent, blending, trucking, pipeline access and additional treating costs compared to the West Texas Intermediate (“WTI”)
benchmark price, but paid in Canadian dollars. While oil prices remained low in 2015 and in 2016, the Canadian dollar weakened
and in 2015 and 2016 offset some of the lower WTI price impact. Our net operating margin after operating expenses is zero since
at this time any negative operating margins are reimbursed to us under the farmout agreement we entered into on July 31, 2013
(the “Farmout Agreement”) with an additional joint venture partner (the “Farmee”) to fund our share of
the current SAGD Project. Transportation costs are included in these operating costs. Therefore, the total share of the capital
costs and operating expenses of our Company’s joint SAGD Project, has been funded in accordance with the Farmout Agreement,
at a net cost to our Company of $Nil. As required by the Farmout Agreement, the Farmee has since reimbursed our Company and/or
paid the operator in total approximately $21.5 million ($26.7 million Cdn) for the Farmee’s share and our share of the capital
costs and operating expenses of the SAGD Project as of November 30, 2017. These costs included the drilling and completion of
one SAGD well pair; the purchase and transportation of equipment of which included the once through steam generator (“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; construction of pipelines and expenditures to connect
and tie-in the source and disposal water wells to the steam plant facility along with a fuel source tie-in pipeline; equipment
for processing and treating the bitumen production at the SAGD facility site; replacement of the electrical submersible pump;
front end costs for the expansion; and the operating expenses associated with the steaming and production of the one SAGD well
pair.
For
the three months ended June 30, 2016, our general and administrative expenses decreased by $231,551 compared to the three months
ended June 30, 2015, which was primarily due to a decrease of $217,095 in non-cash share-based compensation charged to expense,
which was mainly due to vested stock options we granted on December 4, 2013, September 19, 2014 and November 17, 2014 to our directors
and contractors; and and a decrease of foreign exchange loss of $31,545. We also received $90,000 during this quarter from one
of our joint venture partners in accordance with a Farmout Agreement to offset some of our monthly operational expenses. After
adjusting for the non-cash items listed above, our general and administrative expenses were $132,759 for the three months ended
June 30, 2015 compared to $179,743 for the three months ended June 30, 2015.
For
the nine months ended June 30, 2016, our general and administrative expenses decreased by $1,035,274 compared to the nine months
ended June 30, 2015, which was primarily due to (i) a decrease of $679,853 in non-cash share based compensation charged to expense,
which was mainly due to vested stock options we granted in 2013 and 2014 to our directors and contractors (ii) a decrease of foreign
exchange loss of $173,300; and (iii) a decrease in engineering fees of $107,913. We also received $270,000 during the last nine
months from one of our joint venture partners in accordance with the Farmout Agreement, to offset some of our monthly operational
expenses. After adjusting for the non-cash items listed above, our general and administrative expenses were $487,918 for the nine
months ended June 30, 2016 compared to $671,760 for the nine months ended June 30, 2015.
For
the three months ended June 30, 2016, our depreciation, depletion, and accretion expense decreased by $4,324 compared to the three
months ended June 30, 2015, which was primarily due to the depreciating value of our assets. Depreciation expense is computed
using the declining balance method over the estimated useful life of the asset. In compliance with our accounting policy, only
half of the depreciation is taken in the year of acquisition. No significant asset purchases were made in the quarter ended June
30, 2016.
For
the nine months ended June 30, 2016, our depreciation and accretion expense decreased by $12,617 compared to the nine months ended
June 30, 2015, which was primarily due to the depreciating value of our assets. Depreciation expense is computed using the declining
balance method over the estimated useful life of the asset. In compliance with our accounting policy, only half of the depreciation
is taken in the year of acquisition. No significant depreciable asset purchases were made in the quarter ended June 30, 2016.
For
the three months ended June 30, 2016, rental and other income decreased by $3,290 compared to the three months ended June 30,
2015.
For
the nine months ended June 30, 2016, rental and other income decreased by $2,210 compared to the nine months ended June 30, 2015.
For
the three months ended June 30, 2016, there were no significant increases or decreases in interest income for three months ended
June 30, 2015.
For
the nine months ended June 30, 2016, interest income decreased by $1,152 compared to the nine months ended June 30, 2015.
As
a result of the above transactions, we recorded a decrease of $232,400 in our net loss and comprehensive loss from operations
for the three months ended June 30, 2016 compared to the three months ended June 30, 2015. As discussed above, this decrease was
primarily due to an increase in non-cash share based compensation expenses and foreign exchange losses.
As
a result of the above transactions, we recorded a decrease of $1,044,529 in our net loss and loss from operations for the nine
months ended June 30, 2016 compared to the nine months ended June 30, 2015. As discussed above, this increase was primarily due
to decreases in non-cash share based compensation expenses and foreign exchange losses.
Operations
In
accordance with the Farmout Agreement the Farmee has agreed to provide up to $40,000,000 in funding for our portion of the costs
for the SAGD Project in return for a net 25% working interest in 12 sections where we had a working interest of 50% before the
execution of the Farmout Agreement. The Farmee is also required to provide funding to cover monthly operating expenses of our
Company provided that such funding shall not exceed $30,000 per month.
The
first SAGD well pair established that SAGD thermal technology is effective in producing oil from the Bluesky reservoir formation
at Sawn Lake. Our SAGD Project also provided valuable productivity information about the Bluesky reservoir. The following graph
sets out the production levels since the project started producing. In October of 2015, the operator began steam rate trials to
optimize production while lowering the steam injection rate, thereby lowering the steam to oil ratio (“SOR”). The
SOR is reflective of the amount of steam needed to produce one barrel of oil. The average SOR for January and February of 2016
was 2.1.
These
production numbers along with the corresponding SORs compare favorably to analogous reservoirs in thermal recovery projects that
we are monitoring and using as a basis of comparison. The capital costs of the existing SAGD Project steam plant facility, with
pipelines and one SAGD well was approximately $26.5 million (Cdn $34.8 million) on a 100% working interest basis, of which our
share is 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). As a result of the low-price environment for bitumen in 2015 and early 2016, a majority of
our Company’s Joint Venture partners voted to suspend operations of the SAGD Project at the end of February 2016.
The
current SAGD Project has:
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confirmed
that the SAGD process works in the Bluesky formation at Sawn Lake,
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established
characteristics of ramp up through stabilization of SAGD performance,
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indicated
the productive capability and SOR of the reservoir and
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provided
critical information required for well and facility design associated with future commercial
development.
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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 and increased significantly over the 18-month period it produced. In January and February of 2016
production from the SAGD Project reached a steady state averaging 615 bopd, on a 100% basis (154 bopd net to us), with an
average SOR of 2.1 from one SAGD well pair. It is expected that a reactivation of the existing SAGD Project facility and current
SAGD well pair will be part of the potential commercial expansion along with the previously AER approved second SAGD well
pair. In early May of 2016, an amended application was submitted to the 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. The amended application
sought approval to expand the current SAGD Project facility site to 3,200 bopd (100% basis). It is anticipated that only five
SAGD well pairs 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 the expansion of the existing SAGD Project was granted on December 14, 2017. While the
joint venture has not yet approved to expand the SAGD Project, 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 development at
Sawn Lake. Expanding the SAGD Project is a significant step towards establishing commercially viability at Sawn Lake on a
larger scale.
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Oil sales terminal at our joint SAGD Project
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We
also recently participated in drilling one core well in August of 2017. The well was drilled to a total depth of 681 meters. The
results of this well will be used for an application for continuation of the mineral rights on one of our oil sands leases.
In
August 2013, we received approval from the AER for our horizontal cyclic steam stimulation project (“HCSS Project”)
application. It is anticipated that we will develop a thermal demonstration project on our properties followed by a commercial
expansion project on one half section of land located on section 10-92-13W5 of our Sawn Lake oil sands properties where we currently
have a 90% working interest. We have since received the final performance results and revised reservoir modeling studies from
our SAGD Project which will be used to fine-tune our HCSS Project facility design before we initiate start-up operations on the
half of a section of land where we plan to drill two horizontal wells to test the use of HCSS technology. We performed an environmental
field study and surveyed the proposed location of our planned HCSS Project site and recently received AER approval for the surface
wellsite and access road for this project.
Currently,
we have a 90% working interest in 51 sections on six oil sands leases and a 100% working interest in five sections on one oil
sands lease in the Peace River oil sands area of Alberta, where we are the operator. In addition, we have a 25% working interest
in another 12 sections on two oil sands leases in the Peace River oil sands area of Alberta. These nine oil sands leases are contiguous
and cover 43,015 gross acres (17,408 gross hectares) with our Company having 34,096 net acres (13,798 net hectares) as shown in
the map below. The development progress of our properties is governed by several factors such as federal and provincial governmental
regulations. Long lead times in getting regulatory approval for thermal recovery projects are commonplace in our industry. Road
bans, winter access only roads and environmental regulations can, and often, do delay development of similar projects. Because
of these and other factors, our oil sands project could take significantly longer to complete than regular conventional drilling
programs for lighter oil.
Liquidity
and Capital Resources
As
of June 30, 2016, our total assets were $23,208,984 compared to $23,684,393 as of September 30, 2015. This decrease of $475,409
was due to a decrease of $540,802 in our current assets, which was primarily due to cash used for general and administrative expenses
and a decrease in our accounts receivable.
Our
total liabilities as of June 30, 2016 were $482,021 compared to $703,531 as of September 30, 2015. This decrease of $221,510 in
our total liabilities was primarily the result of our payment for outstanding accounts payable to the operator of the SAGD Project
for operating expenses, which was subsequently reimbursed to us by the Farmee, in accordance with the terms of the Farmout Agreement.
Our
working capital (current liabilities subtracted from current assets) is as follows:
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Nine Months
Ended
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Year Ended
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June
30,
2016
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September 30,
2015
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Current Assets
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$
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1,584,998
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$
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2,125,800
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Current Liabilities
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29,861
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276,924
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Working Capital
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$
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1,555,137
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$
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1,848,876
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As
of June 30, 2016, we had working capital of $1,555,137 compared to a working capital of $1,848,876 as of September 30, 2015. This
decrease is mainly the result of cash used for general and administrative expenses and decrease of accounts receivable. As of
June 30, 2016, we had no long-term third party debt other than our estimated asset retirement obligations on oil and gas properties.
On
July 31, 2013, we entered into the Farmout Agreement to fund our share of the costs of our joint SAGD Project. As of June 30,
2016, we had a decrease of $247,063 in accounts payable compared to the prior fiscal year.
As
reported on our condensed Consolidated Statement of Cash Flows under “Operating Activities”, for the nine months ended
June 30, 2016, our net cash used in operating activities was $200,613 compared to $277,562 for the nine months ended June 30,
2015. This decrease of $76,949 was primarily the result of less cash used for general and administrative expenses.
As
reported on our condensed Consolidated Statement of Cash Flows under “Investing Activities”, we had an increase of
$62,272 in the investment in our oil and gas properties for the nine months ended June 30, 2016, compared to the nine months ended
June 30, 2015. There were no significant investing activities during these periods.
As
reported on our condensed Consolidated Statement of Cash Flows under “Financing Activities”, for the nine months ended
June 30, 2016, there was no cash inflow or outflow in financing activities. For the nine months ended June 30, 2015, we received
$5,001 from one shareholder in exchange for 47,618 shares of our common stock upon the exercise by that shareholder of warrants
at an exercise price of $0.105 per common share.
Our
cash and cash equivalents as of June 30, 2016 was $1,493,893 compared to $2,023,228 as of June 30, 2015. This decrease of $529,335
in cash was primarily due to general and administrative expenses. As of June 30, 2016, we had no long-term debt other than our
estimated asset retirement obligations on oil and gas properties.
Our
current SAGD Project operating costs are covered by the Farmout Agreement. For our long-term operations, we anticipate that, among
other alternatives, we may raise funds during the next twenty-four months through sales of our equity securities or debt. We also
note that if we issue more shares of our common stock, our stockholders will experience dilution in the percentage of their ownership
of common stock. We may not be able to raise sufficient funding from stock sales for long-term operations and if so, we may be
forced to delay our business plans until adequate funding is obtained.
Full
Cost Method of Accounting
Our
Company’s Board adopted the full cost method of accounting for its oil sands activities effective July 1, 2015. Our Company’s
Management determined that it is preferable to change its accounting policy for its oil sands properties and adopt the full cost
method under U.S. GAAP to better reflect our non-traditional oil sands resource assets in the Peace River oil sands area in Alberta,
Canada.
Off-Balance
Sheet Arrangements
We
do not have any off-balance sheet arrangements.
Cautionary
Note Regarding Forward-Looking Statements
This
quarterly report on Form 10-Q, including all referenced Exhibits, contains “forward-looking statements” within the
meaning of the United States federal securities laws. All statements other than statements of historical facts included or incorporated
by reference in this report, including, without limitation, statements regarding our future financial position, business strategy,
projected costs and plans and objectives of management for future operations, are forward-looking statements. The words “may,”
“believe,” “intend,” “will,” “anticipate,” “expect,” “estimate,”
“project,” “future,” “plan,” “strategy,” “probable,” “possible,”
or “continue,” and other expressions that are predictions of or indicate future events and trends and that do not
relate to historical matters, often identify forward-looking statements. For these statements, Deep Well claims the protection
of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. The forward-looking
statements in this quarterly report include, among others, statements with respect to:
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our
current business strategy;
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our
future financial position and projected costs;
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our
projected sources and uses of cash;
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our
plan for future development and operations, including the building of all-weather roads;
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our
drilling and testing plans;
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our
proposed plans for further thermal in-situ development or demonstration project or projects;
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the
sufficiency of our capital in order to execute our business plan;
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our
reserves and resources estimates;
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the
timing and sources of our future funding.
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the
quantity and value of our reserves;
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the
intent to issue a distribution to our shareholders;
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our
or our operator’s objectives and plans for our current SAGD Project;
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our
plans for development of our Sawn Lake properties;
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production
levels from our current SAGD Project;
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costs
of our current SAGD Project;
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funding
from the Farmee to pay our costs for the current SAGD project in connection with the
Farmout Agreement;
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additional
sources of funding from the Farmout Agreement;
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funding
from the Farmee to cover our monthly operating expenses;
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our
access and availability to third-party infrastructure;
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present
and future production of our properties; and
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expectations
regarding the ability of our Company and its subsidiaries to raise capital and to continually
add to reserves through acquisitions and development.
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These
forward-looking statements are based on the beliefs and expectations of our management and are subject to significant risks and
uncertainties. If underlying assumptions prove inaccurate or unknown risks or uncertainties materialize, actual results may differ
materially from current expectations and projections. Factors that could cause actual results to differ materially from those
set forward in the forward-looking statements include, but are not limited to:
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changes
in general business or economic conditions;
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changes
in governmental legislation or regulation that affect our business;
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our
ability to obtain necessary regulatory approvals and permits for the development of our
properties, including obtaining the required water licences from Alberta Environment
to withdraw water for our thermal operations;
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changes
to the greenhouse gas reduction program and other environmental and climate change regulations
which are adopted by provincial or federal governments of Canada or which are being considered,
which may also include cap and trade regimes, carbon taxes, increased efficiency standards,
each of which could increase compliance costs and impose significant penalties for non-compliance;
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increase
in taxes and changes to existing legislation affecting governmental royalties or other
governmental initiatives;
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future
marketing and transportation of our produced bitumen;
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our
ability to receive approvals from the AER for additional tests to further evaluate the
wells on our lands;
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our
Farmout Agreement and joint operating agreements;
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opposition
to our regulatory requests by various third parties;
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actions
of aboriginals, environmental activists and other industrial disturbances;
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the
costs of environmental reclamation of our lands;
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availability
of labor or materials or increases in their costs;
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the
availability of sufficient capital to finance our business or development plans on terms
satisfactory to us;
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adverse
weather conditions and natural disasters affecting access to our properties and well
sites;
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risks
associated with increased insurance costs or unavailability of adequate coverage;
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volatility
in market prices for oil, bitumen, natural gas, diluent and natural gas liquids. A decline
in oil prices could result in a downward revision of our future reserves and a ceiling
test write-down of the carrying value of our oil sands properties, which could be substantial
and could negatively impact our future net income and stockholders’ equity;
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changes
in labor, equipment and capital costs;
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future
acquisitions or strategic partnerships;
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the
risks and costs inherent in litigation;
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imprecision
in estimates of reserves, resources and recoverable quantities of oil, bitumen and natural
gas;
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product
supply and demand;
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changes
and amendments in the Canadian Oil and Gas Evaluation Handbook and or the Petroleum Resources
Management System to general disclosure of reserves and resources standards and specific
annual reserves and resources disclosure requirements for reporting issuers with oil
and gas activities;
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future
appraisal of potential bitumen, oil and gas properties may involve unprofitable efforts;
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the
ability to meet minimum level of requirements to continue our oil sands leases beyond
their expiry dates;
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changes
in general business or economic conditions;
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risks
associated with the finding, determination, evaluation, assessment and measurement of
bitumen, oil and gas deposits or reserves;
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geological,
technical, drilling and processing problems;
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third
party performance of obligations under contractual arrangements;
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failure
to obtain industry partner and other third party consents and approvals, when required;
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treatment
under governmental regulatory regimes and tax laws;
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royalties
payable in respect of bitumen, oil and gas production;
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unanticipated
operating events which can reduce production or cause production to be shut-in or delayed;
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incorrect
assessments of the value of acquisitions, and exploration and development programs;
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stock
market volatility and market valuation of the common shares of our Company;
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fluctuations
in currency and interest rates; and
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the
additional risks and uncertainties, many of which are beyond our control, referred to
elsewhere in this quarterly report and in our other SEC filings.
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The
preceding bullets outline some of the risks and uncertainties that may affect our forward-looking statements. For a full description
of risks and uncertainties, see the sections entitled “Risk Factors” and “Environmental Laws and Regulations”
of our annual report on Form 10-K for the fiscal year ended September 30, 2015 filed with the SEC on December 29, 2017. Should
one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may
vary materially from those anticipated, believed, estimated or expected. Any forward-looking statement speaks only as of the date
on which it was made and, except as required by law, we disclaim any obligation to publicly update any forward-looking statements,
whether as a result of new information, future events or otherwise. However, any further disclosures made on related subjects
in subsequent reports on Forms 10-K, 10-Q, 8-K and any other SEC filing or amendments thereto should be consulted.